Neptune Energy
OVERVIEW
1 GENERAL AND 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 report 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. Comparative data for Neptune for the corresponding reporting period ended 31 December 2018 therefore includes only ten and a half months results contribution from the EPI business. In this report, 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. Production for interests held under production sharing contracts is reported on an appropriate unit of production basis. The discussion in this report 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 report speak only as of the date of such statement or the date of this report. This report 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. Introduction SHAREHOLDERS
Headquartered in Beijing, China Global alternative asset manager with Founded in 1981, CVC has $75bn of assets Investment Corporation (CIC) was $212bn of assets under management. under management, $123bn of funds founded in 2007, as China's sovereign Carlyle International Energy Partners, a committed, and a global network of wealth fund. As of 2017, total assets of dedicated energy vehicle, was established offices across Europe, the Americas and CIC exceeded $940bn in 2013 Asia Pacific
Neptune ownership 49.0% Neptune ownership 30.6% Neptune ownership 20.4%
Board of Directors
Audit Risk Committee
Corporate Responsibility Committee
Remuneration and Nominations Committee
Source: Company information 4 1 Excludes credit 2 <1% is held by management MANAGEMENT TEAM
SAM JIM ARMAND KICK LAIDLAW HOUSE LUMENS STERKMAN Executive Chairman CEO CFO Head of HSEQ
MARK GRO ANDREA DAVID RICHARDSON HAATVEDT GUERRA HEMMINGS VP Projects VP Exploration & VP Reservoir VP Business Development Engineering Development
PETE PHILIP BEN KAVEH JONES LAFEBER WALKER POURTEYMOUR Chief Information VP Operations, Europe VP Operations, North General Counsel Africa, Asia Pacific Officer
JULIAN AMANDA REGAN-MEARS CHILCOTT Director of Corporate Group HR Director Affairs
5
5 NEPTUNE AT A GLANCE LEADING INTERNATIONAL INDEPENDENT E&P COMPANY
Large-scale, geographically diversified portfolio Gas weighted portfolio, 2019 production of 143.9 kboepd
Europe North Africa APAC 2019 production split 2019 revenue split
Norway Oil Oil 39% 27% United Indonesia Kingdom Gas 73% Gas(1) 61% Germany Australia
Netherlands AlgeriaAlgeria Egypt Continued focus on gas benefiting from the energy transition and increasing gas demand
Strategy geared towards organic and inorganic growth Strong operational and financial performance
Production efficiency 2019 Reserves split Growth opportunities Adj. EBITDAX ($bn) 2019 production split performance Non- North Africa ◼ OECD Strong pipeline of sanctioned projects to underpin 1.9 Asia Pacfic 4% 88% 85% (2) 1.6 22% growth (c.110 kboepd net new production ) 1.5 14% 1.4 Norway Germany 47% 9% ◼ Recent exploration success in Norway and the UK
Netherlands 15% OECD ◼ Around $1.9bn of headroom to support 2016 2017 2018 2019 UK 2018 2019 11% 78% investment plans and strategic acquisitions 6 2019 YE Reserves: 633 mmboe
1
Source: Company information Note: Production efficiency defined as ratio of actual production to maximum production potential (maximum rate at which plant can deliver at optimum conditions with no downtime) 1 Including oil-linked; 2 Includes North Sea acquisition announced October 14, 2019 6
6 Strategy NEPTUNE KEY CREDIT HIGHLIGHTS
1 2 3 4 5
Large-scale, Long life and low Gas-weighted Significant cash Strategy focused geographically cost production portfolio well- flow generation, on value accretive diversified profile positioned to take strong balance growth and yield portfolio advantage of the sheet and energy transition disciplined capital and increasing gas allocation demand
8 LARGE-SCALE, GEOGRAPHICALLY DIVERSE PORTFOLIO ONE OF THE LARGEST EUROPEAN INDEPENDENT E&P COMPANIES
Neptune’s countries of 2019 net production (kboepd) operations 2019 net 2P reserves (mmboe)
UK Norway Netherlands Indonesia Germany, Algeria, Egypt Rest of the world 200 1000
180 900 OECD Non-OECD 160 800
140 700
120 600
100 500
80 400
60 300
40 200
20 100
0 0
Source: Publicly available information including corporate presentations, filings and websites Note: Reserves and production presented on a net basis (working interest or entitlement) 9 LONG LIFE AND LOW COST PRODUCTION PROFILE LARGE SCALE, EARLY CYCLE ASSETS BOLSTERING RESERVE LIFE
NetIllustrative production reserve (kboepd) life of key early cycle assets Overview
Operator % of 2019 prod. 2020 2030 ◼ Combination of large-scale and early cycle assets providing robust, long- life and low-cost production profile Snøhvit Up to Equinor 11% ◼ Majority of assets have either a long and stable track record of (12%) 2050s production or have recently come onstream
‒ Jangkrik Snøhvit indicates a production life beyond 2050 Eni 14% (33%) ‒ Cygnus, Jangkrik and Touat commenced production in 2016, 2017 and 2019 respectively; and expected to produce into the 2030s Cygnus Neptune 11% (39%) ‒ Gudrun also expected to produce into the 2030s ‒ Gjoa expected to produce into late 2020s, with potential to extend Touat Neptune nm through additional tie-backs such as the Grosbeak discovery (35%)(1) ◼ Early cycle assets ensuring lower costs, depletion and decommissioning expenses Gudrun Equinor 11% (25%) ◼ As of December 31, 2019, average 2P reserve life of portfolio was 12 years and the average 1P reserve life was 8 years
Gjøa Neptune 17% (30%)
Source: Company information 2 Touat BV (Neptune owns 54%) and Sonatrach are co-operators 10
10 GAS WEIGHTED PORTFOLIO WELL POSITIONED IN DIVERSIFIED GAS MARKETS
Gas-weighted by volume, balanced by revenue(1) Diversified access to global markets
Production mix Revenue mix
Dry gas
2 52% 1 61%
LNG
20%
Liquid 39% 28%
Global energy demand growth by fuel type Benefits of a gas weighted portfolio Neptune’s positioning BCM ◼ Natural gas viewed as key for the global transition to a low-carbon energy world 20,000 9% ◼ Gas weighted production and balanced revenue 37% 16% 5% -10% 43% ◼ Gas demand expected to increase by 41% by 2035 mix
◼ Diversified supply and access to domestic and ◼ Widely considered as cleanest burning fossil fuel for electricity production and heating 10,000 global gas markets ◼ c.46% lower carbon emissions than coal and c.27% lower than diesel / gasoline ◼ LNG offers flexibility and mobility ◼ Longer life assets with lower decommissioning costs
0 ◼ Oil linked contracts provides exposure to
Oil
Gas
Coal 2035 2018 upside from oil prices Other ◼ Lower operating and development costs with significantly higher recovery factor and structural
Nuclear reliability Renewables
Source: Company information, EIA, Shell LNG outlook 2020 1 Including oil linked 11 11 NEPTUNE INVESTMENT PROPOSITION DEMONSTRATING A TRACK RECORD OF CASH FLOW GENERATION AND GROWTH
Since the acquisition of EPI in early 2018, we have delivered operational improvements and growth throughout the business
Neptune Energy portfolio* Generated significant earnings Mid-term Pro-forma Sanctioned Exploration and cash flows over the past TRIR(2) target Opex 2P reserves(5) projects(3) potential(6) two years production(4)
2.1 664 mmboe 9 200 kboepd $10.3/boe 2,307 mmboe EBITDAX
(1) Engie E&P International in 2017 $3.5 Billion(9) Sanctioned Exploration TRIR(2) 2P reserves Production Opex projects(3) potential(6) 4.9 555 mmboe 2 154 kboepd $10.5/boe 804 mmboe Operating cash flow
Our acquisition strategy has added high quality and complementary assets in our core regions $2.5 Billion (9)
4 material $1 billion 115 mmboe ~60 kboepd * Our acquisition of the North Sea assets from transactions(7) invested (7) 2P reserves Production(8) Energean Oil & Gas is contingent on the completion of Energean’s transaction with Edison
1. The performance of Engie E&P International in 2017 6. Mean net prospective resources 2. Total Recordable Injury Rate (TRIR) 7. Apache UK Central North Sea assets ($70m), VNG Norge ($437m), ENI Merakes interest ($235m), Energean Oil & Gas North Sea assets ($250m)* 12 3. 2017 includes Touat and Njord; Neptune has added Duva, Gjøa P1, Fenja, Nova*, Dvalin*, Seagull, Merakes 8. Includes assets already in production (7 kboepd) and projects in development - Seagull (15 kboepd), Merakes (15 kboepd), Fenja (10 kboepd), Nova (7 kboepd) and Dvalin (5 kboepd) 4. Neptune production outlook following completion of project pipeline and includes Energean Oil & Gas North Sea assets 9. Cumulative EBITDAX and post-tax operating cash flows since 12 February 2018 5. Pro-forma 2P reserves includes Energean Oil & Gas North Sea assets GROWTH STRATEGY CONTINUED STRONG CASH FLOW SUPPORTING DEVELOPMENT
Reserves M&A Yet to find
90% Two material Increase recovery reserves replacement in bolt-on acquisitions from existing assets 2019 announced in 2019(2) Refreshed exploration Yet to find (4) Increasing proportion Added >100 mmboe portfolio and
of developed reserves of low cost reserves increased investment kboepd
and resources(3) 200 200 Converted ~100 mmboe Continue to 2C production (4) of contingent resources Strengthened manage portfolio into reserves in acreage position opportunities 2018/19(1) in core areas
Increasing the depth and quality of our portfolio 2P production(4) through targeted investments
2022
1. Total additions in 2018 and 2019 3. 2P reserves and 2C resources added in 2019, including the Energean Oil & Gas North Sea assets 2. ENI Indonesia assets and Energean Oil & Gas North Sea assets. Completion of the Energean transaction is contingent on Energean’s 4. Illustrative production profile. Some contingent resources may not be developed and production may vary from period to period 13 transaction with Edison ENVIRONMENT, SOCIAL AND GOVERNANCE MEETING SOCIETY’S ENERGY NEEDS AND THE ENERGY TRANSITION
Setting carbon and methane intensity targets Creating sustainable value for our stakeholders
– Contributing to economies by creating jobs, – Targeting a carbon intensity of 6kg CO2/boe for our operated production by 2030, a reduction of 60% compared to taking no action supporting local supply chains and paying taxes – Our current methane intensity is 0.02% and we are targeting net zero – $2.8 billion gross value added(3) to the economies of Norway, methane emissions by 2030 the UK, the Netherlands and Germany in 2019
Carbon intensity(2) (3) We support the UN Sustainable Economic impact Development Goals, which aim to Europe ($m) kg CO2/boe address global challenges such as Projected carbon 20 intensity in 2030 poverty, inequality and climate change without action Direct: GDP 18 generated by Core business contributes to: 15 our operations 60% reduction Indirect: SDG 7: Affordable and clean energy 10 in carbon spend with intensity supply chain 8.0 5 SDG 8: Decent work and economic growth 6.0 6.0 Induced: 5.8 wage spend in the wider 0 economy SDG 13: Climate action Global industry (1) 2018 2019 Likely 2020 level 2030 target average in 2018
1. International Association of Oil & Gas Producers (IOGP) 2. Carbon intensity includes Scope 1 and 2 emissions related to appraisal/development drilling and production/operations. We calculate intensity using wellhead production, in line with IPIECA sustainability reporting guidance. 14 3. Socio-economic impact includes our direct impact (employment and GDP generated from our activities), indirect impact (supply chain spend and employment) and induced impact (wage consumption in the wider economy) to the economies of Norway, the UK, the Netherlands and Germany Operations COVID-19 AND OIL PRICES RESILIENCE PLAN IN PLACE
Activated our pandemic emergency plan to protect our people and assets
People Operations Projects
The health and safety of our people, and all those Maintaining operational continuity, while reducing Protecting project delivery and asset values who work with us, is our number one priority non-critical activities through enhanced cooperation
– Acted quickly and have implemented our – No impact at our operations – Reviewed our project pipeline and identified areas pandemic emergency plan – Altered shift patterns; reduced non-critical activities of risk – Merakes delayed until mid-2021 – Working with the authorities, our partners and – Stopped or reduced travel – Mitigation plans are in place for critical path global health providers activities – Increased screening capability at all entry points to – Extra precautions are in place for our offshore our operations – Evaluating supply chains for impacts workers – Continuous dialogue with our industry peers – Focus on collaboration, cooperation and – Repatriated all non-essential Neptune employees communication across projects, JV partners and and contractor personnel from Algeria – ~$50 million of operating cost reductions (opex and suppliers G&A in 2020) – ~$250-350 million of capex reductions (~25%) in Resilience through commodity price cycles 2020
Long-life and low-cost Hedged operating cash Strong balance sheet and Fully-funded development Operated assets provide assets flows liquidity projects control of activities
16 COST REDUCTION INITIATIVES $300-400 MILLION OF COST REDUCTIONS IDENTIFIED ACROSS OPERATING COSTS, G&A AND CAPEX
Operating costs and G&A Development capex
Original 2020 (2) Revised 2020 (2) Revised 2020 Original 2020 Cost reduction budget (1) Cost reduction budgets (1) plan (3) plan (3) $50 $250-350 $680 million $630 $1,100 million $750-850 million million million million
G&A initiatives Operating cost initiatives Development capex initiatives – Reduction in vacancies and contractors – Reductions targeted across all our regions – Merakes and Maha on hold until 2021 – Deferment of non-critical IT projects – Savings in logistics, maintenance and scope – Potential capex deferrals at Duva, Fenja and Seagull – Reduction in travel – Lower royalties in Germany – Deferral of development drilling in the Netherlands, Germany and Egypt
Exploration Financial Original 2020 Cash dividend paid (1) – Currently reviewing our exploration plans for 2020 budget – No cash dividend to be paid in 2020 in 2019 – Possible deferrals of drilling and seismic acquisition – All spending under review with JV partners – G&G and new ventures savings $145 million – Portfolio management $200 million
1. Original budget as approved in December 2019 2. Cost reduction includes targeted savings and cost deferrals 17 3. Revised 2020 plan as at 25 March 2020. Further changes to these plans are expected COMMODITY MARKETS DIVERSIFICATION, HEDGING AND LOW COST STRUCTURE TO PROTECT CASH FLOWS
2020 post-tax hedge ratio as at Benchmark oil & gas prices Cash breakeven costs in 2020(2) March 2020(3) $/bbl p/therm(1) 90 90 Brent oil price $/boe 89% 89% 90% 80 80 84% 70 70 68% 60 60 63% 54% 53% 56% 50 50 52% 40 40 36% 36% 30 30 27% UK gas price 20 20 19% 17% 10 10 0 0 Q1 Q2 Q3 Q4 FY Oil Gas Total
Production diversification balances our exposure Some projects may slow and expenditures deferred to different geographies and commodity markets Low breakeven cost Disciplined approach to capital allocation, with projects and hedging provides Our existing assets are long-life and low-cost screened at a range of commodity prices, including: – a low case of $25/bbl protection from Near-term cash flows are protected by our hedging strategy weaker commodity – price curves over the lifecycle of a development We have a strong balance sheet, cash prices flow generation, low leverage and significant liquidity While leverage is expected to increase in 2020, projects coming onstream are low-cost and our capex Additional cost saving measures are being targeted commitments will drop
1. NBP 2. Breakeven costs are shown before financing ($1.9/boe) and tax ($0.3/boe) and exclude our equity accounted entities. Our forecast all-in cash breakeven cost in 2020 is $31.4/boe. Assumes $50 million of opex and G&A savings and $300 million reduction in capex. 18 3. Aggregate post-tax hedge ratio for Q2, Q3 and Q4 as at March 2020 (Q1 2020, reflects 31 December 2019 position). Oil includes gas production sold as LNG and priced in relation to oil prices. FINANCIAL AND OPERATING RESULTS STRONG HSE, OPERATING AND FINANCIAL PERFORMANCE
HSE KPIs Operating KPIs Financial KPIs
Socio- Reserves Leverage(4) Carbon Production Operating TRIR(6) economic Production(5) replacement Opex(1) Capex(3) Net debt to intensity(7) efficiency cash flow(2) impact(8) ratio EBITDAX
143.9 FY 2019 2.1 5.8 $2.8bn 85% 90% $10.3/boe $1,321m $826m 0.93 kboepd
161.8 FY 2018 2.6 6.0 $2.6bn 88% 244% $10.2/boe $1,219m $441m 0.62 kboepd
1. Opex including royalties 6. Total Recordable Injury Rate (TRIR) is defined as the number of recordable injuries per 1 million hours worked. It is calculated on a 12-month rolling average as follows: (fatalities + lost workday cases + restricted workday case + medical treatment cases) 2. Cash flow from operations, after tax and excluding acquisition costs incurred in connection with the EPI and VNG Norge transactions TRIR = x 1,000,000 3. Development capex, excluding acquisitions, exploration and equity accounted entities 푁푢푚푏푒푟 표푓 ℎ표푢푟푠 푤표푟푘푒푑 19 4. Net debt (excluding Subordinated Neptune Energy Group Limited Loan and Touat Project finance facility) to EBITDAX (excluding our share of net income from 7. Carbon intensity includes Scope 1 and 2 emissions related to appraisal/development drilling and production/operations. It is measured using wellhead production on a kg of CO2 per boe basis Touat), as defined by the RBL and shareholder agreement 8. Socio-economic impact includes our direct impact (employment and GDP generated from our activities), indirect impact (supply chain spend and employment) and induced impact (wage 5. Includes equity accounted entities consumption in the wider economy) to the economies of Norway, the UK, the Netherlands and Germany LARGE-SCALE, GEOGRAPHICALLY DIVERSIFIED PORTFOLIO HIGH QUALITY ASSETS WITH ROBUST OPERATIONAL PERFORMANCE
Norway North Africa Germany
◼ Conventional and sizeable portfolio contributing almost half of Algeria: ◼ Sizeable portfolio with mainly operated, stable, oil-weighted onshore Neptune’s total production production and exploration upside ◼ Majority of reserves in North Africa attributed to the Algerian Touat ◼ Includes key fields such as Snøhvit, Gjoa and Gudrun with gas field ◼ Diverse portfolio with significant in-place resources satellite potential and further upside ◼ Field came onstream in September 2019 ◼ Exploration upside through the operated Schwegenheim well ◼ Long life assets with limited near term decommissioning costs ◼ Multi-TCF strategic asset for Algeria currently drilling ◼ Focused exploration portfolio with high impact wells ◼ Phase 2 of development at Touat aims to extend the production ◼ Recent acquisition from Wintershall Dea increases stakes in certain ◼ Stable OECD country with supportive tax regime plateau fields adding c.0.6 kboepd (net)
◼ The fiscal regime allows offsetting c.90% of development costs Egypt: and 78% of exploration costs against tax liabilities ◼ Low cost production with exploration upside ◼ Limits the impact on our cash flow of investing in long-term ◼ Secured the North West El Amal exploration license in 2019 portfolio sustainability
UK Asia Pacific Netherlands
◼ Growing position in stable and supportive fiscal regime ◼ Indonesian portfolio features existing production, short-term growth ◼ Neptune is the largest offshore operator on the Dutch continental shelf and long-term potential for further discoveries and tie-backs to ◼ Cornerstone is the operated, long life, gas producing Cygnus field, existing infrastructure ◼ Mature, cashflow generative, and largely gas production base with and operated Seagull oil development ◼ LNG production sold internationally and to the growing domestic good track record of reserve replacement market ◼ Cygnus is an important indigenous gas field contributing up to ◼ Significant domestic gas market in the Netherlands with gas 10% of domestic gas production ◼ Recently acquired interests in the Indonesian Kutei Basin including contributing c.36% to the energy needs the low-cost Merakes gas development ◼ Material discovery at the Isabella prospect drilled in 2019/20 ◼ Merakes to be developed as a subsea tie-back to Jangkrik, with ◼ Operator of two of the three strategic gas transportation infrastructure first gas expected in mid-2021 in the Netherlands – NGT and NOGAT ◼ Acquired a 25% interest in the material Glengorm discovery ◼ 30% stake in West Ganal block awarded with additional resources ◼ Net cash margins in the UK benefit from substantial historic tax ◼ In Australia, we continue to evaluate development options for the losses and available allowances Petrel discovery
20
20 PRODUCTION OUTLOOK SIGNIFICANT PROGRESS WITH 110 KBOEPD PROJECT PIPELINE
Production by type and region(3) kboepd Full year contribution from projects brought 250 New projects (2) (1) Njord Area, Fenja and onstream in 2021 Askaladd and Dvalin Gas Existing production onstream Duva/Gjøa P1, Seagull, Oil Nova(1) and Merakes 28% Touat ramping onstream 200 Touat and Gas (2) up to plateau Snøhvit Nord 49% 51% 51% onstream Liquids 150 LNG 21%
100 Indonesia 14% North Africa 50 4% 18% Non- Germany 9% OECD 47% Norway 0 OECD
2019 2020 2021 2022 Netherlands 15% 82%
New project opportunities 11% UK Glengorm(1), Isabella, Echino South, Sigrun East, Maha, Merakes East, Touat phase II, Petrel
1. Neptune participating interests in Dvalin, Nova and Glengorm are subject to completion of the Energean Oil & Gas transaction 2. Snøhvit Nord and Askaladd increases available production capacity for our Snøhvit LNG export facility 21 3. 2019 full year production including equity accounted entities HIGH QUALITY GROWTH PIPELINE PROJECTS TO DELIVER ~110 KBOEPD
Production net 2019 2020 2021 Key projects Operator Latest progress to Neptune
Touat Neptune Production commenced in September 2019. 15 kboepd(3) Neptune 35% Snøhvit Nord (production commenced in Q3 2019) and Snøhvit satellites Equinor Askeladd (2020 start-up). Askeladd development drilling 8 kboepd Neptune 12% underway.
Njord Area Equinor Njord project includes recommencement of production from Hyme and first oil from the Bauge field. 25 kboepd Neptune 22.5%(1)
Fenja Neptune Offshore campaign (pipelines, umbilical cables, subsea templates and manifolds) successfully completed. 10 kboepd Neptune 30%
Duva/Gjøa P1 Neptune Development drilling underway. 10 kboepd Neptune 30%
Seagull Neptune Detailed design and engineering work underway. 15 kboepd Neptune 35%
Merakes ENI Due to COVID-19 restrictions, first gas from Merakes is now (3) anticipated in mid-2021. 15 kboepd Neptune 20%(2)
Dvalin Wintershall DEA Development drilling underway. 5 kboepd Neptune 10%(4)
Nova Wintershall DEA Nova module to be installed in Q2 2020. 7 kboepd Neptune 15%(4)
1 Neptune has a 22.5% working interest in Njord and a 12.5% interest in the Hyme and Bauge satellites 4 Neptune participating interests in Dvalin and Nova are subject to completion of acquisition 2 Neptune has a 20% working interest in Merakes/Merakes East and a 30% interest in Maha 5 Including development and maintenance capex 22 3 Entitlement production net to Neptune. Actual plateau rates are subject to debottlenecking, plant uptime and other commercial arrangements EXPLORATION KEY SUCCESSES IN 2019 AND EARLY 2020
Echino South Sigrun East Isabella Oil & gas discovery Oil discovery Gas condensate discovery
Sigrun East
Echino South
Isabella
6 November 2019 2 March 2020 17 March 2020 Neptune Energy 15% Neptune Energy 25% Neptune Energy 50%(2) Location: Norwegian North Sea Location: Norwegian North Sea Location: UK Central North Sea PL090 partners: Equinor (36%, operator), Exxon (25%), Well partner: Equinor (75%(1), operator) P1820 partners: Total (30%, operator), Ithaca Energy Idemitsu Petroleum (15%) PL025/PL187 partners: Equinor (36%, operator), (10%), Edison (10%) Gross recoverable resource estimate: 38-100 mmboe OMV (24%), Repsol (15%) Gross recoverable resource estimate to be confirmed following analysis of the well results and drilling an Potential to commercialise, through a subsea Gross recoverable resource estimate: 7-17 mmboe appraisal well tie-back development Potential to commercialise, along with the Sigrun HPHT discovery, with hydrocarbons encountered Drilling the Blasto prospect in 2020/21 discovery, through a subsea tie-back development in Upper Jurassic and Triassic sandstone reservoirs to the Gudrun platform
1. Equinor and Neptune drilled Sigrun East on a sole risk basis. Due to the funding contribution Equinor’s interest in the discovery is 75%, compared to its 36% interest in the licence 2. On completion of the Energean North Sea acquisition, Neptune will acquire a further 10% interest in P1820 23 RESERVES AND CONTINGENT RESOURCES DEVELOPING OUR RESOURCE BASE THROUGH INVESTMENT AND ACQUISITIONS
22% 90% reserves 2P reserves 633 2C resources 302 43% Non-OECD replacement ratio (150% including by region (2,3,4) mmboe by region (2,5) mmboe OECD 57% Energean transaction(1))
78%
2P reserves by region(2,3,4) Increased 2P reserves life to 12 years
~100 mmboe of 2C resources
mmboe converted to reserves in 2yrs
2P reserves(4) Production Organic Acquisitions 2P reserves(4) Additional Pro-forma 2P 31 Dec 2018 additions 31 Dec 2019 acquisitions(1) reserves(4)
1. Includes 2P reserves attributable to the Energean Oil & Gas North Sea assets and subject to the completion of the transaction 4. 2P reserves are defined as proved plus probable reserves and have a 50% probability that the actual quantity will equal or exceed this estimate 2. As at 31 December 2019 5. 2C resources are defined as contingent resources with a 50% probability that the actual 24 3. Our reserves are reviewed annually by an independent third party quantity will equal or exceed this the estimate. We include contingent resources under the development pending, on hold and unclarified categories. Financials FINANCIAL HIGHLIGHTS RESULTS FOR THE YEAR ENDED 31 DECEMBER 2019
Earnings robust despite lower Strong operating cash Leverage remains production and softer prices flows supporting growth within desired levels
EBITDAX(1) Post-tax operating cash flow(3) Net debt(6) ($m) ($m) ($m) 1,490 1,883 1,321 1,600 1,219 1,284
2018(2) 2019 2018 (2) 2019 2018 2019
Net profit Capex(4) Net debt to EBITDAX(1, 5, 6) ($m) ($m) (x) 0.93 439 826 0.62 262 441
(2) 2018 2019 2018(2) 2019 2018 2019
1. EBITDAX (as defined by the RBL and Shareholder agreements to exclude our share of net income from Touat). EBITDAX comprises net income for the period 4. Development capex excluding acquisitions and exploration before income tax expense, financial expenses, financial income, other operating gains and losses, exploration expense and depreciation and amortisation. 5. As Neptune only completed the acquisition of EPI on 15 February 2018, the 2018 12 month EBITDAX value of $2,055.2m is calculated on a pro-forma basis 26 2. Reflects the acquired EPI business from 15 February to 31 December 2018 assuming Neptune had owned the business from 1 January 2018 3. Cash flow from operations, after tax and excluding acquisition costs incurred in connection with the EPI and VNG Norge 6. Book value net debt excluding Subordinate Neptune Energy Group Limited Loan and Touat Project finance facility as defined in RBL and shareholders agreement KEY FINANCIALS AVERAGE REALISATIONS AND HEDGING
Average realisations 2019 2018(2) – Neptune hedges post-tax operating cash flows; therefore Pre-hedge realisations hedged volumes are less than anticipated sales Gas $/mmbtu 4.7 7.9 – Oil price hedges include hedges for gas production sold as LNG LNG(1) $/mmbtu 8.3 8.2 and priced in relation to oil prices Oil $/bbl 62.0 69.6 – Balanced revenue from oil and gas mitigating exposure Other liquids $/bbl 39.0 58.3 – Post-tax operating cash flow hedge ratio of 84% for gas in 2020 Post-hedge realisations – Current hedge ratios exceed obligations under our RBL facility in 2020 Gas $/mmbtu 5.2 6.9 LNG(1) $/mmbtu 8.3 8.2 – As of 31 December 2019, unrealised hedge gains equalled $183 million, Oil $/bbl 61.5 67.5 of which $135 million relates to contracts expiring in 2020 Other liquids $/bbl 39.0 58.3 – As of 20 March 2020, unrealised hedge gains equalled $422 million Aggregate post-tax hedge ratio – equity case Hedged prices(3) 2020 2021 2022 Hedge Coverage per Year 2020 2021 2022 Gas Position at end-December 2019 Upside cap $/mmbtu 6.6 6.7 5.5 Oil 27% 0% 0% Downside floor $/mmbtu 5.5 5.5 5.3 Gas 84% 60% 18% Oil Total c.56% c.26% c.7% Upside cap $/bbl 69 NA NA Position at end-March 2020(4) Downside floor $/bbl 60 NA NA Oil 24% 0% 0% Gas 90% 65% 49% Total c.57% c.30% c.19%
1. The average realised LNG price reflects some contracts that are linked to JCC prices averaged over an agreed lagged period. Those volumes are hedged using oil-linked instruments 2. Results for 2018 consolidate the acquired EPI business for the post acquisition period only, from 15 February 2018 to 31 December 2018 27 3. March 2020 hedged prices 4. The hedge position for 2020 at end-March reflects Q2-Q4 2020 KEY FINANCIALS ROBUST EARNINGS PERFORMANCE DESPITE SOFT COMMODITY PRICES
Income statement summary ($ million)(3) 2019 2018(1) – Net profit higher due to lower G&A, exploration expense and taxation Total revenues 2,202 2,538 – Tax expense reduced by deferred tax credits recognised in Cost of sales (1,159) (1,203) the UK and current tax credits in Norway and the Netherlands Exploration expenses (60) (89) – Achieved operating costs at the lower end of guidance G&A expenses (69) (132) – Reorganisation costs of $68.9 million in France, Germany and the Netherlands Equity accounted entities 2 4 (5) Other operating (losses)/gains (44) (69) – Post-tax impairments of $28 million in the Netherlands, the UK and Norway Operating profit 873 1,049 Net finance costs (196) (143) Profit before tax 677 906 Tax (238) (645) Income tax reconciliation ($m) Reported net income 439 262
2019 2018(1) Opex $/boe 10.3 10.2 DD&A(2) $/boe 12.0 12.9 Effective tax rate % 35% 71% Adjusted effective tax rate(4) % 71% 67%
Pre-tax Expected Income Non-tax Prior year Deferred Other Income tax profit tax charge subject to deductible adjustment tax charge different expense rates
5. $59.4 million on a pre-tax basis 1. Results for 2018 consolidate the acquired EPI business for the post acquisition period only, from 15 February 2018 to 31 December 2018 2. Depreciation, depletion and amortisation 28 3. Numbers might not equal due to rounding differences 4. Adjusted for deferred tax credits, current tax credits and restructuring costs KEY FINANCIALS STRONG OPERATING CASH FLOWS
Cash flow summary(3) ($ million) 2019 2018 – Operating cash flows fully funded our organic investment and financing costs in 2019 Net operating cash flows 1,321 1,156 – Significant development capex deferrals smoothing investment across 2020 and 2021; Equity accounted entities (63) (15) $750-850 million development capex guidance in 2020 Development capex (826) (441) – Exploration spend in 2020 is under review Exploration capex (62) (20) – Cash taxes expected to be $16 million in 2020(4) Net acquisitions (249) (3,612) Net finance costs (126) (144) Lease accounting (32) 0 (1) Change in debt 127 1,682 Commodity price sensitivity in 2020 Equity issue 0 1,977 Oil ±$10/bbl Gas ±$1/mcf Dividends paid (200) (380) ($) ($) Net change in cash (111) 204 -300 -200 -100 0 100 200 300 -200 -100 0 100 200
EBITDAX Development capex profile(2) Pre-hedging $m 826 750-850 Post-hedging
441 Op. Cash Flow
Pre-hedging
Post-hedging 2018 2019 2020 2021 2022
1. For illustrative purposes only. The actual cash flow and EBITDAX sensitivity will depend on a range of factors and will vary from period to period 3. Numbers might not equal due to rounding differences 2. Development capex excluding acquisitions. Forecast are subject to change 4. Cash taxes are sensitive to a range of factors including commodity prices, investment, production and acquisitions 29 KEY FINANCIALS HEADROOM FULLY FUNDS OUR INVESTMENT PLANS
Debt composition at 31 December 2019 – Significant available liquidity funds project pipeline $100m $108m – Limited near-term debt repayment obligations – Leverage ratio is expected to remain well within RBL threshold in 2020 $256m $690m – Reduction in leverage as new production comes onstream
Senior Notes Short-term facility – Leverage at 31 December 2019 was well within shareholder agreement and RBL Touat project finance facility RBL Engie Vendor Loan thresholds $850m – Total available liquidity of ~$1.2 billion in March 2020 Net debt position in March 2020(2) $m Net debt to EBITDAX projections(1) x 4.00 RBL limit 3.50 3.00 78 Assumes 2.50 $30/bbl Assumes $40/bbl 2.00 Assumes $50/bbl 1.50 0.93 1.00 0.62 0.50 0.00 2018 2019 2020 2021 2022
1. As defined in our RBL and shareholders agreement. EBITDAX forecasts are subject to change 2. Management estimate of net debt position at 31 March 2020 30 Summary OUTLOOK DELIVERING IMPORTANT PROGRESS ACROSS THE PORTFOLIO
2019 was a year of important strategic delivery, Guidance for 2020 laying foundations for growth in reserves and production Production 145-160 kboepd(1) – Pandemic emergency plan activated; focused on people, operational continuity, project delivery Resilience Opex $10-11/boe – Resilience in low commodity price environment – Operator of much of our programme adds flexibility Development capex $750-850 million – Cost reductions of $300-400 million identified, across operational costs, G&A and capex programmes Operations – Committed to industry leading environmental targets – Delivering improvements in production efficiency
– Strong reserves replacement ratio in 2019, including two Growth strategic acquisitions – On course to achieve 200 kboepd through low-cost projects – Discoveries at Isabella, Echino South and Sigrun East prospects
– Significant available headroom and liquidity – High hedge ratio protects cash flows from low prices in 2020 Financial discipline – Reduction in leverage ratio a priority in 2021
1. Our production guidance is subject to unplanned shutdowns, project timing, closing the Energean transaction and the impact of COVID-19 on our operations 32 Asset Summary SNØHVIT, NORWAY
PARTNERS FIELD FACTS Neptune Energy (12%), Equinor Energy (36.39% and ▪ Snøhvit is the first offshore development in the Barents Sea. It is one of the key operator), Petoro AS (30%), producers in the Norwegian portfolio with enough extractable gas to maintain Total E&P Norge AS (18.4%) production to 2040. New projects are set to extend field life further and expand and DEA Norge AS (2.81%) production to meet the LNG plant’s processing capacity.
Snøhvit production ▪ Snøhvit is the first major development on the Norwegian continental shelf with no Daily average production surface installations. It has no fixed or floating units. Instead, its subsea production facilities operate in water depths of 250-345 metres. 2019 production (kboepd) ▪ It consists of three main structures: Snøhvit, Albatross and Askeladd. Nine wells have been drilled at Snøhvit, seven for production and two for reinjecting CO2. LNG production 13.3 ▪ The project relies on one of the world’s longest subsea tie-backs. Natural gas is transported along a 143 km pipeline for liquefaction at the world’s northernmost LNG Liquid production 2.8 facility, a purpose-built plant on Melkøya Island.
▪ Snøhvit is host to a Carbon Capture and Storage (CCS) project which deposits 700,000 tonnes p/a of carbon in a depleted natural gas reservoir deep below the seabed. Total production 16.1 ▪ First gas: August 2007
34 GJØA, NORWAY
PARTNERS FIELD FACTS Neptune Energy (30%), Petoro (30%), Wintershall ▪ Gjøa is the largest operated asset in the Neptune portfolio and a major hub platform in Norge (20%), Norske Shell the northern North Sea. The area encompasses the Gjøa, Duva and Nova fields. (12%), DEA Norge (8%) ▪ Predominantly a gas reservoir, now set to produce 100 mmboe more than was OPERATOR estimated when production started. Neptune Energy ▪ In June 2019, the Norwegian Authorities approved two new subsea tie backs from the Duva and Gjøa P1 fields with production expected in 2020 and estimated to be in the Gjøa production order of 120 mmboe. Daily average production ▪ Gjøa is the first floating production platform to be powered sustainably by onshore facilities. A 100 km submarine cable delivers hydropower-generated electricity from 2019 production (kboepd) Mongstad. Electricity from the mainland saves 200,000 tonnes in CO2 emissions annually. Gas production 14.8 ▪ First oil: 2010
Oil production 2.9
Liquid production 6.1
Total production 23.8
35 CYGNUS, UK
PARTNERS FIELD FACTS Neptune Energy (38.75%), Spirit Energy (61.25%) ▪ Cygnus is the largest single producing gas field in the UK, typically exporting more than 250 million standard cubic feet of gas daily, contributing around seven per cent of UK OPERATOR gas production. Neptune Energy ▪ Cygnus connects via the Esmond Transmission System (ETS) pipeline to the Perenco UK Production operated terminal at Bacton. Daily average production ▪ Cygnus Alpha is made up of three bridge-linked platforms: a wellhead drilling centre, a 2019 production (kboepd) processing/utilities unit and living quarters/central control room. Cygnus Bravo, an unmanned satellite platform, is approximately seven kilometres northwest of Cygnus Alpha. Gas production 16.1 ▪ The export route is via a new 50km pipeline to the ETS pipeline.
Liquid production 0.4 ▪ Nine wells drilled to date, with additional wells planned in the field development plan.
▪ First gas was in 2016, with the field expected to produce into the 2030s.
Total production 16.5
36 INDONESIA
FIELD FACTS PARTNERS Eni, Pertamina & Saka ▪ Jangkrik
OPERATOR ▪ The Jangkrik and Jangkrik North East fields are part of the Muara Bakau production- Eni sharing contract. This covers over 1,000 km² of the eastern part of the Kutei Basin. ▪ Jangkrik supplies the local domestic market as well as the LNG export market. It makes a Indonesian production significant contribution to Indonesia’s growing LNG energy requirements. Daily average production ▪ East Sepinggan & East Ganal PSC. ▪ Neptune has acquired a 20 per cent working interest in the East Sepinggan PSC and a 30 per cent working interest in the East Ganal PSC 2019 production (kboepd) ▪ The East Sepinggan PSC offers the fast-tracked, low-cost Merakes development, which is expected onstream in mid-2021 ▪ The East Ganal PSC provides longer-term exploration prospects in the prolific Kutei basin. Gas production 3.1 ▪ West Ganal ▪ Neptune Energy and its partners, Eni (Op) and Pertamina, were awarded the West Ganal production sharing contract (PSC) in August 2019 LNG production 15.8 ▪ The block includes the Maha discovery with in place gas resources in excess of 600 Bscf.
▪ Indonesia offers Neptune short-term growth and long-term potential for further discoveries and tie- Liquid production 0.6 backs to existing infrastructure
Total production 19.5
37 TOUAT, ALGERIA
PARTNERS FIELD FACTS Groupement Touat Gaz consisting of Neptune ▪ Touat represents a $2 billion investment in Algeria and a 30+ year commitment to its Energy Touat (65%) and safe operation. Sonatrach (35%). ▪ First gas commenced in September 2019. (Within Neptune Energy Touat, ENGIE holds 46% and Neptune 54%) ▪ 75 kboepd gross production through 10-year plateau period OPERATOR Groupement Touat Gaz ▪ Net 2P reserves of 72 mmboe of natural gas and condensate.
Production ▪ The project consists of production wells, pipeline infrastructure, and a central processing Conventional onshore facility, with an export pipeline into the Algeria gathering system.
▪ Phase II of the project will involve work on the remaining 8 gas fields to enable us to maintain plateau at 450 MMSCFD.
38 NETHERLANDS
OPERATOR KEY FACTS Neptune Energy Netherlands has 42 licenses and contributes to 15 per cent of ▪ Neptune is the largest offshore operator in the Dutch sector of the North Sea. total Group production ▪ Neptune operates 26 production licences and maintains a large infrastructure of 32 Netherlands production offshore facilities including four major treatment hubs. Daily average production ▪ 28 operating offshore facilities controlled onshore, 24 hours a day, with production, equipment and managing gas delivering gas contracts monitored. 2019 production (kboepd) ▪ Contributed over US$190 million in EBITDA in 2019.
Gas production 19.9 ▪ In 2019, the Netherlands assets made up six per cent of the Group’s total 2P reserves.
▪ In 2019 Neptune were selected to participate in a pioneering pilot project to create the Liquid production 1.8 first offshore hydrogen plant in the Dutch sector of the North Sea utilising platform Q13a
Total production 21.7
39 GERMANY
OPERATOR KEY FACTS Neptune Energy operates 30 of 42 producing assets ▪ More than 130 years of tradition and experience in the German E&P market. Germany production Daily average production ▪ Stable (mainly onshore) production with a natural decline of around 10 per cent.
▪ Neptune both operate (30 of the 42 producing assets) and work with operating partners (88 of the 117 exploration licences) at some of the most productive fields in Germany.
2019 production (kboepd) ▪ The portfolio is spread broadly across Western, Central and Eastern Germany as well as the Rhine Valley.
Gas production 6.9 ▪ The portfolio accounts for around eight per cent of Neptune’s business.
▪ In 2019 Neptune acquired interests in the Emsland and Grafschaft Bentheim region Liquid production 5.7 adding 600 boed and strengthening our presence in the region.
Total production 12.6
40 BONAPARTE, AUSTRALIA
PARTNERS FIELD FACTS Petrel – Neptune Energy (54%), Santos (40.25%), ▪ Petrel is a large gas field located in the Bonaparte Basin in the Timor Sea, one of the Beach Energy (5.75%) main gas-producing regions in Australia.
OPERATOR ▪ Neptune Energy and its partners are investigating a number of alternative development Neptune Energy concepts, such as a direct pipeline to Darwin. Bonaparte production ▪ Darwin hosts significant LNG infrastructure, it has a gas-fired power station and a Projected first gas TBC pipeline is already in place to connect the Northern Territory markets on the east coast.
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