DEA Group 2016 Year End Results Presentation Thomas Rappuhn CEO of DEA Deutsche Erdoel AG, Managing Director L1E Finance GP GmbH Dmitry Avdeev CFO of

Transcription

1 DEA Group 2016 Year End Results Presentation Thomas Rappuhn 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 March 23rd, 2017

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. DEA Deutsche Erdoel AG (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 DEA Financial Overview L1E Finance Reconciliation 4. Operational Update 5. Outlook 6. Appendix Page 3

4 2016 DEA AG Group Highlights Successful integration of E.On Norway, relocation of the regional headquarters to Stavanger Sanctioning of DEA-operated Dvalin gas development in the Norwegian sea and increase of DEA share in the project to 55% 2P Reserves 667 mmboe +16% Production 138 kboe/d +20% Acquisition of additional share in the Njord Area; subsequent sanctioning of Njord redevelopment Successful exploration campaign in the Barents sea: further de-risked Alta; discovered Filicudi Inaugural 400 million Senior Unsecured Notes issuance contributed to already strong liquidity profile; obtaining corporate rating of BB- by S&P and BB by Fitch LTIF 0.32 per million working hours, no incidents with loss of primary containment EBITDAX 776 million -6% Leverage 2.3x Capex 646 million +6% Free Cash Flow 78 million Page 4

5 Contents 1. Highlights DEA Financial Overview L1E Finance Reconciliation 4. Operational Update 5. Outlook 6. Appendix Page 5

6 DEA AG Group Highlights 2016 (1) FY 2016 FY 2015 Production (2) (kboe/d) P Reserves (mmboe) Realized oil price (3) ($/boe) Realized gas price (3) ($/mcf) Revenue ( m) 1,476 1,425 Production costs (4) ($/boe) Exploration costs ( m) EBITDAX (5) ( m) (6) Net Income ( m) Capex (7) ( m) Free Cash Flow (8) ( m) Net Debt ( m) 1,795 1,706 Leverage (9) (1) For purposes of the Senior Notes due 2022 issued by DEA Finance SA, the DEA Group consists of L1E Finance GmbH & Co KG and its subsidiaries, including DEA. Pursuant to the indenture governing the Notes, the DEA Group is required to report the consolidated financial accounts of L1E Finance GmbH & Co KG. For comparability purposes with prior period, the presentation focuses on the consolidated financial results of DEA Deutsche Erdoel AG, unless otherwise stated (2) Working interest production (3) Includes hedges and physical forward sales (4) Production costs include G&A allocation but exclude export and processing tariffs, finance items, CO ² tax and R&D (5) 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; (6) 2015FY figure excludes effects of E.On Norge acquisition and DEA UK sale (7) Capex excludes financial asset capex and excludes capex from discontinued operations and acquisitions (8) Free cash flow comprises of cash flows from operating activities and from investing activities, but excludes cash flows from acquisitions (9) Leverage calculated based on EBITDAX pro forma of E.On Norge acquisition and DEA UK divestment Note: Certain numerical figures and percentages set out in this presentation have been subject to rounding adjustments Page 6

7 Production and Pricing Commentary Production Profile (kboe/d) 2016 production was 138kboe/d, 20% higher compared to the same period last year due to the acquisition of E.On Norge assets Q production of 131kboe/d is 7% higher compared to the same period last year due to acquisition of E.On Norge assets. Production in Q was lower than average production in 2016 due to production stop in Njord and natural decline, particularly in Skarv % oil: % gas: 43% 57% % 42% 56% 58% % 57% Q4 realized oil price was $46/bbl, about 13% lower than in Q Average price for the year was 30% lower compared to Q4 realized gas price was $5.3/mcf, 8% higher than in Q Average price for the year was 6% lower compared to 2015 Realized Oil Price ($/bbl) Q Q Germany/Denmark Egypt Norway Realized Gas Price ($/mcf) Q1 Q2 Q3 Q Quarterly Realized Oil Price 2015 Quarterly Realized Oil Price 2016 Realized Oil Price 2015 Realized Oil Price Q1 Q2 Q3 Q Quarterly Realized Gas Price 2015 Quarterly Realized Gas Price 2016 Realized Gas Price 2015 Realized Gas Price Page 7

8 Revenues and Profitability Commentary 2016 revenues of 1,476m up 4% compared to the same period last year due to the higher sales volumes partly offset by lower commodity prices Q revenues increased by 7% compared to revenues for the same period last year due to higher volumes and overall neutral commodity prices 2016 average production costs were 19% lower at $7.4/boe due to higher proportion of low-cost production in Norway and ongoing cost reduction measures. Q4 was positively impacted by significantly lower costs in Egypt due to EGP devaluation and further cost decreases in Norway 2016 EBITDAX of 776m was 6% lower compared to 2015 as higher revenues were offset by higher absolute production costs (+22%), higher tariff and transportation costs due to increased Norway output volumes (+ 50 million), and higher Egypt receivables write down ( 69 vs 39 million in 2015) Q4 EBITDAX increased by 13% due to higher revenues and lower overall production costs, partially offset by higher Egypt receivables write down EBITDAX ( m) Gross Revenues ( m) 1,425 1, Q Q Germany/Denmark Egypt/Algeria Norway Average Production Costs ($/boe) 58% 53% % margin 61% 63% Q Q Germany/Denmark Egypt/Algeria Norway Other (1) (1) Q Q Group Production Costs (1) Incl. rest of the world, central functions and investment property Note: Production costs include G&A allocation but exclude export and processing tariffs, finance items, CO² tax and R&D Page 8

9 Capital Expenditure Capex Breakdown by Country ( m) % (1) Q Q Germany/Denmark Egypt/Algeria Norway Other (2) 48 (1) 2015 net of capex reimbursement for West Nile Delta farmdown (2) Incl. rest of the world, central functions and investment property Page 9

10 Cash Position Development Cashflow Bridge ( m) Post closing effects of DEA UK divestment, Raven unitization, and other -10 Voluntary reduction of drawings under the RBL and partial repayment of shareholder loan Cash 01/01/16 Cash Flow from Operations Cash Flow from Investment Activities Cash Flow from Divestments Cash Flow from Acquisitions Cash Flow from Financing Cash 31/12/16 Page 10

11 Liquidity and Net Debt Source of Liquidity ( m) Net Debt ( m) ,180 2,580 2,627 1,897 1,497 1,796 1, (1) (1) 400 Senior Unsecured Notes RBL Overdraft Facility Cash Available Liquidity Senior Unsecured Notes RBL (drawn) Cash Net Debt 31/12/2016 (1) Nominal value, 399 million based on IFRS Page 11

12 Hedging Overview Oil (as of February 28 th, 2017) Gas (as of February 28 th, 2017) Volume (mmbbl) Volume (bcf) Hedged Volumes Price ($/boe) Price ($/mcf) % of Target Hedging Volume 100% 90% 45% % of Target Hedging Volume >100% 100% 100% 10% Page 12

13 Contents 1. Highlights Financial Overview L1E Finance Reconciliation 4. Operational Update 5. Outlook 6. Appendix Page 13

14 L1E Finance Group Highlights 2016 FY 2016 FY 2015 Production (1) (kboe/d) P Reserves (mmboe) Realized oil price (2) ($/boe) Realized gas price (2) ($/mcf) Revenue ( m) 1,460 1,094 Production costs (3) ($/boe) EBITDAX (4) ( m) Net Income ( m) ,107 Capex (5) ( m) Free Cash Flow (6) ( m) Net Debt ( m) 1,765 1,672 (1) Working interest production (2) Includes hedges and forward sales (3) Production costs include G&A allocation but exclude export and processing tariffs, finance items, CO ² tax and R&D (4) 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 (5) Capex excludes financial asset capex and acquisitions (6) Free cash flow comprises of cash flows from operating activities and from investing activities, but excludes cash flows from Acquisitions Note: Certain numerical figures and percentages set out in this presentation have been subject to rounding adjustments Page 14

15 Reconciliation of Certain Line Items of L1E Finance to DEA AG Group ( m) DEA AG FY 2016 Adjustments L1E Finance FY Comments Revenue 1, ,460 Slightly lower oil hedges, different accounting treatment of financial leases for gas storages Cost of Sales -1, ,261 Due to higher scheduled depreciation EBITDAX (1) P&L Financial Income Interest income from Upstream loan eliminated in consolidation at L1E Finance level, no net fx gains Financial Expenses Shareholder loan interest, net fx losses Income Taxes Net Income Change in deferred taxes related to purchase price allocation and current taxes Differences in revenues, financial result, taxes and higher DDA related to purchase price allocation Free Cash Flow (2) Working capital effect Net Debt 1, ,765 RBL net of amortized fees Balance Sheet Other and Deferred Tax Liabilities ,129 Deferred tax liabilities from purchase price allocation adjustment PP&E, Intangible Assets 3,097 +1,859 4,956 Effects from purchase price allocation Financial Receivables 2,209-1, Loans to related parties, intercompany eliminations (1) 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 (2) Free cash flow comprises of cash flows from operating activities and from investing activities, but excludes cash flows from Acquisitions Note: Certain numerical figures and percentages set out in this presentation have been subject to rounding adjustments Page 15

16 Contents 1. Highlights Financial Overview L1E Finance Reconciliation 4. Operational Update 5. Outlook 6. Appendix Page 16

17 Reserves Base Overview (1) Evolution of Reserves Reserves Breakdown by Country 800 1P Reserves Germany / Denmark 21% Egypt / Algeria 36% Norway 43% mmboe P Reserves Egypt / Algeria 35% Germany / Denmark 20% 0 1P P Norway 45% (1) >99% of reserves are audited by RPS Page 17

18 Reserves Base Overview High Potential Through Undeveloped Reserves (mmboe) Historical Evolution of 2P reserves (mmboe) % % % % 70% % % % 50% % % % 35 20% 10% Germany/Denmark Norway Egypt/Algeria Total 2P 2PD 2PD/2P Ratio 0% Production Acquisitions GoS Extension Organic Growth P: Sum of proven and probable reserves 2PD: Sum of developed proven and probable reserves Page 18

19 Njord Area Well established position in Norway DEA Significantly Increased its Share in Greater Njord Area as a Future Strategic Hub Transaction Overview DEA signed the SPA with Engie on 22 nd December 2016 to acquire participating interest in 7 licenses Acquisition includes 2P reserve additions of 35mmboe (1), with significant further upside Production of Njord Area to commence in Q The transaction between DEA Norge AS and Engie E&P Norge AS will be effective as of 1 st January 2017 Closing is expected to take place by Q after governmental approvals Njord Unit Licence Overview Acquisition of 20% in Njord (PL107, PL107C, PL132) Discovered in 1986, first production in 1997, gas export since 2007 via Åsgard transportation system Semi-submersible steel platform (Njord A) with drilling and processing facilities; oil pumped to floating storage unit Njord B Platform A currently in dry-dock, external inspections have been successfully completed confirming the need for minor refurbishment Submission of a revised plan of development and operation expected in March/April 2017 Acquisition of 10% in Hyme (PL348) Discovered in 2009, first production in 2013; Subsea tie-back to Njord Acquisition of 10% in Bauge (formerly Snilehorn) (PL348B) Discovered in A tie-back to Njord A was decided in 2016, and a plan for development and operation (PDO) is expected to be submitted to the authorities in 2017 Acquisition of 15% in Noatun (PL107B, PL107D) Gas discovery from 2008 Planned as subsea development with 3 depletion wells Unit Participation post-m&a Company Njord Hyme / Snilehorn Noatun Njord Hyme / Snilehorn Noatun Statoil DEA Njord Engie Faroe VNG POST M&A Point (1) As per 01/17 audit Petoro Page 19

20 Dvalin (Previously Zidane) Well DEA established Acquired Additional position Share in Norway in an Attractive Development Project Transaction Overview In Q4 2016, DEA increased its share in Dvalin project to 55% by taking 10% from Maersk Oil and another 5% from Edison Partners are now Petoro with a 35% share (newly acquired), and Edison Norge with a 10% share (previously 20%) DEA acquired 16mmboe of 2P reserves. Total 2P reserves amounting to 58mmboe (1) Project Update The Dvalin gas field, discovered in 2010, is DEA s first own operated field development project in Norway The Plan for Development and Operation (PDO) was submitted to the Norwegian Authorities in October 2016 and became effective on January 3 rd 2017; approval of PDO occurred in March 2017 The total development cost is estimated to be 1.1bn Map Unit Participation Company Pre-M&A Post-M&A DEA Norge AS 40% 55% Petoro AS 20% 35% Edison Norge AS 20% 10% Maersk Oil Norway AS 20% - (1) As per 01/17 audit Page 20

21 West Nile Delta Development Well position Norway Westestablished Nile Delta First Gas isinimminent Project Background Map The Project involves development of five major fields within the concessions, namely Taurus and Libra ( TL ) and Giza, Fayoum and Raven ( GFR ) TL fields are being developed fast-track - thanks to the existence of nearby infrastructure - through an offshore tie-in to existing West Delta Deep Marine (WDDM) subsea and onshore infrastructure GFR fields are being executed as a single project with a common completion and first gas date The Project is being developed by BP (WI: 82.75%), which is the Operator and DEA Deutsche Erdoel AG (WI: 17.25%) Project Update Production is expected to start in Q2 2017, significantly ahead of plan DEA s share of 2P Reserves are 98mmboe(1) with meaningful upside in contingent resources and yet to be discovered volumes The project expenditures are over 20% below original estimates. The cost savings are mainly attributed to the excellent well delivery performance, realized price deflation on contract awards, and reduced allowances (1) As per 01/17 audit Page 21

22 Contents 1. Highlights Financial Overview L1E Finance Reconciliation 4. Operational Update 5. Outlook 6. Appendix Page 22

23 Guidance and Outlook Production EBITDAX EBITDAX Capex kboe/d 1-10% higher than in 2016 (1) 20-30% higher than in 2016 Outlook Further focus on selective M&A, mainly focusing on North-western Europe and potentially new basins such as Brazil and Mexico Potential sanctioning of additional developments Proactive reservoir management of existing fields Commencement of production in West Nile Delta and Reggane Maintenance of financial discipline Focus on safety (1) Assuming $50-55/bbl for Brent and UK NBP of $ /mcf Page 23

24 Contents 1. Highlights Financial Overview L1E Finance Reconciliation 4. Operational Update 5. Outlook 6. Appendix Page 24

25 DEA Asset Base Overview Field Operator Working Interest Oil/Gas Split 1PD (mmboe) 1P (mmboe) 2PD (mmboe) 2P (mmboe) 2016 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) Individual sums may not add up due to rounding (2) Reserves as of January 1 st, 2017 Page 25