H1 2019 Results 29 AUGUST 2019 GENERAL & DISCLAIMER Except as - - PowerPoint PPT Presentation

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H1 2019 Results 29 AUGUST 2019 GENERAL & DISCLAIMER Except as - - PowerPoint PPT Presentation

H1 2019 Results 29 AUGUST 2019 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


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SLIDE 1

H1 2019 Results

29 AUGUST 2019

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SLIDE 2

GENERAL & DISCLAIMER

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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 30 June 2018 therefore includes only four and a half months results contribution from the EPI business. The unaudited results for the period ended 30 June 2018 as previously disclosed have been adjusted as they were based on provisional assigned fair values of the EPI business. On completion of the business combination accounting for the year ended 31 December 2018, the associated judgements and fair values were concluded. So, the June 2018 comparative financial results and associated metrics include this position. 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

  • ur 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.

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SLIDE 3

Introduction

SAM LAIDLAW, EXECUTIVE CHAIRMAN

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SLIDE 4

SIGNIFICANT STRATEGIC PROGRESS

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DEMONSTRATING RESILIENCE AND BUILDING GROWTH Delivering current returns

  • Strong cash flow despite lower commodity price environment
  • Continued cost reduction and efficiency improvements

Delivering medium-term production growth

  • Touat gas plant fully operational, exports imminent
  • Good progress with our key operated Fenja, Duva/Gjøa P1 and Seagull developments
  • Announced acquisition of a 20% interest in the East Sepinggan PSC, with Merakes field due onstream in 2020

Creating long-term growth opportunities

  • Expanded our exploration footprint in the prolific Kutei Basin through a farm-in to the East Ganal PSC and the award of the West Ganal PSC
  • Repositioned our exploration portfolio, with licence awards in all regions of the business
  • Higher impact exploration activity set to commence, with material wells planned in Norway, the UK, Germany and Indonesia

Building resilience into the business

  • Established a diverse global portfolio of long-life and low-cost production, with a balanced exposure to commodity prices
  • Portfolio delivers resilient growth in a lower commodity price environment
  • Robust balance sheet and active hedging strategy protects the downside and enables us to capture value accretive growth opportunities

Delivering value and growth

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SLIDE 5

Operational update

JIM HOUSE, CEO

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SLIDE 6

6

FINANCIAL AND OPERATING RESULTS SOLID H1 2019 PERFORMANCE, DESPITE LOWER COMMODITY PRICES

6

  • 1. 12 month rolling average as of June 2019
  • 2. Opex includes royalties
  • 3. With the exception of TRIR, H1 2018 reflects the period from 15 February to 30 June
  • 4. Cash flow operations, after tax

Production

149 kboepd

H1 20183

166 kboepd

Opex2

$10.3/boe

H1 20183

$10.9/boe

EBITDAX

$880m

H1 20183

$767m

HSE1

TRIR5 2.08

H1 2018 3.59

Cash flow4

$613m 613m

H1 20183

$585m

  • 5. 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 work day cases + restricted work day case + medical treatment cases)

𝑂𝑣𝑛𝑐𝑓𝑠 𝑝𝑔 ℎ𝑝𝑣𝑠𝑡 𝑥𝑝𝑠𝑙𝑓𝑒

x 1,000,000

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SLIDE 7

7

DIVERSE GEOGRAPHICAL PORTFOLIO ROBUST OPERATIONAL PERFORMANCE IN Q2 2019

  • Production 0.3 kboepd higher in Q2 2019

at 72.5 kboepd vs Q1 2019

  • Strong operational performance and

production efficiency

  • Three infill wells at Fram to add

incremental production in H2

  • Production flat in Q2 at 12.5 kboepd due to

lower production efficiency

  • Acquisition from Wintershall Dea adds

approximately 600 boepd

  • Agreement builds on strategy to develop

projects in Northwest Germany

  • Q2 production down 5.5 kboepd to 20.2

kboepd due to unplanned shutdowns of L5a- D and Q13a platforms

  • Brought forward planned maintenance at

Q13 to coincide with shutdown

  • Production expected to return to plan in Q4
  • Q2 production of 16.8 kboepd higher on Q1,

reflecting strong Cygnus performance

  • Cygnus produced at record levels above 320

mmcf/d in May

  • Cygnus A5 production well online in June,

producing at around 50 mmscf/d

  • Production flat at 4.4 kboepd in Q2,

following workover and infill campaigns

  • Shorter shutdown at Bed-3, workover

campaign at Ashrafi and AESW infill well

  • Touat gas project operational (Algeria),

exports to commence imminently

  • Q2 production lower at 19.2 kboepd due to

JK off initial plateau and minor curtailments

  • Infill well drilling at JNE-9 and JKK-12, along

with workover at JKK-5

  • Signed agreement to acquire interests in

Kutei Basin and awarded West Ganal PSC

Production 9% of portfolio

GERMANY

Production 50% of portfolio

NORWAY

Production 11% of portfolio

UK

Production 14% of portfolio

NETHERLANDS

Production 3% of portfolio

NORTH AFRICA

Production 13% of portfolio

ASIA PACIFIC

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SLIDE 8

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PRODUCTION UPDATE 2019 PRODUCTION WEIGHTED TOWARDS H2

  • Lower levels of production in Q2 and Q3, but significant

increase expected in Q4 2019

  • Production from Touat to commence imminently and contribute

around 5 kboepd on a full year net entitlement basis (8 kboepd

  • n a working interest basis)
  • Three infill wells at Fram to come online in H2, adding

incremental production

  • Netherlands production to return to plan in Q4. The Q13a

platform recommenced in early August and start-up operations are currently underway at L5a-D

  • Acquisition of German interests from Wintershall Dea to add

600 boepd

  • Full year production expected to be 150-155 kboepd, with

production to exceed 170 kboepd by the end of the year

135 140 145 150 155 160 165 170 175 130 135 140 145 150 155 160 165 170 175 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019* Q4 2019*

Delivering material production growth through investment in the portfolio1 Increasing production throughout H2, with Touat reaching plateau and infill well drilling at Fram

Source: Company information

1 Forecasts subject to change and external factors

kboepd kboepd

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SLIDE 9

9

FOCUS ON MAINTAINING LOW BREAKEVEN THROUGH COST CONTROL

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Competitive breakeven costs Lower operating costs

48% 11% 17% 8% 16% $7.1 $12.3 $25.7 $11.5

  • H1 2019 Group opex of $10.3/boe, lower than H1 2018
  • Low cost production in Norway and the UK
  • Netherlands opex impacted by lower production
  • Lower opex production from Touat project to contribute in H2 2019
  • Low all in pre-tax cost of $27.2/boe
  • Initiatives underway to lower operating and G&A costs in all areas of

the business

  • Cost efficiency programmes in place Norway, the UK,

Germany and the Netherlands

  • Proposed closure of Paris office

Opex Exploration expense Net finance costs All-in costs (post-tax) G&A Tax All-in costs (pre-tax)

Capex Decom.

Forecast 2019 all-in breakeven costs ($/boe)

0.0 5.0 10.0 15.0 20.0 25.0 0% 20% 40% 60% 80% 100% UK Norway Netherlands Asia Pacific Germany North Africa 61% of production ≤$7.1/boe

H1 2019 opex per country ($/boe)

Cumulative production $6.5/boe $7.1/boe $9.7/boe1 $13.7/boe $21.5 /boe2 $13.3/boe

  • 1. Excludes the cost of C3/C4 purchases
  • 2. Excludes royalties
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SLIDE 10

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BUILDING OUR ACREAGE POSITION IN INDONESIA NEAR-TERM PRODUCTION GROWTH, WITH LONGER-TERM UPSIDE OPPORTUNITIES

  • Strategically important acquisition of net acreage in three highly

prospective PSCs

  • Transaction complements our existing acreage position and

further aligns our interests with Eni

  • Includes the low-cost developments of the Merakes and Merakes

East fields

  • Developments benefit from significant synergies due to tie-back

with Jangkrik

  • Significant exploration opportunities across the acreage with at

least two wells planned for 2020

  • Deal completion expected in Q4 2019

Addition of interests in the East Sepinggan, East Ganal and West Ganal PSCs

Building a strategic growth footprint

Jangkrik and Jangkrik NE Existing interests in the Mura Bakau and North Ganal PSCs West Ganal PSC award Merakes and Merakes East discoveries East Sepinggan and East Ganal PSCs interests acquired from ENI

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SLIDE 11

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Latest progress

Onstream Onstream Onstream Onstream

22 kboepd net 2019 2020 2021

HIGH QUALITY GROWTH PIPELINE PROJECTS TO DELIVER SOME ~100 KBOEPD FROM 2019 ONWARDS

Neptune 35%

Seagull

Neptune 22.5%

Njord

Neptune 30%

Fenja

Neptune 30%

Duva/Gjøa P1

16 kboepd net 13 kboepd net 17 kboepd net Njord project remains on track for production to recommence in late 2020. Includes recommencement of production from Hyme and first oil from the Bauge field Subsea EPCI contract awarded to TechnipFMC in July, with the offshore campaign scheduled to commence in Q2 2020 Norwegian authorities approved the development plan for the projects in June. Scheduled for drilling in early 2020 Installation of pipelines, umbilical cables, subsea templates and manifolds commenced in June

Key projects

Neptune 12%

Snøhvit satellites

Snøhvit Nord (2019 start-up) and Askeladd (2020 start-up) Neptune 20%

Merakes

East Sepinggan PSC acquired in 2019. To be developed as a tie-back to the Jangkrik FPU Neptune 35%

Touat

16 kboepd net 8 kboepd net 13 kboepd net Commissioning complete and ready to commence gas exports

Onstream Onstream Onstream Onstream

FY 2019 capex of $700 million (excluding Merakes and M&A activities) unchanged

Neptune ENI Equinor Neptune Neptune Neptune Equinor

Operator

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SLIDE 12

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INCREASING INVESTMENT IN GROWTH FIVE WELLS TO BE DRILLED IN H2 2019

Exploration

Country Project Neptune interest Timing Norway Sigrun East 25% Q3 Echino South 15% Q3 Skumnisse (Draugen step-out) 7.56% Q4 UK Isabella 50% Q4 Germany Schwegenheim 50%, operated Q3

  • Increased level of drilling activity in H2 2019
  • Results of the Darach Central-1 well drilled in the UK

Southern North Sea being analysed

  • High impact Isabella well is due to spud in October

with results expected in early 2020. Well is targeting 83 mmboe (P50 gross) in the UK Central North Sea

  • Three wells to be drilled in Norway in H2, with further

activity planned in 2020

  • Increased acreage footprint in Kutei Basin provides

material long-term growth opportunities; at least two wells planned in 2020

  • Exploration spend guidance unchanged at $125m for

2019, weighted towards H2

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SLIDE 13

Financial results

ARMAND LUMENS, CFO

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SLIDE 14

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FINANCIAL HIGHLIGHTS STRONG H1 2019 FINANCIAL PERFORMANCE

  • 1. 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
  • 2. Free cash flow defined as operating cash flow before acquisition expenses and net of development and exploration capex, investment in equity accounted entities and net interest paid
  • 3. For the twelve months ended 30 June 2019

Revenues $1,238 million

  • Neptune production of 26.9 mmboe in H1
  • Realised oil price of $62.7/bbl and dry gas sales

price of $5.5/mcf before hedging

  • Higher oil price and lower gas price during Q2

2019, compared with Q1

Post-tax operating cash flow $613million FCF(2) $179 million

  • Strong cash flow generation in the period
  • Cash flows continue to comfortably cover capex and

financing requirements

  • Net debt reduced to $1,435 million

Operating costs $277 million

  • Good progress made on cost control across the

Group

  • Opex lower at $10.3/boe for H1 2019; $10.9 in H1

2018

Total capex $352 million

  • Development capex of $335 million
  • Majority of investment in Norway as key projects

progress

  • $32m invested in Touat in the period

H1 2019 EBITDAX(1) $880 million H1 2019 EBITDA $861 million

  • Higher earnings reflecting effect of consolidating a

full half year result from the EPI acquisition

  • Depreciation and amortisation expense of

$338 million, representing $12.6/boe

Net debt to EBITDA: 0.75x EBITDAX: 0.72x

  • Financial ratios(3) remain well within desired levels

‒ Shareholder agreement: <1.5x net debt to EBITDA ‒ RBL requirement: <3.5x net debt to EBITDAX

  • >$1.3 bn of available liquidity

Pre-tax profit $385 million Net income after tax $116 million

  • Improved earnings compared to H1 2018
  • 70% tax rate in the period

Hedged position 2019 Oil 53% Gas 64%

  • 2019 FY: Oil has been hedged with an average

downside floor of $61/bbl and a capped upside of $75/bbl

  • 2019 FY: Gas has been hedged with an average floor

price of $5.7/mmbtu and an upside cap of $7.1/mmbtu

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SLIDE 15

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COMMODITY PRICES IN H1 2019 REALISED OIL AND GAS PRICES REFLECT SOFTER COMMODITY PRICES

15

Realised LNG price1 ($/mcf) Realised oil price ($/bbl) Realised gas price ($/mcf)

  • 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. From 15 February to 31 December 2018
  • 3. Benchmark prices for illustrative purposes only

Brent crude price average3 FY 20182 $72.3/bbl H1 2019 $66.2/bbl TTF price average3 FY 20182 $8.1/mcf H1 2019 $5.2/mcf Japan-Korea marker price average3 FY 20182 $9.3/mcf H1 2019 $5.7/mcf

Neptune’s realised prices

69.6 62.7 67.5 61.6 F Y 2018 H 1 2019

Pre-hedging Post hedging

7.9 5.5 6.9 5.8 F Y 2018 H 1 2019

Pre-hedging Post hedging

8.2 8.6 F Y 2018 H 1 2019

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SLIDE 16

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COMMODITY PRICE SENSITIVITY HEDGING PROGRAMME PROTECTS DOWNSIDE, WHILE PRESERVING UPSIDE

Operating cash flow sensitivity Diverse production and commodity exposure

  • While gas accounts for 71% of production, oil-linked products

lower our exposure to gas prices to around 54% by volumes and 39% by Group revenues

  • On a post tax basis, we have hedged approximately 64% of gas

volumes and 53% of oil volumes for the remainder of 20192

  • This protects 59% of Group post tax volumes
  • Our diverse production and hedging activity reduces our cash

exposure to gas price weakness

  • Exposure to oil price movements is approximately 3x higher

than for gas

Source: Company information

  • 1. Analysis uses the following base prices: Brent $65/bbl, NBP 40p/th, TTF €15.5/MWh, gas $5.0/mcf
  • 2. As at 30 June 2019

52% 19% 20% 9% Product split Gas Oil NGL LNG 71% 29% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Production Oil Gas 54% 46% Commodity price exposure Gas Oil 39% 61% Revenue by commodity Gas Oil 38% 21% 22% 19% Post tax hedging

H2 2019 post-tax operating cash flow sensitivity to a $10/bbl change in oil and/or a 15% change in gas prices1

Unhedged volumes 41% Hedged volumes 59%

  • 150
  • 100
  • 50

50 100 150 Gas Oil Oil & Gas $m

Production

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SLIDE 17

KEY FINANCIALS

  • Revenues of $1,238 million, up $171 million
  • n H1 2018
  • Operating costs per barrel lower at

$10.3/boe

  • Depreciation and amortisation expense

broadly unchanged at $12.6/boe

  • Exploration expense of $19 million reflects

costs incurred on geological and geophysical activities

  • Tax charge of 70% of pre-tax income
  • Effective tax rate of 62%

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H1 2019 EARNINGS

H1 2019 Total revenues 1,238 Operating costs (277) DD&A (338) Exploration expense (19) G&A (43) Other (38) Operating profit 523 Other (35) Net financial items (103) Profit before tax 385 Tax (269) Reported net income 116 EBITDA 861 EBITDAX 880

Consolidated income statement ($m) Commentary EBITDAX Net income

$m $m

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KEY FINANCIALS

  • Operating cash flows of $613 million after

cash taxes of $190 million

  • Cash capex before acquisitions of $352

million includes:

  • Development capex $335 million
  • Exploration capex of $17 million
  • FY 2019 capex guidance of $700m
  • unchanged. Excludes Merakes and

acquisitions.

  • Free cash flow after financing costs remains

strong at $179 million

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H1 2019 CASH FLOW

H1 2019 EBITDA 861 Cash taxes (190) Change in WC and other items (58) Cash flows from operations 613 Exploration capex (17) Development capex (335) Investments in equity accounted entities (32) Other 13 Cash flows from investment (371) Change in debt (230) Lease accounting (10) Interest paid (52) Cash flows from financing (292) Net change in cash (50) Cash at end of period 147 Free cash Flow after financing costs 179

Consolidated cash flow statement ($m) Commentary Operating cash flow Capex

$m $m 140 352 50 100 150 200 250 300 350 400 H1 2018 H1 2019

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SLIDE 19

KEY FINANCIALS

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H1 2019 BALANCE SHEET

Source: Company information

  • 1. Book value of total debt

H1 2019 Goodwill

657

PPE and intangibles

4,133

Investments in JVs

567

Other

674

Non-current assets

6,031

Trade and other receivables

632

Cash

147

Other

162

Current assets

941

Total assets

6,972

Equity

1,879

Long-term borrowings

1,581

Provisions

1,681

Other

918

Non-current liabilities

4,180

Trade payables

238

Taxes payable

250

Other

425

Current liabilities

913

Total liabilities

5,093

Net assets

1,879

Consolidated balance sheet ($m) Commentary Debt breakdown

$m

  • Net debt at the end of the period of

$1,435 million

  • Total debt(1) of $1,581 million
  • $750 million drawn under Reserve Base Lending facility
  • $550 million senior notes
  • $111 million Engie Vendor Loan Note
  • $233 million project financing facility for Touat
  • Available liquidity of $1,324 million
  • Cash at end of the period of $147 million
  • $1,177 million undrawn headroom under RBL
  • 79% debt portfolio was fixed rate at

30 June 2019

  • Average weighted cost of borrowing 5.8%
  • Net debt to EBITDA of 0.75x
  • Net debt to EBITDAX of 0.72x

RBL, $750m Senior Secured Notes, $550m Touat, $233m Engie Vendor Loan, $111m 0.84 0.64 0.72 0.00 0.20 0.40 0.60 0.80 1.00 FY 2018 Q1 2019 H1 2019

Net debt to EBITDAX

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SLIDE 20

20

FINANCIAL POSITION SIGNIFICANT AVAILABLE LIQUIDITY

750 550 233 111 63 1,581 147 1,435 1,177 147 1,324 613 384 50 179

  • 500

1,000 1,500 2,000 Drawn RBL Senior Notes Touat Project Finance Engie Vendor Loan B Debt Issuance Costs Total Debt Cash Net Debt Undrawn RBL Cash Headroom Operating CF Investing CF Finance & Other costs Free CF surplus $m

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SLIDE 21

OUTLOOK

SAM LAIDLAW, EXECUTIVE CHAIRMAN

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SLIDE 22

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NEAR-TERM PRODUCTION INCREASE, LONG-TERM GROWTH OPPORTUNITIES

  • Re-energising exploration portfolio ahead of higher impact drilling activity
  • Long-life, low-cost portfolio development – greater access to global markets

and commodity prices

  • Near-term production increase and long-term growth opportunities
  • Robust balance sheet, strong cash flow and significant headroom to support

growth organically or through acquisition

Touat gas facility, Algeria

FY 2019 guidance

  • Production weighted towards H2, with FY guidance of 150-155 kboepd. Expect

to exit the year at near record high production, exceeding 170 kboepd

  • Continued project development and exploration progress, driving medium and

long-term production growth

  • Opex guidance unchanged at $10-11/boe. Cost savings coming through
  • FY capex unchanged at $700 million, before impact of M&A activities

Strategy

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SLIDE 23

Q&A

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