Faroe Petroleum 2017 Final Results Presentation 10 April Slide 1

Transcription

1 Faroe Petroleum 2017 Final Results Presentation 10 April 2018 Slide 1 1

2 Disclaimer These materials do not constitute or form any part of any offer or invitation to sell or issue or purchase or subscribe for any shares in Faroe Petroleum plc (the Company ) nor shall they or any part of them, or the fact of their distribution, form the basis of, or be relied on in connection with, any contract with the Company relating to any securities. Any decision regarding any proposed acquisition of shares in the Company must be made solely on the basis of public information on the Company. These materials are not intended to be distributed or passed on, directly or indirectly, to any other persons. They are available to you solely for your information and may not be reproduced, forwarded to any other person or published, in whole or in part, for any other purpose. No reliance may be placed for any purpose whatsoever on the information contained in these materials or on their completeness. Any reliance thereon could potentially expose you to a significant risk of losing all of the property invested by you or the incurring by you of additional liability. No representation or warranty, express or implied, is given by the Company, its directors or employees, or their professional advisers as to the accuracy, fairness, sufficiency or completeness of the information, opinions or beliefs contained in these materials. Save in the case of fraud, no liability is accepted for any loss, cost or damage suffered or incurred as a result of the reliance on such information, opinions or beliefs. Certain statements and graphs throughout these materials are forward-looking statements and represent the Company s expectations or beliefs concerning, among other things, future operating results and various components thereof, including financial condition, results of operations, plans, objectives and estimates (including resource estimates), the Company s anticipated future cash-flow and expenditure and the Company s future economic performance. These statements, which may contain the words anticipate, believe, intend, estimate, expect and words of similar meaning, reflect the directors beliefs and expectations and involve a number of risks and uncertainties as they relate to events and depend on circumstances that will occur in the future. Forward-looking statements speak only as at the date of these materials and no representation is made that any of these statements or forecasts will come to pass or that any forecast results will be achieved. The Company expressly disclaims any obligation to update or revise any forward-looking statements in these materials, whether as a result of new information or future events. If you are considering buying shares in the Company, you should consult a person authorised by the Financial Conduct Authority who specialises in advising on securities of companies such as Faroe Petroleum plc. Slide 2

3 2017 results summary outlook Material investment phase for Faroe 2017 production towards top end of guidance Total average economic production 1 for 2017 at 14,349 boepd (2016: 17,395 boepd) following Njord/Hyme shut-in Significant reserves growth = highest ever 2P 2P Reserves +20% to 98 mmboe (2016: 81 mmboe) Exploration programme adding 2C & replenishing hopper Successful Brasse appraisal and flow-test increase 2P to 31 mmboe net: good initial results on Fogelberg appraisal well Financially robust and fully funded EBITDAX of 82.2m ( m), year-end net cash of 75.0m ( m) Production outlook 2018 forecast 12-15,000 boepd, maintaining production levels during material investment phase Highest ever investment in development Njord & Bauge, Oda, Fenja, Tambar = 175 million development capex (2018) Exploration remains core to growth story Five firm 2018 E&A wells in Norway - recent success with Iris/Hades discoveries Fully funded to 35,000 boepd January 2018: Sale of 17.5% in Fenja for 39 million, fully funded on remaining developments $250m undrawn RBL, $100 million accordion, NOK 1.0bn EFF, recent $100 million Norwegian bond 1 Economic production which includes actual production acquired during a period - accounting production reflects production acquired only from the acquisition completion date Slide 3 3

4 Sustained delivery through the drillbit Reserves evolution driven by discoveries 2P Reserve Growth (mmboe) % Discoveries (Transfer from 2C) 61 16% Discoveries (Maria swap) 19 25% Existing portfolio & acquisitions (net of production) Reserves Evolution Slide 4

5 Production (boepd) Visible, material organic production growth Organic projects fully funded with additional infill and field investment upside 50,000 Contingent Resources incl. infills Gross Margin $/boe Producing fields, Oda, Njord Future, Bauge, Fenja, Brasse* Unit Opex Fully funded production growth plus identified upside in existing portfolio * Pending development commitment Strong growth trajectory from subsea tie back developments Note: this chart relates to existing, defined projects; it is illustrative and not forward guidance Slide 5

6 Exploration & Appraisal Production & Development Key catalysts 2018 Value-driving events over next ~12 months Q1 Q2 Q3 Q4 H1 Tambar infills Brage infills Brasse DG2 and PDO Fenja PDO approval 1 Oda first oil Iris/Hades Fogelberg Rungne Cassidy Pabow Brasse Extension 2 Yoshi 1 CP to divestment 2 Uncommitted Slide 6

7 Asset summary

8 Material production & reserves from diversified portfolio ULA hub area Growth area for Faroe given Oda development, Tambar (gas lift) and further investment opportunities Pursuing cost reductions and incremental barrels Operators (Ula/Tambar) (Oselvar) (Oda) Net 2P Net prod. mmboe, Jan 2018 boepd, ,440 Greater NJORD hub area Njord Future project to exploit 340+ mmboe of gross reserves Njord A platform on track for restart in 2020 Fenja PDO approved April 2018 TRYM Operators (Njord Area) (Fenja) Net 2P Net prod. mmboe, Jan 2018 boepd, restart Faroe-operated subsea tieback with low unit Opex Materially de-risked following Tyra redevelopment plan Contributing material production until suspension in mid with planned restart in 2022 BRASSE hub area NCS producer with initial STOOIP of ~1,000 mmboe Faroe-operated Brasse discovery nearby with targeted development sanction in 2019 Brage decommissioning liabilities retained in part by Petoro UKCS Tax efficient production from portfolio of mature assets Tax loss position enables value-accretive M&A Blane field (UKCS) included in Ula hub Operator Operators (Brage) (Brasse) Operators (Schooner & Ketch) (East Foinaven) Net 2P Net prod. mmboe, Jan 2018 boepd, ,540 Net 2P Net prod. mmboe, Jan 2018 boepd, ,830 Net 2P Net prod. mmboe, Jan 2018 boepd ,490 Slide 8

9 BRASSE hub area: Flagship operated project Robust, simple subsea development project with excellent address Brasse: (Faroe 50% and operator) PL740 Brasse oil and gas discovery July 2016 similar to Brage Matured to 2P reserves within 18 months from discovery 2P reserves of 30.7 mmboe net Recoverable oil: 25mmbbl; recoverable gas: 34 bcf 2 potential hosts - 13 km to Brage & Oseberg Central platforms Brasse 2017 appraisal campaign successful: Already proves southern extent of discovery, and commerciality of field Very good reservoir properties and in communication with discovery DST flowed at a maximum stable rate of 6,187 bopd Successful side-track confirmed high quality sands Concept Selection planned for 2018; first oil anticipated 2020/21 Preliminary estimates assuming a subsea tie back development Preliminary net capex estimated at 240m for a five wells development scenario 1 1 The actual capex levels will depend on development concept and commercial terms for tie-in Slide 9

10 ULA hub area: Ula, Tambar, Blane, Oda and Oselvar Significant upside from further infill drilling and WAG scheme Ula, Tambar, Oda and Blane Ula (Faroe 20%) Renewed exploitation drive underway led by AkerBP New 4D seismic, infill targets maturing Tambar (Faroe 45%) Two new infill wells drilled, on stream Q Retrofit gas lift system in existing wells Oda (Faroe 15%) Subsea tie-back to Ula First oil expected in 2019 Upside potential Oselvar candidate for redevelopment Blane infill well being considered Exploration Cassidy in H2 Significant reduction in unit opex targeted Ula Hub (20%) Oda (15%) Tambar (45%) Ula platforms Oselvar (55%) Blane* (44.5%) Slide 10

11 NJORD hub area: Njord+ Hyme + Bauge + Fenja Attractive projects with excellent upside Njord: (Faroe 7.5%) + Fenja (Faroe 7.5%*) Significant resource base Gross reserves on Faroe licences estimated to be more than 340 mmboe (gross) via Njord hub Njord Future Project Njord A dry dock phase completed Bauge to be developed as a subsea tie-back to Njord Planned to come back on stream in 2020 Fenja subsea tie back development to Njord Three horizontal producers supported by water and gas injectors FDP approved April 2018 Partial cash sale (17.5%) to Suncor ($54.5m) Bauge (7.5%) Njord Hub (7.5%) Fenja (7.5%)* Hyme (7.5%) Njord (Faroe 7.5%) Fenja (Faroe 7.5%)* Njord A facility at the Aker Stord yard * as adjusted for the sale of 17.5% of Fenja which remains subject to approval by Norwegian Authorities Slide 11

12 Exploration benefiting from significantly lower costs Tax-efficient exploration offers material value uplift Balanced exploration strategy with strict internal criteria Benefiting from lower exploration costs Brasse among cheapest wells drilled on the NCS in recent times Exploration spend deductible for tax purposes (and eligible for a tax rebate from the Norwegian State at the rate of 78%) Successful track record that has added delivered significant development projects from exploration, notably Maria (2010), Fogelberg (2010), Oda (2011), Fenja (2014), and Brasse (2016) Iris Hades discoveries announced April 2018 Fogelberg appraisal good initial results and well test under way Four high-quality E&A wells committed for H and H Rungne (Faroe 40% and operator, 70 mmboe gross*) Pabow (Faroe 20%, 70 mmboe gross*) Cassidy (Faroe 15%, 50 mmboe gross*) Yoshi (Faroe 30%, 30 mmboe gross*) Many further targets being matured to drilling decisions to deliver sustainable long term drilling programme * Gross unrisked resource potential Slide 12

13 Iris & Hades Discoveries Start of 2018 exploration programme Significant gas/condensate discoveries History Original award in APA 2009 as extension to Cooper licence Prospects identified by Faroe exploration team Reapplied as an extension to Aerosmith in APA 2015 Faroe 20%, OMV (operator) 30%, Statoil 40% 1 and Spirit 10% 1 Lange Hades gas/condensate discovery Lange sandstones of moderate to good quality 35 metres gross HC column 15 metres net reservoir Recoverable estimates: mmboe Garn Iris gas/condensate discovery Thick (218m) moderate-excellent Garn reservoir 93 metres HC column 85 metres net reservoir Recoverable estimates : mmboe Future development potential Proximity to production infrastructure Host Appraisal programme now under consideration 1 subject to completion) Slide 13

14 Financial

15 2017 final results & 2018 outlook Financial highlights and outlook 2017 Results Revenue 152.9m (2016: 94.8m), EBITDAX 82.2m (2016: 25.8m) Production 2017 economic production¹ 14,349 boepd, forecast 2018 production 12-15,000 boepd Liquidity Net cash (31 Dec-17) 75.0m (31 Dec-16: 96.8m) $100m NOK Bond + $250m RBL facility + $100m accordion + NOK 1.0bn EFF = significant liquidity Capex 2017 E&A spend 47.7m ( 11.5m post-tax), D&P spend 96.0m 2018 E&A forecast 80m ( 20m post-tax), D&P forecast 175m Hedging 85% of post-tax gas production hedged to end-2018 averaging 42p/therm, 60% oil production hedged averaging $57/bbl (post-tax) ¹ Economic production in 2016 includes production from the recent acquisitions from the effective date. Accounting production excludes production between the effective date and date of completion. Accounting production in 2017 was 8,026 boepd (2014: 10,252 boepd) Slide 15

16 2017 Results Summary Increased EBITDAX and fully financed Financial Summary ( m) Explanation Revenue (IFRS) Underlift 30.7 (7.0) Due to timing of liftings Adjusted revenue See above Operating costs (excl. underlift) (118.3) (66.7) Other Income Realised hedging (losses) / gains (1.9) 4.7 EBITDAX Impairment (12.9) (2.9) DDA (44.8) (22.9) Administrative expenses (7.7) (10.2) An increase of 76% in accounting production (due to acquisition of DONG assets) and recovery in commodity prices led to higher revenue in the period Increase in operating costs is largely related to increased accounting production. Opex/bbl relatively stable at $26.5/boe (for producing fields and excl. accrued future Ula upgrade costs) Compensation recognised by Faroe as Oselvar partner from Oda. Future compensation accrued of 7.7m and net compensation receipt in H1 7.8m Realised hedging gains of 0.4m were offset by premiums of 2.3m in Higher commodity prices in 2017 compared to 2016 led to lower gains on hedges Increase in EBITDAX is mainly attributable to increased volumes and recovery of commodity prices and also Oda compensation payments Impairment charge recognised on Schooner and Ketch due to uncertainties on downstream infrastructure, which has led to an acceleration of COP. Higher absolute DDA mainly due to higher production volumes. DDA/boe has increased to $11.3/boe due to higher Schooner & Ketch decommissioning costs (2016: $10.5/bbl) Reduction in administrative expenses due to higher time-writing recoveries as a result of greater activity levels on operated assets Exploration and evaluation expenses (25.9) (33.5) Predominantly write-off in 2017 of Boné well of 20.4m Finance costs (17.0) (11.2) The increase of 5.8m is largely non-cash related and is driven by the significant increase in the decommissioning provision following completion of DONG asset acquisition in 2016 Finance income Movement mainly relates to lower FX gains in 2017 Gain on disposal of asset Pre-tax gain on Jotun disposal Unrealised hedging gains / (losses) 0.4 (13.1) Predominantly put instruments Loss before tax (13.7) (61.6) Mainly driven by improved EBITDAX offset by movements on DDA Tax credit Decrease due to a deferred tax charge which is driven by significant levels of capex in Norway Loss for the period (11.4) (32.9) Losses narrowed Slide 16

17 Strong financial foundations unlocking value Diversified capital structure and financial flexibility Hedging Healthy cash balance Strong cash flow Financial flexibility & discipline Tax efficient Fully funded programme Significant debt headroom Exploration success driving growth programme Manage exposure to individual projects Operatorship important factor Strong balance sheet crucial Prudently increase leverage in development phase Maintain financial ratios below mandate levels Manage uncertainty actively Active hedging programme Maintain cash buffer Financial flexibility Ensure diversity in funding sources Remain nimble to access opportunities Slide 17

18 2018 outlook Material investment phase for Faroe Production outlook Forecast 12-15,000 boepd (2018), maintaining production levels during material investment phase Highest ever investment in development Njord & Bauge, Oda, Fenja, Tambar = 175 million development capex (2018) Exploration remains core to growth story Five firm 2018 E&A wells in Norway Fully funded to 35,000 boepd January 2018: Sale of 17.5% in Fenja for 39 million, fully funded on remaining developments $250m undrawn RBL, $100 million accordion, NOK 1.0bn EFF, recent $100 million Norwegian bond Slide 18

19 Appendices

20 Faroe Petroleum full cycle E&P independent Unique strategic position High quality, diversified pan-north Sea asset base Material production growth from existing portfolio Active portfolio management driving shareholder returns Exploration remains core value creator Strong balance sheet provides financial flexibility ~ $500m liquidity 12 principal fields across 4 hubs/areas 2P reserves: 98 mmboe, 79% oil (YE17) 1 Production: 14,349 boepd (FY17) 2 Funded growth potential to >35,000 boepd Further upside to deliver >50,000 boepd from existing portfolio DONG assets acquired at bottom of cycle Fenja part-divestment agreed UK and Norway acquisition focus Significant 2P reserves from exploration Five high quality E&A wells planned for 2018 Actively adding to acreage position YE17 net cash of 75 million 3 Successful $100 million bond (Nov-17) $250 million RBL remains undrawn 1 Adjusted for the disposal of a 17.5% participating interest in Fenja which remains subject to regulatory approvals net economic production 3 Gross cash 149 million YE17. Slide 20

21 Faroe s executive team Graham Stewart Chief Executive Officer Instrumental in founding Faroe Petroleum in 1998 Over 30 years experience in oil and gas technical and commercial affairs Previously finance director and commercial director at Dana Petroleum 1997 to 2002 Experience with Schlumberger, DNV Technica, Petroleum Science & Technology Institute Offshore Engineering degree (Heriot- Watt University) and MBA (University of Edinburgh ) Helge Hammer Chief Operating Officer Joined Faroe Petroleum in 2006 Over 30 years technical & business experience, incl. Shell (Norway, Oman, Australia and Holland) Managing Director of wholly owned Norwegian subsidiary, Faroe Petroleum Norge AS Previously Asset Manager and Deputy Managing Director at Paladin Resources Economics degree (Institut Français du Pétrole, Paris) Petroleum Engineering degree (NTH University of Trondheim) Jonathan Cooper Chief Financial Officer Joined Faroe Petroleum as Chief Financial Officer in 2013 Former Finance Director of Gulf Keystone Petroleum and Sterling Energy and CFO of Lamprell plc Former Director of the Oil and Gas Corporate Finance Team of Dresdner Kleinwort Wasserstein Broad range of experience from mergers and acquisitions, public offerings and financing Chartered accountant by training having qualified with KPMG PhD Mechanical Engineering (University of Leeds) Slide 21

22 Rebased vs. FPM (GBp) Strong support from institutional shareholders Share price performance and shareholder overview 12 Month share price performance Major shareholder split* DNO: 27.7% Invesco: 4.1% JP Morgan: 5.2% Aviva: 6.6% Blackrock: 9.0% Shareholder geographic split* Other institutional 35.9% Retail: 11.6% Rest of the World: 2.4% North America: 3.7% United Kingdom 58.2% 55 Faroe FTSE AIM O&G Brent Nordic / Europe: 35.7% * Source: RD:IR as at 31 March 2018 Slide 22

23 Group Income Statement Revenue 152,924 94,779 Cost of sales (132,508) (96,666) Asset Impairment (12,992) (2,923) Gross profit / (loss) 7,424 (4,810) Other income / (expense) 17,353 (8,412) Gain on disposal of asset 7,229 - Exploration and evaluation expenses (25,851) (33,468) Administrative expenses (7,678) (10,189) Operating loss (1,523) (56,879) Finance revenue 4,790 6,423 Finance costs (17,006) (11,139) Loss on ordinary activities before tax (13,739) (61,595) Tax credit 2,313 28,686 Loss for the year (11,426) (32,909) Slide 23 23

24 Group Balance Sheet Non-current assets Goodwill 9,386 7,744 Intangible assets 68, ,376 Property, plant and equipment: development & production 201, ,328 Other assets Deferred tax assets 114, ,055 Current assets 394, ,114 Inventories 10,644 10,456 Trade and other receivables 102,088 63,063 Current tax receivable 35,610 41,764 Cash and cash equivalents 149,084 96,769 Assets held for sale 50, ,052 Total assets 743, ,166 Current liabilities Trade and other payables (113,989) (53,900) Current taxation (65) (31) Provisions (10,022) - Financial liabilities Norway Exploration Financing facility (32,948) (35,845) Financial liabilities Other financial liabilities (767) (1,383) Non-current liabilities (157,771) (91,159) Provisions (254,697) (269,469) Bond (72,742 - Assets held for sale (31,854) - Total liabilities (517,064) (360,628) Net assets 226, ,638 Slide 24 24

25 Group Cash Flow Statement Condensed Group Cash Flow Statement for the year ended 31 December Loss before tax (13,739) (61,595) Depreciation, depletion and amortisation 45,179 23,369 Exploration asset write off 21,524 29,908 Unrealised hedging losses / (gains) (369) 13,095 Gain on disposal of asset (7,229) - Disposal of decommissioning provision (1,092) - Asset impairment 12,992 2,923 Fair Value of share based payments 4,948 4,408 Movement in trade and other receivables (42,263) (24,478) Movement in inventories (188) (4,534) Movement in trade and other payables 61,728 22,865 Currency translation adjustments (4,060) (5,814) Cash outflows on share based payments (886) - Investment revenue (730) (609) Interest and financing fees paid 17,006 11,139 Tax rebate 41,031 44,729 Net cash generated in operating activities 133,852 55,406 Net cash used in investing activities (143,509) (78,838) Financing activities Net proceeds from issue of equity instruments - 62,756 Net proceeds from debt issue 73,995 - Net (repayments) / proceeds from borrowings (1,404) (19,931) Interest and financing fees paid (4,022) (4,225) Net cash inflow /(outflow) provided from financing activities 68,569 38,600 Net increase / (decrease) in cash and cash equivalents 58,912 15,168 Cash and cash equivalents at the beginning of year 96,769 91,515 Effect of foreign exchange rate changes (6,597) (9,914) Cash and cash equivalents at end of the year 149,084 96,769 Slide 25 25