DEA Group 2017 Year End Results Presentation Maria Moræus Hanssen CEO of DEA Deutsche Erdoel AG, Managing Director L1E Finance GP GmbH Dmitry Avdeev

Transcription

1 DEA Group 2017 Year End Results Presentation Maria Moræus Hanssen CEO of DEA Deutsche Erdoel AG, Managing Director L1E Finance GP GmbH Dmitry Avdeev CFO of DEA Deutsche Erdoel AG, Managing Director L1E Finance GP GmbH Dirk Warzecha COO of DEA Deutsche Erdoel AG March 8 th, 2018

2 Disclaimer Forward-Looking Statements This communication may include projections and other forward-looking: statements within the meaning of applicable securities laws, which are based on current expectations and projections about future events and financial performance. Statements herein, other than statements of historical fact, regarding future events or prospects, are forward-looking statements. The words may, will, should, expect, anticipate, believe, estimate, plan, predict, intend or variations of these words, as well as other statements regarding matters that are not historical fact or regarding future events or prospects, constitute forward-looking statements. L1E Finance GmbH & Co KG (the Company ) has based these forward-looking statements on its current views with respect to future events and financial performance in addition to certain assumptions about the future, some of which are beyond the Company s control. These forward-looking statements involve a number of risks, uncertainties, and assumptions about the Company and its subsidiaries and its investments, including, among other things, the development of its business, trends in its operating industry, and future capital expenditures and acquisitions. In light of these risks, uncertainties and assumptions, actual results may not occur or may differ materially from those predicted in the forward-looking statements and from the past performance of the Company. As a result, you should not rely on these forward-looking statements. Neither the Company nor any other person make any warranties or representations about accuracy, sequence, timeliness or completeness of the content of the presentation or the achievement or reasonableness of future projections, management targets, estimates, prospects or returns, if any. Non-GAAP and Non-IFRS Financial Measures This communication may contain certain non-gaap and non-ifrs measures and ratios, including for example EBITDAX, net debt, net working capital, coverage ratios and EBITDAX per boe that are not required by, or presented in accordance with, any GAAP or IFRS. The non-gaap and non-ifrs 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 any GAAP. Our management uses these measures to measure operating performance and liquidity, in presentations to our Management Board and as a basis for strategic planning and forecasting, as well as monitoring certain aspects of our operating cash flow and liquidity. We present non-gaap and non-ifrs measures and ratios because we believe that they and similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity. Non-GAAP and non-ifrs measures and ratios such as EBITDAX, coverage ratios and EBITDAX per boe are not measurements of our performance or liquidity under IFRS and should not be considered as alternatives to operating profit, profit for the year, capital expenditure or any other performance measures derived in accordance with IFRS or any GAAP or as alternatives to cash flow from operating, investing or financing activities. We present in this communication a reconciliation of each of the non-gaap and non-ifrs measures to the most directly comparable measure calculated and presented in accordance with IFRS and discuss its limitations See note above. Some of the limitations of EBITDAX are: they do not reflect our cash expenditures or future requirements for contractual commitments; they do not reflect changes in, or cash requirements for, our working capital needs; they do not reflect the significant interest expense, or the cash requirements necessary, to service interest or principal payments on our debt; although depreciation and amortization are non cash charges, the assets being depreciated and amortized will often need to be replaced in the future and EBITDAX does not reflect any cash requirements that would be required to make such replacements; they do not reflect the impact of certain cash charges resulting from matters we consider not to be indicative of our ongoing operations; and other companies in our industry may calculate these measures differently from the way we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDAX should not be considered as measures of discretionary cash available to us to invest in the growth of our business or as measures of cash that will be available to us to meet our obligations. You should compensate for these limitations by relying primarily on our IFRS results and using these non-gaap and non-ifrs measures only to supplement your evaluation of our performance. Page 2

3 Contents 1. Highlights 2. Financial Overview 3. Operational Update 4. Outlook 5. Appendix Page 3

4 2017 in Numbers Production 2P Reserves QHSE Operational 125 kboe / d -9% vs Original guidance: kboe/d 698 mmboe (1) +5% vs LTIF 0.46 vs in 2016 EBITDAX Investments Free Cash Flow Financial 924 million +22% vs Original guidance: 1-10 % higher than million +30% vs Original guidance: % higher than million +3% vs Leverage Net Debt Production Costs Other 1.72x vs. 2.33x in ,592 million vs. 1,765 million in $/boe vs. 7.4 $/boe in 2016 (1) excl. Ogarrio as external audit is yet to be completed Page 4

5 2017 Highlights Operations West Nile Delta and Reggane first gas achieved Three developments sanctioned in Norway: Njord, Snorre SEP and Ærfugl (formerly Snadd) Gulf of Suez license extended, overdues in Egypt significantly reduced Successful appraisal well drilled within the Alta license Financing Moody s assigned Ba3 corporate rating to DEA Group S&P upgraded unsecured notes rating to BB- from B+ RBL availability reconfirmed at $2.3bn Production start of West Nile Delta project Reggane production start Business Development / Other Increased share in Dvalin to 55%, acquisition of Njord package completed Country entry in Mexico with award of first exploration license and 50% license share and operatorship of producing Ogarrio field Successful completion of internal reorganisation program On December 7 th 2017, LetterOne and BASF signed Letter of Intent to combine their oil and gas businesses under Wintershall DEA Ogarrio Field Njord Area Page 5

6 Contents 1. Highlights 2. Financial Overview 3. Operational Update 4. Outlook 5. Appendix Page 6

7 Production and Pricing Commentary Production Profile (kboe/d) Q production 1 % higher QoQ mainly due to resumed production after annual maintenance in Norway and Germany, but offset due to temporary shut in of a Snadd well Q realized oil price 18 % higher QoQ (+15 % YoY), mainly in line with Brent price development Q realized gas price was $5.0/mcf, 11 % higher QoQ due to seasonally higher gas prices. YoY prices were lower 6 % mainly due to higher gas output in Egypt where fiscal terms lead to lower fixed prices compared to Europe % liquids: % gas: 44% 45% 56% 55% % 43% 44% 38% 38% 39% 39% 55% 57% 56% 62% 62% 61% 61% Q Q Q Q Q Q Q Q Jan-2018 Norway Germany/Denmark North Africa Realized Oil Price ($/bbl) Realized Gas Price ($/mcf) Q Q Q Q Q Q Q Q Q Q Q Q Quarterly Realized Oil Price Q Quarterly Realized Oil Price Q Q Quarterly Realized Gas Price Q Quarterly Realized Gas Price Page 7

8 Revenues and Profitability Commentary 2017FY revenues were 2 % lower compared to 2016FY, and Q % lower YoY, as lower production volumes were only partially offset by higher commodity prices Gross Revenues ( million) -2% 1,460 1, FY EBITDAX was 22 % higher compared to 2016FY due to lower cost of sales, reduction of G&A and reversal of impairments of receivables, partially compensated by higher tariffs and royalties 2017FY unit production costs increased 4% compared to 2016FY, mainly due to lower output as well as weaker USD EBITDAX ( million) Q Q Germany/Denmark Norway North Africa Average Production Costs ($/boe) % margin 52% 64% 60% 74% (28) (81) (69) (10) (6) Q Q Germany/Denmark Norway North Africa Other (1) Incl. rest of the world, central functions and investment property (1) Page 8

9 Capital Expenditure Commentary 2017FY capital expenditures increased 30 % compared to the year before Capex Breakdown ( million) Norway: 2017FY expenditures increased by 222 million mainly due to increased development activity in Dvalin and Njord fields. Both developments are progressing in line with the plan Germany/Denmark: expenditures remained stable due to continuous drilling in Mittelplate North Africa: 2017FY investments were 8 % lower compared to 2016FY, as both West Nile Delta and Reggane fields were nearing production Q Q Germany/Denmark Norway North Africa Other(1) (1) Incl. rest of the world, central functions and investment property Page 9

10 Cash Position Development Cashflow Bridge ( million) 881 (821) Mainly Njord acquisition payment 60 (65) Cash 01/01/17 Cash Flow from Operations Cash Flow from Investment Activities Free Cash Flow Cash Flow from M&A Cash Flow from Financing Cash 31/12/17 Page 10

11 Liquidity and Net Debt Source of Liquidity ( million) Net Debt ( million) 102 (2) ,918 (1) 2,318 2,419 1,312 (3) 1,734 1,592 1,592 (1) 400 (1) 400 (3) Senior Unsecured Notes RBL Overdraft Facilities Cash Available Liquidity Senior Unsecured Notes RBL (drawn) Cash Net Debt 31/12/2017 (1) Nominal value (2) Includes US$50m and 60m unsecured revolving credit facilities (3) Balance sheet amount, net of amortized fees and including accrued interest FX rate used USD/EUR Page 11

12 Hedging Overview Oil (as of February 28 th, 2018) Gas (as of February 28 th, 2018) Volume (mmbbl) Volume (bcf) Hedged Volumes Price ($/boe) Price ($/mcf) (1) % of Target Hedging Volume 100% 100% 65% % of Target Hedging Volume >100% >100% 85% 14% 12% 2% (1) Calculated at the forward rates applicable on February 28 th, 2018 Page 12

13 Contents 1. Highlights 2. Financial Overview 3. Operational Update 4. Outlook 5. Appendix Page 13

14 Reserves Overview Significant reserves base supporting production growth mmboe Reserves Addition P P 698 2P Reserves by Country Norw ay 49% Germany / Denmark 18% North Africa 33% 698 mmboe Organic Reserves Replacement Ratio 153% 169% Significant Undeveloped Reserves Upside Historical Evolution of 2P Reserves mmboe % Germany / Denmark 39% % % 323 Norway North Africa Total 2P 2PD 2PD / 2P Ratio >99% of reserves are audited by RPS, excl. Ogarrio as external audit is not yet completed 100% 80% 60% 40% 20% 0% Page 14 mmboe (46) 56% - 375mmboe designated to the RBL 2016 Production Organic Growth GoS Extension % - 404mmboe designated to the RBL

15 Current Development Project Update Well established position in Norway Existing development projects well on stream West Nile Delta Reggane Nord Dvalin Current Status and Outlook The first two fields, Taurus and Libra, started production in March 2017, reaching over 700 mmscf/d Maersk Discoverer continued with Giza Fayoum completion in December 2017; second drilling rig commenced drilling in October The remaining fields, Giza, Fayoum and Raven are expected to come on-stream by Project Background Subsea development of five fields, Taurus, Libra, Giza, Fayoum and Raven DEA s Working Interest: % 2P reserves of 91 mmboe (1) (1) As per 01/18 audit Current Status and Outlook First Gas achieved on December 13th 2017 In total, ten wells planned to come on stream during the ramp-up phase The first wells were put in production, further wells to be tied-in in 2018 Targeted production level expected to be reached in 2018 A new drilling campaign will start in mid 2018 and will extend until mid 2020 Project Background Comprises of six gas fields Reggane, Azrafil Sud-Est, Kahlouche, Kahlouche Sud, Tiouliline and Sali DEA s Working Interest: 19.5 % Current Status and Outlook Drilling rig contract awarded to Transocean in November 2017 Drilling rig services contracts to be awarded shortly Drilling of four production wells to start in mid-2019 Project Background Dvalin is being developed as subsea connection to Heidrun platform First own operated field development in Norway; PDO approved in March 2017 Production start planned in 2020 DEA s Working Interest: 55 % 2P reserves of 58 mmboe (1) Page 15

16 Current Development Project Update Well established position in Norway Three PDO submissions to support organic growth Njord Area Ærfugl (formerly Snadd) Skarv Unit Snorre SEP Current Status and Outlook Njord, Hyme and Bauge sanctioned in early 2017; PDO approved in June Tie-in agreement signed with Fenja in December 2017, enhancing economics of the fields Next upcoming major contract awards are Njord B yard and Bauge drilling rig contracts Planned production start in 2020 Project Background Njord redevelopment to boost recovery and extend producing of all three fields DEA s Working Interest: Njord: 50 %, Hyme/Bauge: 27.5 % 2P reserves of 88 mmboe (1) Current Status and Outlook PDO submitted in December 2017 Snadd test well producing via Skarv since 2013, increasing confidence to inplace volumes Production start planned in 2020 Project Background First development concept includes three production wells to be drilled in southern part of the field and tied back to Skarv FPSO DEA s Working Interest: % 2P reserves of 37 mmboe (1) Current Status and Outlook PDO submitted in December 2017 Production start planned in 2021 Project Background Conventional subsea tie-back project to increase and accelerate production Positively impact on potential future Snorre redetermination DEA s Working Interest: 8.57 % 2P reserves of 17 mmboe (1) (1) As per 01/18 audit Page 16

17 Contents 1. Highlights 2. Financial Overview 3. Operational Update 4. Outlook 5. Appendix Page 17

18 2018 Guidance 2017 Actuals 2018 Guidance Production 125 kboe/d kboe/d EBITDAX 924 million % lower than 2017 (1) Capital Expenditure 838 million % higher than 2017 (1) Assuming $52-58/bbl for Brent and UK NBP of $ /mcf for 2018 Page 18

19 Contents 1. Highlights 2. Financial Overview 3. Operational Update 4. Outlook 5. Appendix Page 19

20 DEA Asset Base Overview Field Operator Working Interest Oil/Gas Split 1PD (mmboe) 1P (mmboe) 2PD (mmboe) 2P (mmboe) 2017 Production (kboepd) Production Start Germany Mittelplate DEA AG 50% Oil Volkersen DEA AG 100% Gas Low Materiality Norway Gjøa ENGIE 8% Oil / Gas Snorre Statoil 8.57% Oil Snøhvit Statoil 2.81% Mostly gas Knarr BG 10% Mostly oil Skarv BP 28.1% Oil / Gas Njord Statoil 50% Oil / Gas Hyme Statoil 27.5% Oil / Gas Bauge Statoil 27.5% Oil Dvalin DEA 55% Gas Low Materiality Egypt Gulf of Suez SUCO 100% Oil / Gas Disouq DISOUCO 100% Gas West Nile Delta BP 17.25% Gas Denmark Other Total (1) Reserves as of January 1 st, 2018 Page 20

21 Definitions DEA Group DEA Group consists of L1E Finance GmbH & Co. KG and its subsidiaries Free cash flow Free cash flow comprises of cash flows from operating activities and from investing activities, but excludes cash flows from acquisitions EBITDAX EBITDAX defined as income before tax, financing costs, exploration expense, DD&A and impairments, acquisitions, disposals, extraordinary items, minority interest, FX gains and losses, pensions, loss or gain in relation to disposal of fixed assets Production Working Interest Production Production costs Production costs include G&A allocation but exclude export and processing tariffs, finance items and R&D LTIF Lost Time Incident Frequency (number of Lost Time Incident per 1 million working hours) Capital Expenditure Capex excludes financial asset capex and excludes capex from discontinued operations and acquisitions Realized oil/gas price Includes hedges and physical forward sales Note: Certain numerical figures and percentages set out in this presentation have been subject to rounding adjustments Page 21