Q1 2020 Results 27 MAY 2020 GENERAL AND DISCLAIMER Except as the - - PowerPoint PPT Presentation

Q1 2020 Results

27 MAY 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. 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

• perating 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

SAM LAIDLAW, EXECUTIVE CHAIRMAN

SAFETY PARAMOUNT

4

People and operations

Strong Q1 operational performance, despite challenges of COVID-19 and lower commodity prices – Materially higher quarterly production – Limited impact from COVID-19 on our operations – Programmes in place to support employees, contractors, suppliers and local communities

Projects

New project schedules in response to COVID-19 and lower commodity prices – Some project delays related to COVID-19; 2020 capex reduced as a result of deferred activity – New project schedules lower production outlook in 2021 and 2022 – Agreed to terminate the acquisition of Edison E&P’s UK and Norwegian subsidiaries saving ~$460 million in 2020

Cost reductions

Good progress delivering cost and capex reduction measures; targeting $300-400 million in 2020 – Realised a significant proportion of cost reductions – Identifying further potential reductions in both capex and opex – Managing value over volume ▪ Strengthened liquidity to ~$1.7 billion through increase in RBL borrowing base ▪ Free cash flow in 2020 protected through hedging and cost reductions ▪ Lower expected leverage

Robust financial position Consistent growth profile

▪ Expect to achieve production growth from existing projects until 2023 ▪ Production shifted into higher expected price environment ▪ Targeting 200 kboepd in the medium term

RESILIENT PERFORMANCE; WITH GROWTH IN THE PORTFOLIO

Operational update

JIM HOUSE, CEO

6

FINANCIAL AND OPERATING RESULTS STRONG OPERATING AND ROBUST FINANCIAL PERFORMANCE

TRIR(1) PSER(2) Production

(3)

Production efficiency Opex(4) Operating cash flow

(5)

Capex(6) Leverage(7) Net debt to EBITDAX

Q1 2020 2.3 1.95 162.1 kboepd 86% $8.9/boe $355m $233m 0.99x Q4 2019 2.1 2.19 147.9 kboepd 85% $9.2/boe $373m $225m 0.93x Q1 2019 1.9 NR(2) 151.8 kboepd 91% $10.1/boe $362m $153m 0.50x

HSE KPIs Operating KPIs Financial KPIs

• 1. 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

• 2. Process Safety Event Rate (PSER) is a three-tiered measurement of process safety events per million hours worked. We commenced measuring PSER in April 2019.
• 3. Includes equity accounted entities
• 4. Opex including royalties
• 5. Cash flow from operations, after tax and excluding acquisition costs
• 6. Development capex, excluding acquisitions, exploration and equity accounted entities
• 7. 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

DIVERSE GEOGRAPHICAL PORTFOLIO

7

STRONG OPERATIONAL PERFORMANCE IN Q1 2020

▪ Strong production due to start-up of the Troll C Gas Module and recommencement of the Mossmoran Ethylene plant ▪ Rescheduled shutdown programme with deferrals until 2021 ▪ Reported production higher due to change in Group conversion factors; underlying performance below plan due to offtake constraints ▪ Discoveries at Schwegenheim, Ringe-6 and Adorf-Z15. Ringe-6 and Adorf-Z15 to be brought onstream in 2020 ▪ Production impacted by shutdowns and delayed compressor project; positive contribution from new wells ▪ Start-up of the cross border Sillimanite field contributing to UK and Netherlands production ▪ Strong production reflecting high export availability ▪ Material discovery at Isabella – post well studies underway, with results to be incorporated in appraisal plan Algeria ▪ Touat production higher with fewer start- up related issues; plant now operating at plateau capacity Egypt ▪ Production in Egypt ahead of plan ▪ 3D seismic acquired in Gulf of Suez Indonesia ▪ Strong production, with annual volumes front-loaded; second pipeline tie-in project completed ▪ Curtailments at the start of Q2 Australia ▪ Acquisition of 3D seismic

Q1 production: 17.3 kboepd (10.7% of portfolio)

GERMANY

Q1 production: 68.1 kboepd (42.0% of portfolio)

NORWAY

Q1 production: 19.3 kboepd (11.9% of portfolio)

UK

Q1 production: 19.2 kboepd (11.9% of portfolio)

NETHERLANDS

Q1 production: 12.7 kboepd (7.8% of portfolio)

NORTH AFRICA

Q1 production: 25.5 kboepd (15.7% of portfolio)

ASIA PACIFIC

8

NEAR-TERM PRODUCTION OUTLOOK OPTIMISING OUR SHUTDOWN SCHEDULES

162

Q1 2020 Q2 2020 Q3 2020 Q4 2020

Quarterly production outlook

kboepd – Revised shutdown schedule – Deferred extended shutdowns until 2021 – Reduction in non-critical activities – Minimise COVID-19 risks – Planned shutdowns at key assets to have a material impact on Group production volumes – Norway: Gjøa (May, July and August), Snøhvit (May) – UK: Cygnus (June/July) – Smaller impact from shutdowns in the Netherlands and Germany – Minimal reduction in production due to mandated oil cuts in Norway – Limited impact from the agreement to terminate the acquisition of Edison E&P’s UK and Norwegian subsidiaries from Energean Oil & Gas – Full year production guidance unchanged at 145-160 kboepd

Planned shutdowns to impact Group production in Q2 and Q3

FY guidance range 145-160 kboepd

HIGH QUALITY GROWTH PIPELINE

9

REVISED PROJECT SCHEDULES - NORWAY

1. Neptune has a 22.5% working interest in Njord and a 12.5% interest in the Hyme and Bauge satellites

Njord

Neptune non-op (22.5%(1)) Operator (Equinor)

2020 2021

Engineering Subsea Drilling Topside Production

Duva

Neptune op (30%)

2020 2021 2020

Fenja

Neptune op (30%)

2020 2021 2022

Gjøa P1

Neptune op (30%)

2020 2021

Engineering Subsea Drilling Topside Production

Gjøa area Njord area

– Gjøa P1 is largely unaffected with first production expected in late 2020/early 2021 – Development drilling and subsea campaigns essentially unchanged – Topside work for Duva deferred until 2021 to ensure operational continuity at Gjøa due to COVID-19 – First production from Duva deferred by four to six months – COVID-19 and a slower pace of development has delayed first production from Njord until H2 2021 – Fenja drilling plans reduced in 2020, with the main campaign to commence in mid-2021 – Subsea and topside work at Fenja delayed by around 12 months to coincide with delivery of the Njord project – First production from Fenja expected in early 2022

10

kboepd

25

kboepd

9

kboepd

7

kboepd

Original plan for first production Revised plan for first production P1 Gjøa first production plan unchanged

– Due to the impact of COVID-19, limited topside activities can be carried out in 2020 – Drilling and subsea work has been deferred until 2021/2022 to coincide with the new topside schedule – All four wells to be drilled ahead of first production – First production is likely to be deferred by 12-15 months until the fourth quarter

• f 2022; full production delayed by only 6-9 months

HIGH QUALITY GROWTH PIPELINE

10

REVISED PROJECT SCHEDULES – REST OF THE WORLD

Seagull

Neptune op (35%)

2020 2021 2022

Engineering Subsea Drilling Topside Production

Merakes

Neptune non-op (20%) Operator (ENI)

2020 2021 2022

Engineering Subsea Drilling Topside Production

UK Indonesia

– Operator declared force majeure due to COVID-19 disruptions – Protects operational integrity of the existing Jangkrik production – Activities expected to recommence in early 2021 – First production delayed by 6-9 months

15

kboepd

8

kboepd

Original plan for first production Revised plan for first production The original Seagull development plan included a ramp-up phase to full production

2019 2020 2021 2022 2023

144

MEDIUM-TERM GROWTH OUTLOOK SIGNIFICANT NEW PRODUCTION TO BE BROUGHT ONSTREAM BY 2022

Production growth from existing portfolio

kboepd Touat

• nstream

Gjøa P1

• nstream at YE,

Touat ramping up to plateau Njord, Duva and Merakes

• nstream

Full year contribution from projects brought

• nstream in

2022 11 Fenja and Seagull

• nstream

– Outlook reflects new project schedules – Lower production outlook in 2021 and 2022 – Expect to achieve production growth from existing projects until 2023 – Targeting 200 kboepd in the medium term – Asset values protected – Volumes shifted into higher expected price environment – Additional costs of deferring activity

• ffset by cost savings

Financial results

ARMAND LUMENS, CFO

355 362

Q1 2020 Q1 2019

323 451

Q1 2020 Q1 2019

47 53

Q1 2020 Q1 2019

233 153

Q1 2020 Q1 2019

FINANCIAL HIGHLIGHTS ROBUST FINANCIAL PERFORMANCE IN Q1 2020

EBITDAX(1)

($m)

Leverage remains within desired levels Strong operational cash flows, fund increased investment Robust earnings, despite softer commodity prices

Post-tax operating cash flow

($m)

Net debt(4)

($m)

Net profit

($m)

Capex(2)

($m)

Net debt to 12-month EBITDAX(1, 3, 4)

(x)

• 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. Development capex, excluding acquisitions, exploration and equity accounted entities
• 3. EBITDAX is calculated on a 12-month rolling basis
• 4. Book value net debt excluding Subordinate Neptune Energy Group Limited Loan and Touat Project finance facility as defined in RBL and shareholders agreement

13

0.99 0.50

Q1 2020 Q1 2019

1,463 1,113

Q1 2020 Q1 2019

KEY FINANCIALS HEDGING ACTIVITY PROTECTS CASH FLOWS

Hedged prices(2) 2020 2021 2022 Gas Hedged volumes(3) mmboe 11.5 10.6 7.2 Upside cap $/mmbtu 6.7 6.7 5.6 Downside floor $/mmbtu 5.5 5.6 5.5 Oil Hedged volumes(3) mmbbl 6.2 na na Upside cap $/bbl 48.5 na na Downside floor $/bbl 43.9 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. Hedged volumes and prices reflect the April to December 2020 period 3. Hedged volumes includes swaps and puts 4. Post-tax hedge ratio reflects our equity production volumes, whereas our RBL hedging obligations exclude certain volumes

14

– Significantly increased oil hedges for the remainder of 2020 – Increased volumes hedged by 3 mmbbl in March – Currently well hedged for gas, with floor prices well above spot prices – Unrealised commodity derivative gains of $420 million, of which $278 million relates to contracts expiring in 2020 – Average realisations in Q2 are expected to be lower than in Q1

Aggregate post-tax hedge ratio(4) at 31 March 2020

Average realisations Q1 2020 Q1 2019 Pre-hedge realisations Gas $/mmbtu 2.9 6.5 LNG(1) $/mmbtu 7.4 9.0 Oil $/bbl 47.1 58.5 Other liquids $/bbl 21.3 42.2 Post-hedge realisations Gas $/mmbtu 4.1 6.5 LNG(1) $/mmbtu 7.4 9.0 Oil $/bbl 49.2 57.8 Other liquids $/bbl 21.3 42.2

47% 0% 0% 90% 65% 49% 68% 29% 19%

2020 2021 2022 Oil Gas Total

KEY FINANCIALS DELIVERING A SIGNIFICANT REDUCTION IN COSTS

Income statement summary ($ million)(1) Q1 2020 Q1 2019 Total revenues 480 621 Cost of sales (291) (300) Exploration expenses (22) (8) G&A expenses (13) (41) Equity accounted entities 9 1 Other operating (losses)/gains (7) (2) Operating profit 155 271 Net finance costs (37) (65) Profit before tax 118 207 Tax (71) (154) Reported net income 47 53 Q1 2020 Q1 2019 Opex $/boe 8.9 10.1 DD&A(2) $/boe 10.5 12.5 Effective tax rate % 60% 74%

1. Numbers might not equal due to rounding differences 2. Depreciation, depletion and amortisation

15

– Net profit broadly stable despite lower revenues – Operating costs below guidance due to delivery of our cost reduction measures; FY

• pex guidance lowered to <$10/boe

– Lower G&A costs reflect cost efficiency programme and one-off R&D credits – Higher exploration write-off due to unsuccessful Grind well in Norway – Higher taxed production in Norway provides ‘natural hedge’ to commodity prices – Asset impairment review to be conducted in Q2

Operating costs

($/boe) 10.1 10.8 11.2 9.2 8.9

Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020

KEY FINANCIALS STRONG OPERATIONAL CASH FLOWS

Cash flow summary(2) ($ million) Q1 2020 Q1 2019 Net operating cash flows 355 362 Equity accounted entities (13) (15) Development capex (233) (153) Exploration capex (39) (3) Net acquisitions 1 8 Net finance costs (22) (34) Lease accounting (17) (3) Change in debt (19) (188) Net change in cash 13 (26)

• 1. Development capex excluding acquisitions. Forecast are subject to change
• 2. Numbers might not equal due to rounding differences
• 3. The reduction in investment includes acquisition costs, cash flows from the effective date and assumed capex from the completion date

Development capex profile(1)

441 826 700-800 2018 2019 2020 2021 2022

($m) 16

– Stable post-tax operating cash flows reflect lower taxes and working capital increase – Development capex expected to slow in subsequent quarters, with FY guidance reduced to $700-800 million – Exploration spend weighted towards H1 2020; $125 million expected for FY – Potential Norwegian tax amendments to be confirmed in June – Material ~$460 million(3) reduction in investment in 2020 related to the agreement to terminate the Energean transaction; partially offset by higher expected cash taxes

Q1 2020 cash flow waterfall

Post-tax

• perating

cash flow Exploration capex Development capex Equity accounted investments Reduction in debt Other Net interest Change in cash

($m)

KEY FINANCIALS STRENGTHENING OUR LIQUIDITY POSITION

• 1. As defined in our RBL agreement. EBITDAX forecasts are subject to change
• 2. The increase in the RBL borrowing base is subject to completion of the inclusion of the Touat asset
• 3. Previous guidance included $0.2 billion in the borrowing base for the proposed acquisition of Edison E&P’s UK and Norwegian assets from Energean

Oil & Gas. The RBL facility size is unaffected.

Liquidity at 31 March 2020(2) Net debt to EBITDAX projections(1)

0.62 0.93 0.99 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 2018 2019 Q1 2020 2020 2021 2022

RBL limit Assumes $30/bbl 25p/therm

17

– Finalised RBL redetermination on 15 April 2020 – Upsized facility to $2.6 billion and increased borrowing base to $2.3 billion(3) – First scheduled amortisation of $250 million delayed by 12 months to April 2022 – Includes Merakes and Touat(2) – Total committed facilities now equalling $3.5 billion – Agreement to terminate the acquisition of Edison E&P’s UK and Norwegian subsidiaries from Energean Oil & Gas enhances our expected liquidity position by $0.2 billion at YE 2020 and by $0.3 billion at YE 2021(4) – Leverage ratio forecast to increase to ~1.6x by FY 2020; significantly lower than previously guided

Debt composition at 31 March 2020

Senior Notes Touat project finance facility Engie Vendor Loan Short-term facility RBL Assumes $40/bbl 35p/therm Assumes $50/bbl 45p/therm

(x)

($Bn)

$750m $850m $261m $108m $21m

2.3 0.75 0.1 1.7

Overview

JIM HOUSE, CEO

Operations Financial discipline Q2 Outlook

OVERVIEW

– Q1 2020 production above FY guidance range – Deferred development drilling and non-critical activities – Positive results from exploration in Norway, the UK and Germany – Reduced opex, development capex and exploration guidance – Increased oil hedges for 2020 – Strengthened liquidity through upsized RBL and agreed termination of the Energean transaction – Planned shutdowns to reduce production in Q2 – Lower expected earnings and cash flows from weaker commodity prices – Further progress delivering cost reduction plan

ROBUST OPERATIONAL AND FINANCIAL PERFORMANCE

19

Production 145-160 kboepd

(unchanged)

Opex <$10/boe

(from $10-11/boe)

Development capex $700-800 million

(from $750-850 million)

Exploration $125 million

(from $145 million)

Guidance for 2020

Resilience

– Limited impact from COVID-19 on our operations – $300-400 million cost reduction measures on target – Project schedules deferred; asset values protected

Q&A