Full Year 2019 Results 31 MARCH 2020 GENERAL AND DISCLAIMER Except - - PowerPoint PPT Presentation

Full Year 2019 Results

31 MARCH 2020

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

• ver 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

• r financing activities.

Introduction

SAM LAIDLAW, EXECUTIVE CHAIRMAN

COVID-19 AND OIL PRICES

4

RESILIENCE PLAN IN PLACE

People

The health and safety of our people, and all those who work with us, is our number one priority – Acted quickly and have implemented our pandemic emergency plan – Working with the authorities, our partners and global health providers – Extra precautions are in place for our offshore workers – Repatriated all non-essential Neptune employees and contractor personnel from Algeria

Operations

Maintaining operational continuity, while reducing non-critical activities – No impact at our operations – Altered shift patterns; reduced non-critical activities – Stopped or reduced travel – Increased screening capability at all entry points to

• ur operations

– Continuous dialogue with our industry peers – ~$50 million of operating cost reductions (opex and G&A in 2020)

Projects

Protecting project delivery and asset values through enhanced cooperation – Reviewed our project pipeline and identified areas

• f risk – Merakes delayed until mid-2021

– Mitigation plans are in place for critical path activities – Evaluating supply chains for impacts – Focus on collaboration, cooperation and communication across projects, JV partners and suppliers – ~$250-350 million of capex reductions (~25%) in 2020

Resilience through commodity price cycles

Long-life and low-cost assets Hedged operating cash flows Strong balance sheet and liquidity Fully-funded development projects Operated assets provide control of activities

Activated our pandemic emergency plan to protect our people and assets

10 20 30 40 50 60 70 80 90 10 20 30 40 50 60 70 80 90 Brent oil price UK gas price

COMMODITY MARKETS DIVERSIFICATION, HEDGING AND LOW COST STRUCTURE TO PROTECT CASH FLOWS

36% 36% 19% 17% 27% 68% 89% 89% 90% 84% 52% 63% 54% 53% 56% Q1 Q2 Q3 Q4 FY Oil Gas Total

Low breakeven cost and hedging provides protection from weaker commodity prices

5

• 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.
• 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.

Production diversification balances our exposure to different geographies and commodity markets Our existing assets are long-life and low-cost Near-term cash flows are protected by our hedging strategy We have a strong balance sheet, cash flow generation, low leverage and significant liquidity Additional cost saving measures are being targeted Some projects may slow and expenditures deferred Disciplined approach to capital allocation, with projects screened at a range of commodity prices, including: – a low case of $25/bbl – price curves over the lifecycle of a development While leverage is expected to increase in 2020, projects coming onstream are low-cost and our capex commitments will drop

$/bbl p/therm(1)

2020 post-tax hedge ratio as at March 2020(3) Cash breakeven costs in 2020(2) Benchmark oil & gas prices

$/boe

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

EBITDAX

$3.5 Billion(9)

Operating cash flow

$2.5 Billion (9)

Generated significant earnings and cash flows over the past two years

* Our acquisition of the North Sea assets from Energean Oil & Gas is contingent on the completion

• f Energean’s transaction with Edison

Engie E&P International in 2017(1)

TRIR(2) 2P reserves Sanctioned projects(3) Production Opex Exploration potential(6) 4.9 555 mmboe 2 154 kboepd $10.5/boe 804 mmboe

Neptune Energy portfolio*

TRIR(2) Pro-forma 2P reserves(5) Sanctioned projects(3) Mid-term target production(4) Opex Exploration potential(6) 2.1 664 mmboe 9 200 kboepd $10.3/boe 2,307 mmboe Our acquisition strategy has added high quality and complementary assets in our core regions

1. The performance of Engie E&P International in 2017 2. Total Recordable Injury Rate (TRIR) 3. 2017 includes Touat and Njord; Neptune has added Duva, Gjøa P1, Fenja, Nova*, Dvalin*, Seagull, Merakes 4. Neptune production outlook following completion of project pipeline and includes Energean Oil & Gas North Sea assets 5. Pro-forma 2P reserves includes Energean Oil & Gas North Sea assets

4 material transactions(7) $1 billion invested (7) 115 mmboe 2P reserves ~60 kboepd Production(8)

6

• 6. Mean net prospective resources
• 7. Apache UK Central North Sea assets ($70m), VNG Norge ($437m), ENI Merakes interest ($235m), Energean Oil & Gas North Sea assets ($250m)*
• 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)
• 9. Cumulative EBITDAX and post-tax operating cash flows since 12 February 2018

7

GROWTH STRATEGY

• 1. Total additions in 2018 and 2019
• 2. ENI Indonesia assets and Energean Oil & Gas North Sea assets. Completion of the Energean transaction is contingent on Energean’s

transaction with Edison

Reserves

90% reserves replacement in 2019 Increasing proportion

• f developed reserves

Converted ~100 mmboe

• f contingent resources

into reserves in 2018/19(1)

M&A

Two material bolt-on acquisitions announced in 2019(2) Added >100 mmboe

• f low cost reserves

and resources(3) Strengthened acreage position in core areas

Yet to find

Increase recovery from existing assets Refreshed exploration portfolio and increased investment Continue to manage portfolio

• pportunities

CONTINUED STRONG CASH FLOW SUPPORTING DEVELOPMENT

• 3. 2P reserves and 2C resources added in 2019, including the Energean Oil & Gas North Sea assets
• 4. Illustrative production profile. Some contingent resources may not be developed and production may vary from period to period

200 kboepd 2022

2P production(4) Yet to find (4) 2C production (4)

Increasing the depth and quality of our portfolio through targeted investments

8

ENVIRONMENT, SOCIAL AND GOVERNANCE MEETING SOCIETY’S ENERGY NEEDS AND THE ENERGY TRANSITION

kg CO2/boe

18 6.0 5.8 8.0 6.0

5 10 15 20 Global industry average in 2018 2018 2019 Likely 2020 level 2030 target

(1)

Projected carbon intensity in 2030 without action

Economic impact (3)

Europe ($m)

Direct: GDP generated by

• ur operations

Indirect: spend with supply chain Induced: wage spend in the wider economy

We support the UN Sustainable Development Goals, which aim to address global challenges such as poverty, inequality and climate change Core business contributes to:

SDG 7: Affordable and clean energy SDG 8: Decent work and economic growth SDG 13: Climate action

• 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.
• 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

Creating sustainable value for our stakeholders

– Contributing to economies by creating jobs, supporting local supply chains and paying taxes – $2.8 billion gross value added(3) to the economies of Norway, the UK, the Netherlands and Germany in 2019

Setting carbon and methane intensity targets

– Targeting a carbon intensity of 6kg CO2/boe for our operated production by 2030, a reduction of 60% compared to taking no action – Our current methane intensity is 0.02% and we are targeting net zero methane emissions by 2030

Carbon intensity(2)

60% reduction in carbon intensity

Operational update

JIM HOUSE, CEO

10

FINANCIAL AND OPERATING RESULTS STRONG HSE, OPERATING AND FINANCIAL PERFORMANCE

TRIR(6) Carbon intensity(7) Socio- economic impact(8) Production(5) Production efficiency Reserves replacement ratio Opex(1) Operating cash flow(2) Capex(3) Leverage(4) Net debt to EBITDAX

FY 2019 2.1 5.8 $2.8bn 143.9 kboepd 85% 90% $10.3/boe $1,321m $826m 0.93 FY 2018 2.6 6.0 $2.6bn 161.8 kboepd 88% 244% $10.2/boe $1,219m $441m 0.62

HSE KPIs Operating KPIs Financial KPIs

• 1. Opex including royalties
• 2. Cash flow from operations, after tax and excluding acquisition costs incurred in connection with the EPI and VNG Norge transactions
• 3. Development capex, excluding acquisitions, exploration and equity accounted entities
• 4. Net debt (excluding Subordinated Neptune Energy Group Limited Loan and Touat Project finance facility) to EBITDAX (excluding our share of net income from

Touat), as defined by the RBL and shareholder agreement

• 5. Includes equity accounted entities
• 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:

TRIR = (fatalities + lost workday cases + restricted workday case + medical treatment cases)

𝑂𝑣𝑛𝑐𝑓𝑠 𝑝𝑔 ℎ𝑝𝑣𝑠𝑡 𝑥𝑝𝑠𝑙𝑓𝑒

x 1,000,000

• 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
• 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

consumption in the wider economy) to the economies of Norway, the UK, the Netherlands and Germany

11

COST REDUCTION INITIATIVES $300-400 MILLION OF COST REDUCTIONS IDENTIFIED ACROSS OPERATING COSTS, G&A AND CAPEX

– Merakes and Maha on hold until 2021 – Potential capex deferrals at Duva, Fenja and Seagull – Deferral of development drilling in the Netherlands, Germany and Egypt

Development capex Operating costs and G&A

– Reductions targeted across all our regions – Savings in logistics, maintenance and scope – Lower royalties in Germany – Reduction in vacancies and contractors – Deferment of non-critical IT projects – Reduction in travel

Exploration

– Currently reviewing our exploration plans for 2020 – Possible deferrals of drilling and seismic acquisition – G&G and new ventures savings

Financial

– No cash dividend to be paid in 2020 – All spending under review with JV partners – Portfolio management

Original 2020 budget (1)

$1,100 million

Revised 2020 plan (3)

$750-850 million $250-350 million

Cash dividend paid in 2019

$200 million

Cost reduction (2)

• 1. Original budget as approved in December 2019
• 2. Cost reduction includes targeted savings and cost deferrals
• 3. Revised 2020 plan as at 25 March 2020. Further changes to these plans are expected

Original 2020 budgets (1)

$680 million

Revised 2020 plan (3)

$630 million $50 million

Cost reduction (2)

G&A initiatives Operating cost initiatives Development capex initiatives

Original 2020 budget(1)

$145 million

PRODUCTION OUTLOOK SIGNIFICANT PROGRESS WITH 110 KBOEPD PROJECT PIPELINE

50 100 150 200 250 2019 2020 2021 2022 kboepd

New project opportunities

Glengorm(1), Isabella, Echino South, Sigrun East, Maha, Merakes East, Touat phase II, Petrel Touat and Snøhvit Nord(2)

• nstream

Askaladd (2) and Dvalin(1)

• nstream

Touat ramping up to plateau Njord Area, Fenja and Duva/Gjøa P1, Seagull, Nova(1) and Merakes

• nstream

Full year contribution from projects brought

• nstream in 2021
• 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
• 3. 2019 full year production including equity accounted entities

51% 49% 51% 21% 28% Gas Liquids Gas LNG Oil

Production by type and region(3)

82% 18% 47% 11% 15% 9% 4% 14% Non- OECD OECD UK Indonesia Germany North Africa Netherlands Norway

12 New projects Existing production

OPERATING UPDATE DELIVERING IMPROVEMENTS ACROSS THE GROUP

40 80 120 160 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

13

– Touat brought onstream in September – Shutdowns at Gjøa and Gudrun in Norway – Offtake curtailments in Indonesia – Planned shutdown at Cygnus completed ahead of plan – Fram development wells onstream – Snøhvit Nord onstream – Ongoing shutdowns in the Netherlands – Karam-10 well onstream in Egypt – Strong production in the UK, Germany and Indonesia – Unplanned shutdowns at Snøhvit – High production efficiency elsewhere in Norway – Q13a-A and L5a-D platforms shutdown in the Netherlands – Offtake curtailments in Indonesia commence – Strong production in Norway – Record production at Cygnus in May – Touat ramp-up slower than anticipated due to operational and technical start-up issues – E17a-A6 development well brought

• nstream in the Netherlands

– Fram wells performing ahead of expectations – Contribution from the Emsland oil and gas fields acquired in Germany

2019 production lower

– Plant availability generally good (85% production efficiency) – Strong reservoir performance among many of our production assets – Delayed first gas and start-up production issues at Touat – Export-system curtailments in Norway, the Netherlands, the UK and Indonesia

Improving the robustness of our business

– Improved safety, asset integrity and production availability in the Netherlands – Increased collaboration with 3rd party asset owners – Identifying alternative commercial arrangements

2019 monthly production

kboepd

Notes: Production includes equity accounted entities

152 kboepd

Q1 2019

146 kboepd

Q2 2019

131 kboepd

Q3 2019

148 kboepd

Q4 2019

14

EXPLORATION KEY SUCCESSES IN 2019 AND EARLY 2020

Isabella

Gas condensate discovery

Echino South

Oil & gas discovery

Sigrun East

Oil discovery

Neptune Energy 50%(2) Location: UK Central North Sea Neptune Energy 15% Location: Norwegian North Sea Neptune Energy 25% Location: Norwegian North Sea

P1820 partners: Total (30%, operator), Ithaca Energy (10%), Edison (10%) Gross recoverable resource estimate to be confirmed following analysis of the well results and drilling an appraisal well HPHT discovery, with hydrocarbons encountered in Upper Jurassic and Triassic sandstone reservoirs PL090 partners: Equinor (36%, operator), Exxon (25%), Idemitsu Petroleum (15%) Gross recoverable resource estimate: 38-100 mmboe Potential to commercialise, through a subsea tie-back development Drilling the Blasto prospect in 2020/21 Well partner: Equinor (75%(1), operator) PL025/PL187 partners: Equinor (36%, operator), OMV (24%), Repsol (15%) Gross recoverable resource estimate: 7-17 mmboe Potential to commercialise, along with the Sigrun discovery, through a subsea tie-back development 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 Echino South Isabella Sigrun East

17 March 2020 6 November 2019 2 March 2020

RESERVES AND CONTINGENT RESOURCES DEVELOPING OUR RESOURCE BASE THROUGH INVESTMENT AND ACQUISITIONS

78% 22% 43% 57%

Non-OECD OECD

2P reserves by region (2,3,4) 633 mmboe 302 mmboe 2C resources by region (2,5)

mmboe

90% reserves replacement ratio

(150% including Energean transaction(1))

Increased 2P reserves life to 12 years ~100 mmboe of 2C resources converted to reserves in 2yrs

15

2P reserves by region(2,3,4)

2P reserves(4) 31 Dec 2018 Production Organic additions Acquisitions 2P reserves(4) 31 Dec 2019 Additional acquisitions(1) Pro-forma 2P reserves(4)

• 1. Includes 2P reserves attributable to the Energean Oil & Gas North Sea assets and subject to the completion of the transaction
• 2. As at 31 December 2019
• 3. Our reserves are reviewed annually by an independent third party
• 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
• 5. 2C resources are defined as contingent resources with a 50% probability that the actual

quantity will equal or exceed this the estimate. We include contingent resources under the development pending, on hold and unclarified categories.

Financial results

ARMAND LUMENS, CFO

FINANCIAL HIGHLIGHTS RESULTS FOR THE YEAR ENDED 31 DECEMBER 2019

0.62 0.93

2018 2019

1,284 1,490

2018 2019

1,219 1,321

2018 2019

441 826

2018 2019

1,883 1,600

2018 2019

262 439

2018 2019

EBITDAX(1)

($m)

Leverage remains within desired levels Strong operating cash flows supporting growth Earnings robust despite lower production and softer prices

Post-tax operating cash flow(3)

($m)

Net debt(6)

($m)

Net profit

($m)

Capex(4)

($m)

Net debt to EBITDAX(1, 5, 6)

(x)

(2)

• 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

before income tax expense, financial expenses, financial income, other operating gains and losses, exploration expense and depreciation and amortisation.

• 2. Reflects the acquired EPI business from 15 February to 31 December 2018
• 3. Cash flow from operations, after tax and excluding acquisition costs incurred in connection with the EPI and VNG Norge
• 4. Development capex excluding acquisitions and exploration
• 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

assuming Neptune had owned the business from 1 January 2018

• 6. Book value net debt excluding Subordinate Neptune Energy Group Limited Loan and Touat Project finance facility as defined in RBL and shareholders agreement

(2) (2) (2)

17

KEY FINANCIALS AVERAGE REALISATIONS AND HEDGING

Hedged prices(3) 2020 2021 2022 Gas Upside cap $/mmbtu 6.6 6.7 5.5 Downside floor $/mmbtu 5.5 5.5 5.3 Oil Upside cap $/bbl 69 NA NA Downside floor $/bbl 60 NA NA

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 3. March 2020 hedged prices 4. The hedge position for 2020 at end-March reflects Q2-Q4 2020

18

– Neptune hedges post-tax operating cash flows; therefore hedged volumes are less than anticipated sales – Oil price hedges include hedges for gas production sold as LNG and priced in relation to oil prices – Balanced revenue from oil and gas mitigating exposure – Post-tax operating cash flow hedge ratio of 84% for gas in 2020 – Current hedge ratios exceed obligations under our RBL facility in 2020 – As of 31 December 2019, unrealised hedge gains equalled $183 million,

• f which $135 million relates to contracts expiring in 2020

– As of 20 March 2020, unrealised hedge gains equalled $422 million

Aggregate post-tax hedge ratio – equity case

Average realisations 2019 2018(2) Pre-hedge realisations Gas $/mmbtu 4.7 7.9 LNG(1) $/mmbtu 8.3 8.2 Oil $/bbl 62.0 69.6 Other liquids $/bbl 39.0 58.3 Post-hedge realisations Gas $/mmbtu 5.2 6.9 LNG(1) $/mmbtu 8.3 8.2 Oil $/bbl 61.5 67.5 Other liquids $/bbl 39.0 58.3 Hedge Coverage per Year 2020 2021 2022 Position at end-December 2019 Oil 27% 0% 0% Gas 84% 60% 18% Total c.56% c.26% c.7% Position at end-March 2020(4) Oil 24% 0% 0% Gas 90% 65% 49% Total c.57% c.30% c.19%

KEY FINANCIALS ROBUST EARNINGS PERFORMANCE DESPITE SOFT COMMODITY PRICES

Income statement summary ($ million)(3) 2019 2018(1) Total revenues 2,202 2,538 Cost of sales (1,159) (1,203) Exploration expenses (60) (89) G&A expenses (69) (132) Equity accounted entities 2 4 Other operating (losses)/gains (44) (69) Operating profit 873 1,049 Net finance costs (196) (143) Profit before tax 677 906 Tax (238) (645) 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%

• 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
• 3. Numbers might not equal due to rounding differences
• 4. Adjusted for deferred tax credits, current tax credits and restructuring costs

19

– Net profit higher due to lower G&A, exploration expense and taxation – Tax expense reduced by deferred tax credits recognised in the UK and current tax credits in Norway and the Netherlands – Achieved operating costs at the lower end of guidance – Reorganisation costs of $68.9 million in France, Germany and the Netherlands – Post-tax impairments of $28 million(5) in the Netherlands, the UK and Norway

Income tax reconciliation

($m)

Expected tax charge Income subject to different rates Prior year adjustment Non-tax deductible expense Pre-tax profit Other Income tax charge Deferred tax

• 5. $59.4 million on a pre-tax basis

KEY FINANCIALS STRONG OPERATING CASH FLOWS

Cash flow summary(3) ($ million) 2019 2018 Net operating cash flows 1,321 1,156 Equity accounted entities (63) (15) Development capex (826) (441) Exploration capex (62) (20) Net acquisitions (249) (3,612) Net finance costs (126) (144) Lease accounting (32) Change in debt 127 1,682 Equity issue 1,977 Dividends paid (200) (380) Net change in cash (111) 204

• 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
• 2. Development capex excluding acquisitions. Forecast are subject to change

Development capex profile(2)

441 826 750-850 2018 2019 2020 2021 2022

$m 20

– Operating cash flows fully funded our organic investment and financing costs in 2019 – Significant development capex deferrals smoothing investment across 2020 and 2021; $750-850 million development capex guidance in 2020 – Exploration spend in 2020 is under review – Cash taxes expected to be $16 million in 2020(4)

Commodity price sensitivity in 2020 (1)

• 300
• 200
• 100

100 200 300 Post-hedging Pre-hedging Post-hedging Pre-hedging

• Op. Cash Flow

EBITDAX

• 200
• 100

100 200

Oil ±$10/bbl

($)

Gas ±$1/mcf

($)

• 3. Numbers might not equal due to rounding differences
• 4. Cash taxes are sensitive to a range of factors including commodity prices, investment, production and acquisitions

KEY FINANCIALS HEADROOM FULLY FUNDS OUR INVESTMENT PLANS

• 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

$690m $850m $256m $108m $100m

Net debt position in March 2020(2) Net debt to EBITDAX projections(1)

0.62 0.93 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 2018 2019 2020 2021 2022

RBL limit Assumes $30/bbl

21

– Significant available liquidity funds project pipeline – Limited near-term debt repayment obligations – Leverage ratio is expected to remain well within RBL threshold in 2020 – Reduction in leverage as new production comes onstream – Leverage at 31 December 2019 was well within shareholder agreement and RBL thresholds – Total available liquidity of ~$1.2 billion in March 2020

Debt composition at 31 December 2019

Senior Notes Touat project finance facility Engie Vendor Loan Short-term facility RBL Assumes $40/bbl Assumes $50/bbl

x

$m

78

22

KEY FINANCIALS LEVERAGE AND DIVIDEND CONSIDERATIONS

Leverage

▪ In March 2020, the RBL borrowing base was renegotiated resulting in a new borrowing base of $2.5 billion (up from $2.0 billion). We have exercised the accordion and upsized the RBL to $2.7 billion and have delayed the first scheduled amortisation by 1 year. The final maturity date of the facility will remain the same in 2024. ▪ Available liquidity to increase to ~$1.9 billion through our undrawn RBL and cash ▪ The new RBL borrowing base now also includes Touat and Merakes. ▪ At the end of 2018 the net debt / EBITDAX ratio equalled 0.62x at the end of 2019 it equalled 0.93x. ▪ Due to our capex and the anticipated Energean acquisition profile in 2020 we expect Net Debt/EBITDAX will be around 2.0x by the end of 2020. This may vary depending on capex reductions and commodity prices. ▪ We aim to use cash flows from projects that come on-stream during 2020 and 2021 to de-lever and bring the Net Debt/EBITDAX ratio back to below 1.5x.

RBL agreement Net debt to EBITDAX ratio

23

KEY FINANCIALS DIVIDENDS

▪ No cash dividend to be paid in 2020 General dividend considerations(1) ▪ Neptune’s investment proposition is aimed at providing both yield and growth for bondholders and shareholders throughout the cycle, with capital investment allocated to exploration, development and production assets. Dividends form part of such expected shareholder returns, but as a young company with an evolving portfolio we do not have a formal dividend policy. ▪ When determining a potential dividend and the level of such dividend, the Board takes into account the following metrics: Production/Capex profile, Leverage (Net Debt/EBITDAX), total (net) debt, acquisitions or divestments, projected liquidity under different commodity price scenarios, as well as any potential impact on Credit Rating of the Company and bonds issued. ▪ Any dividend shall be sustainable in the context of allowing the company to continue to pursue its organic growth strategy and to develop its contingent resources whilst maintaining a conservative gearing ratio and retaining an appropriate liquidity position within its available credit lines. This disclosure was included in the Neptune Bond (Notes) prospectus of October 2019.

Past dividends paid

2018 $380m 2019 $200m

• 1. The Company and/or its affiliates may purchase Notes in the open market on an opportunistic basis

Outlook

SAM LAIDLAW, EXECUTIVE CHAIRMAN

Operations Growth Financial discipline

OUTLOOK

– Cost reductions of $300-400 million identified, across

• perational costs, G&A and capex programmes

– Committed to industry leading environmental targets – Delivering improvements in production efficiency – Strong reserves replacement ratio in 2019, including two 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 – Reduction in leverage ratio a priority in 2021

DELIVERING IMPORTANT PROGRESS ACROSS THE PORTFOLIO

25

Production 145-160 kboepd(1) Opex $10-11/boe Development capex $750-850 million

Guidance for 2020 2019 was a year of important strategic delivery, laying foundations for growth in reserves and production

• 1. Our production guidance is subject to unplanned shutdowns, project timing, closing the Energean transaction and the impact of COVID-19 on our operations

Resilience

– Pandemic emergency plan activated; focused on people,

• perational continuity, project delivery

– Resilience in low commodity price environment – Operator of much of our programme adds flexibility

Q&A

Upcoming events

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