Investor Call – 6th September 2018

Neptune Energy – H1 2018 Results

2

General & 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 presentation 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. Equivalent data for Neptune for the corresponding reporting period ended 30 June 2017, starting when the Company

was incorporated on 22 March 2017, are generally not informative, as the Company had minimal activity at the time, principally comprising only minor

administration expenses. Therefore, in respect of certain measures, including production, EBITDAX and capital expenditure, we have provided additional

approximate pro forma information relating to the acquired EPI business, to enable a comparison of the results for the full six months ended 30 June

2018 (including the period prior to our acquisition on 15 February) with those for the six months ended 30 June 2017.

In this presentation, 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.

The discussion in this presentation 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

presentation speak only as of the date of such statement or the date of this presentation.

Unless otherwise indicated, all production figures are presented on a net entitlement basis. Where gross amounts are indicated, they are presented on a

total basis—i.e., the actual interest of the relevant license holder in the relevant fields and license areas without deduction for the economic interest of our

commercial partners, taxes or royalty interests or otherwise. This presentation presents certain production and reserves related information on an

“equivalency” basis. Our conversion of oil and gas data into barrels of oil equivalent may differ from that data used by other companies.

This presentation 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.

3

Outline

Introduction Sam Laidlaw – Executive Chairman

Operations Jim House – CEO

Finance Peter Thomas – CFO

Portfolio & Summary Sam Laidlaw – Executive Chairman

Highlights Jim House – CEO

4

IntroductionStrong start to 2018

Production

Cash Flow

Sustainable

Growth

Organisation

and Systems

First half production above pre-closing expectations

Strong cash flow generation; $487 mm pre-EPI acquisition costs

Development projects proceeding; announced two ‘bolt-on’ transactions

Significant capacity build

Safety Steady improvements

5

HighlightsConsolidated results since acquisition of EPI on 15th Feb 2018

Operations

HSSE culture and performance improving

Strong production performance, averaging 165.6 kboepd production(1)

Progressed developments across portfolio and successfully appraised Sigrun in Norway

Strengthened business through key senior management appointments and improved processes

Finance

Portfolio &

Summary

$0.74 bn EBITDAX for period to 30 June 2018 and $0.94 bn for full H1 2018(2)

$598 mm operating cash flow (post-tax)(3) and operating costs of $10.0 /boe vs. $10.5 /boe in 2017

Successful inaugural $550 mm bond issue and long term issuer credit ratings of BB- and Ba3

0.65x net debt to EBITDAX(4)

VNG Norge – agreement to acquire oil-weighted assets with operated growth and synergies in Norway

Seagull & Isabella – agreement to acquire low-cost, near-term development and high impact exploration in UK

Full year production in line with previous guidance

H2 focus on operational efficiency, further strengthening the organisation, cost reductions, integration of VNG

and driving forward our developments

1. For the post-acquisition period, 15 February 2018 to 30 June 2018, calculated over

136 days in order to provide data comparable with other periods. Production for the

six months to 30 June 2018 for EPI was 166.1 kboepd

1.

2. Pro forma for EPI acquisition, compared with $709 mm for the first 6 months of 2017

3. Adjusted for EPI acquisition-related expenses

4. 12 month pro forma EBITDAX

6

OperationsJim House - CEO

7

80.2 78.7 77.2

33.629.8 30.1

18.820.1 20.6

13.313.0 13.0

7.224.5 24.7

91.6 86.8 87.4

12.233.5 33.5

49.3

45.8 44.7

0

20

40

60

80

100

120

140

160

180

1 2 3 4 5 6 7 8

5.6

7.5 7.6

H12017

H12018

Feb -Jun '18

5.2

7.17.3

H12017

H12018

Feb -Jun '18

51.3

69.4

69.9

H12017

H12018

Feb -Jun '18

ProductionStrong performance since EPI acquisition closed

+8%

1. Production for the six months to 30 June 2018 pro forma for EPI from 01 Jan 2018

2. Production for this period relates to the post acquisition period only, from 15 February 2018 to 30 June 2018. Average daily production is therefore calculated over 136 days, in order

to provide data comparable with other periods. Production of Neptune for 2017 was nil

3. Liquids include oil, condensate and other natural gas liquids

4. Realised other liquids (excluding oil) price of $45.4/bbl in H1 2017, $43.9/bbl in H1 2018 and $43.7/bbl in 15 Feb – 30 June 2018

Realised Gas

Price ($/mmbtu)

Realised LNG

Price ($/mmbtu)

Realised Oil

Price ($/bbl)(4)

Norway

Netherlands

UK

Germany

Outside Europe

2017 H1

Production

(kboepd)

2018 H1

Production

(kboepd)

15 Feb – 30 June

Production

(kboepd)

153.1166.1(1) 165.6(2)

Gas

LNG

Liquids(3)

+34% +37% +35%

8

Fram – 3 wells

Onstream 2019-2021

~1.5 kboepd net per well(1)

Accelerates production from field

Snohvit – Askeladd development

3 wells + option for four future wells

Onstream 2020, ~34 mmscf/d at peak(1)

Maintains Snohvit production plateau

Capital ProgrammeTargeted and disciplined capital deployment

L5a-D Sierra Njord Touat

H1 ‘18 ExplorationCara & P1

Status: Onstream

H1 2018 prod: 3.2 kboepd

Status: 43.6% complete

Onstream 2020, prod: 20.9 kboepd(1)

Status: 90% complete

Onstream H1 2019, prod: 13.9 kboepd(1)

Status: FID expected early 2019

Onstream 2021, prod: 9.6 kboepd(1)

$36.5 mm E&A expenditure(2)

2 small commercial discoveries in Dutch

sector

Successful Sigrun appraisal in Norway

Awarded four licences in Norway

2 preliminary licence awards in UK

Acquired $10.6 mm of seismic across

new acreage

H1 ‘18 Sanctioned Infills

1. Peak full year net production to Neptune

2. H1 2018 of which $13 mm was exploration capex and $10.6 mm incurred on acquisition of new seismic data in areas where we have recently been awarded new licences and to

refresh and revitalise our data library in support of new venture activity

9

OrganisationManagement and organisation progress through H1 2018

Carve out from ENGIE systems almost complete

Implemented safety culture program

Revised management organisation structure with clear accountabilities

Weekly and monthly performance and outlook reviews

Improved investment approval process

New corporate management and treasury capabilities

Name Position Previous Experience

Amanda Chilcott Group HR Director HR Director at Aggreko ; BP ; Ford

Andrea Guerra VP Corporate Reservoir Engineering Corporate Manager of Reserves & Economics Apache

Gro Haatvedt VP Exploration Exploration VP Aker BP ; Equinor

David Hemmings VP Business Development Managing Director at Rothschild & Co

Pete Jones Country Manager UK Managing Director Taqa Europe ; Marathon Oil

Philip Lafeber VP SE Asia / Africa Norway Manager at DONG Energy ; Hess Corp.

Mark Richardson VP Projects Group Projects Manager at Apache ; BP

Julian Regan-Mears Director of Corporate Affairs Group Head of External Communications at De Beers ; Centrica ; Britvic

Andreas Scheck Country Manager Germany Country Manager Wintershall

Bruce Webb VP Operations COO at DNO ; 20 years+ with BP

Strengthened existing EPI Team with additional first class E&P leadership

Transitioning organisation to standalone E&P progressing well

10

FinancePeter Thomas - CFO

11

Income Statement

6 months to June 2018 US$ mm Notes

Revenue 1,033.3165.6 kboepd production with realised oil price of $69.9 /bbl. Realised gas price of $7.6

/mmbtu and LNG price of $7.3 /mmbtu

Operating Costs (245.7) Opex /boe of $10.0 /boe (vs. $10.5 / boe for EPI for FY 2017(1))

Exploration Expense (23.0) High seismic data acquisition costs

G&A (31.1) Includes $7 mm non-recurring expenses

DD&A (276.7) Reflects fair valuation of acquired assets

Equity-accounted investments 7.6 Dutch pipeline

Operating profit / loss 464.4 Operating income, reflecting EPI business for 15 Feb – 30 June 2018

Net financial items (61.0) Net of financial expenses and income, mark-to-market on derivatives, other

Tax (269.6)Effective tax rate of 67% (79% on non-adjusted pre tax profit, reflecting acquisition

expenses)

Adjusted Net Income (adj)(2) 133.8 Reported net profit, unadjusted, $70.4 mm

Over $1 bn of revenue and net income of $134 mm

1. Opex per boe based on operating costs adjusted to exclude charge relating to over -and under-lifted production entitlement and tariff and service revenues (total $21 mm)

2. Adjusted for costs relating to the EPI acquisition of $63.4 mm

12

598 91

20487

--

100

200

300

400

500

600

700

Operating CF Investing CF Finance costs Free CF surplus

Cash Flow

1. Pro forma for EPI acquisition, compared with $709 mm for the first 6 months of 2017. Neptune H1 2018 EBITDAX, excluding EPI, was $0.74 bn

Strong CF generation

Update

Operating cash flow $598 mm

• adjusted for acquisition-related costs of $63 mm

• includes abex of $15 mm

• working capital impact of +$137 mm

Cash tax rate: 32%

Cash capex relatively low due to re-phasing and some

slippage

Touat to be reported as equity investment: no new

capital injected to JV since 15 February

$1.98 bn equity raised to cover EPI acquisition, plus

$100 mm subordinated loan. Balance from senior debt

H1 2018 Operating CF

$0.6 bn

Including:

• Development capex $80.9 mm

• E&A capex $10.2 mmUS

$ m

m

H1 2018 EBITDAX

$0.9 bn(1)

Cash Flow Summary

13

583

550

187

100 721,349 375

974

1,207

375 1,582

--

500

1,000

1,500

2,000

Drawn RBL Senior Notes TouatProjectFinance

SubordinatedNEGL Loan

DebtIssuance

Costs

Total Debt Cash Net Debt Undrawn RBL Cash Headroom

Financial PositionStrong balance sheet and robust level of liquidity

Net Debt : EBITDAX

0.65x(1)

Leverage

34%

Total Headroom

$1.58 bn

US

$ m

m

Note: Results reflect 15 Feb 2018 – 30 June 2018

1. 12 month pro forma EBITDAX

Corporate Credit Ratings

BB- (Stable) / Ba3 (Stable)

14

Hedging

Hedging update

Weighted Average Swap & Put prices (1,2,3)

1. Oil price hedges include hedges of realisations for gas production sold as LNG and pricing in relation to oil prices

2. Post tax hedge ratios adjust for different tax rates on physical sales and hedge gains and losses, which mean that effective post tax hedges can be achieved through hedging contracts

for volumes which may be significantly less than anticipated sales

3. Caps for hedged volumes under collar structures: $73-$75 / barrel for oil and >$7 /mmbtu for gas

Conservative risk management

Aggregate Post-Tax Hedge Ratios (as of 30 June 2018) (1,2,3)

Novated hedge book from ENGIE at acquisition

(MtM $53.8 mm liability). Historically based on

swaps

Continued to add hedges, using mainly option

collar structures

Hedge book comprises mostly swaps for legacy

2018 hedges and option collars for future years

RBL Facility Agreement minimum commodity

hedging requirement, on 3-year rolling basis of

forward looking post-tax production

• 50% for first year

• 30% for second year

• 15% for third year

Mark-to-market hedge book liability of $231 mm

pre-tax at 30 June reflects rising prices

26%

46%

8%

0%

73%

52%

23%

3%

2H2018 2019 2020 2021

Oil Gas

52.5

58.0

52.9

5.35.9 5.9

2H2018 2019 2020

Brent Oil Price ($/bbl) Gas Price ($/mmbtu)

15

FY Guidance

No change. FY low single-digit growth on 2017: stronger H1 performance offset by seasonal

maintenance in H2

Development capex reduced to approx. $420 mm (incl. Touat) reflecting some re-phasing;

$90 mm E&A; $35 mm abex

Plus acquisitions: $430 mm for VNG Norge and $75 mm for Seagull

Pro forma to 30 June 2018 for VNG Norge and Seagull: net debt $1.48 bn, leverage 44%

Cash flow since EPI acquisition anticipated to cover capex, bolt-on acquisitions and finance

costs, at current commodity prices

In line with previous guidance: cash tax as % of pre-tax operating cash flow reducing to below

40% due to higher Norway capex and Algerian future production

1. Excludes VNG contribution, post-closing

2. VNG transaction considered separately due to (i) short term tax cash flows (ii) debt finance contribution for longer term growth

Production

Capex

FCF

Tax Rate

16

Portfolio & SummarySam Laidlaw – Executive Chairman

17

FENJA

IVAR AASEN

BRAGE

VNG Norge ASStrategic portfolio growth in Norway

SNOHVIT

NJORD

BAUGE

HYME

GJØA

FRAM

VEGA

GUDRUN

Stavanger

Florø

DRAUGEN

Neptune Assets

VNG Assets

Neptune & VNG assets

Neptune Offices

VNG Offices

Oslo

$352 mm firm + $50 mm contingent consideration

Adds oil-weighted Norwegian portfolio with growth & synergies

42 licences, five producing fields, three development projects

Incremental 2P reserves + 2C growth of 50 mmboe net

Net production for 2017 of 4,000 boepd with significant

increase to approx. 14,000 boepd by 2022

Adds operatorship of flagship Fenja subsea project and

consolidates around Njord hub

Respected and skilled local organisation

Closing expected by year-end 2018

Significant tax synergies expected in 2019

Investment Highlights

Delivering on strategy and M&A priorities

Synergistic

bolt-ons

Extends reserve

life (R/P)

Tax synergies

Near-field,

short-payback

developments

Growth from

exploration & 2C

Operational fit

Complementary Asset Portfolio

18

Seagull & IsabellaStrategic portfolio growth in UK

$70 mm firm consideration

Leverages Neptune’s UK operational capability

Incremental 2P reserves growth of 13 mmboe net and

production growth of up to 12,000 boepd by 2022

Seagull provides attractive development economics at

moderate cost with well established export routes

Isabella is a high risk / high reward opportunity with material

upside, enhancing Neptune exploration portfolio

Accretive transaction metrics with potential for tax synergies

with existing strong UK asset base

Closing expected by year-end 2018

Investment Highlights

Delivering on strategy and M&A priorities

Synergistic

bolt-ons

Extends reserve

life (R/P)

Tax synergies

Near-field,

short-payback

developments

Growth from

exploration & 2C

SEAGULL

ISABELLA

Cygnus

Operational fit

Complementary Asset Portfolio

19

2018 H2 PrioritiesContinuing to deliver against plan

Operational Excellence

Further Strengthening

the Organisation

Integrate VNG

Drive Forward

Developments

Cost Reductions

20

Summary and Outlook

H1 production outperformance, safety improving, projects progressing

Strong cash flow generation, robust liquidity, disciplined capital allocation

Delivered two ‘bolt-on’ transactions, rebuilding exploration inventory

Production in-line and disciplined capital programme, sustained cash flow generation

Leading international independent E&P company

Operations

Finance

Portfolio

Outlook

22

Glossary

DD&ADepreciation, depletion and amortisation – reflects uplift in asset carrying values as a result of fair valuation of assets

required for purchase accounting for the EPI business combination

EBITDAX

comprises net income for the period before income tax expense, financial expenses, financial income, non-recurring

acquisition-related expenses, mark-to-market adjustments on commodity contracts exploration expense and depreciation

and amortisation

G&A General & Administrative

HSSE Healthy, Safety, Security and Environment

KboepdThousand barrels of oil equivalent. Neptune applies a scf per barrel conversion factor that varies from field to field ranging

from 4,400 to 21,050 scf per barrel

LNG Liquid Natural Gas

Operating costs

per boe

Operating costs adjusted for under-lifted entitlement to production and to offset income from tariffs and services which

serve to recover costs, divided by production in boe

RBL Reserves Based Lending

Touat Project

Finance Facility

limited recourse loan agreement between Neptune and ENGIE entered into in connection with the EPI acquisition to

finance 50% of future expenses in relation to the Touat Development Project