EnQuest 2018

Full Year Results

Amjad Bseisu

Chief Executive

Overview Amjad Bseisu, CEO

Operations overview Bob Davenport,

Managing Director - North Sea

Kraken subsurface Martin Mentiply,

Chief Petroleum Engineer

Financials Jonathan Swinney, CFO

Summary Amjad Bseisu, CEO

Agenda

EnQuestA clear strategy with a focused business model

3

Strategic vision

To be the operator of choice for maturing and underdeveloped hydrocarbon assets

Focused business model

A production and development led E&P business

Utilises EnQuest core strengths

Strategically aligned

Value-accretive portfolio opportunities continue

to be assessed

EnQuest priorities“Deliver, de-lever, grow”

4

Deliver

De-lever

Grow

Production

Cost control

Capital discipline

Scheduled bank amortisation

Targeting net debt:EBITDA ratio of 1-2x

Develop asset base

Consider selective, value enhancing acquisitions

EnQuest 2018 performanceOperational and financial targets met

5

Deliver

✔

37,405

55,447

20,000

30,000

40,000

50,000

60,000

2017 2018

Net production (Boepd)

26

23

20

22

24

26

2017 2018

Unit opex ($/boe)

368

220

0

100

200

300

400

2017 2018

Cash capex ($m)

Strong safety performance

Acquired remaining 75% interest in Magnus

Production increased 48% to 55,447 Boepd

Unit opex decreased by 10% to $23/boe, lower than guidance

Cash capital expenditure was $220m, lower than guidance

EnQuest 2018 performanceDebt reduction on track

6

De-lever

✔

75% Magnus acquisition brings significant cash generation

Gross bank debt lower by $340 million

Group net debt: $1,774 million; 11% lower vs 2017

1.7

3.33.8

6.6

2.5

0

1

2

3

4

5

6

7

2014 2015 2016 2017 2018

Net debt:EBITDA ratio

EnQuest 2018 performanceMagnus acquisition provides growth and portfolio balance

7

Grow

✔Material increase in production

Significant 2P and 2C resource additions

203 215 210245

146 151 164

198

0

50

100

150

200

250

300

350

400

450

500

31 Dec 2015 31 Dec 2016 31 Dec 2017 31 Dec 2018

Reserves and resources (MMboe)

2P 2C

21,263 18,88515,627

19,293

6,242 11,718

8,131 6,353

4,709

21,369

9,062 9,148

8,938

8,432

0

10,000

20,000

30,000

40,000

50,000

60,000

2015 2016 2017 2018

Net production (Boepd)

NNS CNS Kraken Malaysia

Operations overview

Bob Davenport

Managing Director - North Sea

9

Production performanceGrowth of 48%, in line with guidance

15,627

8,131

4,709

8,938

19,293

6,353

21,369

8,432

NNS CNS Kraken Malaysia

2017 2018

9

2018: 55,447 Boepd1

2017: 37,405 Boepd1Production growth:

✔ Delivered

Full year contribution from

Kraken and Magnus

Drilling at Heather, Magnus and

Seligi

Alma/Galia ESP replacements

Magnus wellwork and plant de-

bottlenecking

Strong production efficiency

1 Net working interest

10

Malaysia

PM8/Seligi

Tanjong Baram

Drilled 2 wells at PM8/Seligi; delivered target

production volumes

PM8/Seligi: idle well restoration and compression

train rejuvenation campaigns

Excellent production efficiency

2018 operational deliverySuccessful drilling in Malaysia; ESP replacements at Alma

Central

North Sea

Scolty/Crathes

Alma/Galia

Kittiwake

Alba

Maintained high production efficiency

Kittiwake: extended shutdown to install new

compressor

Alma/Galia: 3 ESP replacements

Scolty/Crathes: effective wax management;

replacement pipeline on schedule for Q3 2019

8,938 8,432

2017 2018

Net production (Boepd)

8,131

6,353

2017 2018

Net production (Boepd)

11

Northern

North Sea

Magnus

Heather/Broom

Thistle/Deveron

The Dons

Maintained high production and injection efficiency

Magnus: drilling, well interventions and plant

de-bottlenecking

Heather: strong H-67 well performance

Well abandonments at Heather and Thistle

Reduced SVT costs by 25%: efficient project

execution & focused supply chain management

2018 operational delivery cont.Magnus and Kraken drive production growth

Kraken

Production lower from FPSO system and weather

related outages

Positive reservoir and well performance; good well

connectivity

Increased daily water injection to 145,000 Bwipd;

improving reservoir voidage

Completed DC3; commenced DC4 drilling

Optimised 3-well DC4 programme, saved

$23 million

15,627

19,293

2017 2018

Net production (Boepd)

4,709

21,369

2017 2018

Net production (Boepd)

12

MagnusUnlocking production and reserve growth potential

Magnus

A giant field with c.2.0 billion boe HIIP and

significant remaining potential

Secured early wins

Production increased >20% in first year

Plant de-bottlenecking increased water

handling capacity by 40 Mbwpd

Drilled 2 wells; barrel-adding well

interventions

Improved reservoir understanding

Incorporated recent seismic into reservoir

simulation modelling

Reservoir surveillance

Unlocking future potential

Improved reservoir management

Drilling and well intervention

Higher operating efficiency

13

Kraken

Multiple areas improved since first oil

Water injection system including seawater

filters

Power load management

Steam and heating systems

Separation stability

Fuel gas availability

FPSO uptime has been poor; improvement

focused on three main areas:

Main power engines

HSP seal failures

Rundown cooler systems

Working with the FPSO operator on

improvement initiatives

Kraken Improve FPSO performance; realise long-term value

Kraken Field Development

Kraken subsurface

Martin Mentiply

Chief Petroleum Engineer

Kraken field water cut evolutionField data indicates effective reservoir sweep

15

Voidage recovery through water flood provides

the primary approach to maximising reserves

80% of the field volumes are now at voidage

Positive water cut trend

3 water cut trends have been observed

Coning: drove early rapid rise in water cut

Preferential channeling through underlying

water

Effective sweep and displacement efficiency

between producer/injector pairs

Tracers breakthrough times later than

anticipated; indicating effective lateral sweep

Coning

Channelling

Alternative potential water pathways

Water cut trend

Coning Channelling Efficient sweep

Lateral sweepWater injector

Kraken reservesLife of field reserves substantially unchanged

16

Field-wide STOIIP and reservoir properties remain

largely unchanged since FDP

High-quality seismic

Extensive drilling completed

Confirmed pressure communication

Injection and producer well performance is better than

anticipated since FDP submission

Positive producer/injector communication response at

DC4

Comprehensive suite of production and subsurface data

incorporated into reservoir model; used to predict field

performance

Excellent match to oil and water rates achieved;

supports long term production forecasts

Kraken life of field reserves are substantially unchanged

Further opportunities in Western Flank

Kraken well locations

Jonathan Swinney

Chief Financial Officer

Financial review

18

1 Including losses of $93.0 million (2017: loss of $20.6 million) associated with EnQuest’s oil price hedges2 EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back

depletion, depreciation, foreign exchange movements, inventory revaluation and the realised gains/loss on foreign currency and derivatives related to capital

expenditure3 Includes PIK

Unless otherwise stated all figures are before exceptional items and depletion of fair value uplift and are in US Dollars

Results summaryStrong 2018 performance

Production

55,447 Boepd

48%

Revenue1

$1,201 million

89%

EBITDA2

$716 million

136%

Cash generated by

operations

$789 million

141%

Cash capex

$220 million

40%

Net debt3

$1,774 million

11%

Operational and financial targets met

Debt reduction underway

Deliver

De-lever

Unit opex

$23/boe

10%

Net financing costs

$233 million

59%

302

794

210

203

50

50

(20)

200

300

400

500

600

700

800

900

2017 Price Volume,margin & mix

Other cashgen by ops

Thistle option Decom, Taxand other

2018

Net cash flow from operating activities

19

$m

Cash flowStrong cash generation

Improved cash generation:

✔ Delivered

Favourable prices

Material increase in volumes

Improved asset mix

Thistle decommissioning

option

Favourable working capital

252

35

76

3 2

121

53

2419

3

0

50

100

150

200

250

300

Kraken NNS CNS Malaysia Other

2018 vs 2017 cash capex

2017 2018

$m

20

Capital disciplineMaterially lower capex requirement post Kraken development

2018: $220m

2017: $368m

1,058

751

609

368

220

275

0

200

400

600

800

1,000

1,200

2014 2015 2016 2017 2018 2019Outlook

Cash capex trend$m

Phasing &

deferrals

2018 cash capex:

✔ Delivered

Focused on drilling at Kraken,

Magnus, Heather and

PM8/Seligi

Capex outlook:

✔ Underpins production

Kraken, Magnus and

PM8/Seligi drilling

UK North Sea pipeline projects

Includes prior period deferrals

1,991

1,774

220

320 37

794

1,000

1,100

1,200

1,300

1,400

1,500

1,600

1,700

1,800

1,900

2,000

2,100

2,200

Opening net debt Net CF from ops Cash capex Net financing& other

Capitalised int.& Fx

Closing net debt

Movement in net debt

21

$m

Net debt and cash flowImproved cash generation facilitating debt reduction

Debt reduction:

✔ Delivered

Strong cash flow from

operations

Offset by

Production enhancing capex

Higher financing costs

Kraken lease

Vendor loan

Net interest paid

Capitalised interest

967

1,548

1,797

1,991

1,774

1.7

3.3

3.8

6.6

2.5

0

1

2

3

4

5

6

7

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2014 2015 2016 2017 2018

Net debt metrics

Net debt Net debt:EBITDA

$m

22

Deleveraging remains a priorityPortfolio cash generation underpinned by hedges

Ratio ✔ De-levering underway

End of high capex phase

Production volumes increasing

from improved portfolio mix

✔ 2019 outlook1

c.8 MMbbls hedged (c.6.5 at

avg floor price of c.$66/bbl)

EBITDA increases c.$150

million at $70/bbl vs $60/bbl

✔ Net debt:EBITDA

Approaching 2x in 2019

Intend to operate between

1-2x

1 Based on mid-point of 2019 production guidance of 63,000 to 70,000 Boepd

205 155

439

965

25

32

0

500

1,000

1,500

2,000

2019 2020 2021 2022 2023

5-year repayment profile1

Credit facility Bonds Other loans

23

Debt structureLong-dated, manageable repayment structure

874 799

965 965

179 179

72 72

0

500

1,000

1,500

2,000

2,500

Facilities Drawn

Debt structure1

Credit facility Bonds Oz Mgt Other loans

$m $m

1 As at 31 December 2018. Includes PIK on the Bonds ($117.6 million) and bank debt ($14.4 million), along with capitalised interest on the Oz Management facility

($3.5 million)

Scheduled amortisation on credit facility with long-dated bond repayment

Oz Management facility repaid out of ring-fenced cash flow over 5 years

24

Magnus generates strong cash flow75% interest cash waterfall1

Free cash flow Vendor loanrepayment

EnQuestrepayment

Profit share

Cash flow waterfall pre repayment of EnQuest’s $100m consideration

Free cash flow Vendor LoanRepayment

Profit share

Cash flow waterfall post repayment of EnQuest cash consideration

50%

50%

50%

50%

1 For illustrative purposes only

Vendor loan repaid in instalments over 5 years

EnQuest cash consideration expected to be repaid in 2019

2019 profit share forecast around $60/bbl Brent

25

2019 outlookPrioritising debt reduction

Production

63,000-70,000 Boepd

20%

Cash capex

$275 million

Net debt:EBITDA

Approaching 2x

Operating expense

$600 million

Hedging

c.8 MMbbl

Oil price sensitivity

EBITDA increases

c.$150 million at

$70/bbl vs $60/bbl

Operational performance and financial discipline

Focused on debt reduction; sensitive to price

Deliver

De-lever

Production Cash capex

Operating expense Hedging

Amjad Bseisu

Chief Executive

27

2019 outlookFocused on projects that maximise cash flow

Target: 63,000-70,000 Boepd

YTD Feb: 67,700 Boepd

✔

Operational priority to

improve Kraken FPSO

uptime:

30,000 to 35,000

Bopd (gross)

guidance unchanged

Magnus performing above

expectations

Rest of portfolio in line

with plans

Production

On track

✔

Maintain low unit costs

Drilling:

Kraken DC4 complete

Magnus: 2 wells

PM8/Seligi: 2 wells

Project expenditures:

Scolty/Crathes

pipeline

Dunlin bypass

Operating costs and

capital spend

Evaluation underway

✔

Kraken: infill drilling and

Western Flank

Magnus: production

optimisation; future drilling

targets

PM8/Seligi: future drilling

and intervention; facility

upgrades

Eagle: progress to

sanction

Dons NE: potential

development options

Near-term opportunities

28

Operational growth beyond 2019Selected portfolio opportunities

Deliver 2P Reserves

Late-life asset /

life extension

Platform

drillingInfill drilling

Well

intervention

Plant

improvements

Sub-sea

tie-back

Magnus ✔ ✔ ✔ ✔ ✔

Kraken ✔ ✔ ✔

PM8/Seligi ✔ ✔ ✔

Thistle/Deveron ✔ ✔ ✔ ✔

Heather/Broom ✔ ✔ ✔ ✔

Grow 2C Resources

Late-life asset /

life extension

Platform

drillingInfill drilling

Well

intervention

Enhanced

recovery

Sub-sea

tie-back

Magnus ✔ ✔ ✔ ✔ ✔

Kraken ✔ ✔ ✔

PM8/Seligi ✔ ✔ ✔ ✔

Heather/Broom ✔ ✔ ✔ ✔

Eagle ✔

The Dons ✔ ✔ ✔ ✔

EnQuest prioritiesDebt reduction remains the priority

29

Deliver De-lever Grow

Production growth

Cost control

Capital discipline

Scheduled amortisation

Targeting net

debt:EBITDA of 1-2x

Potential for near-field,

short-cycle opportunities

Substantial 2C resources

EnQuestA clear strategy with a focused business model

30

Questions & Answers

Appendices

0

10000

20000

30000

40000

50000

60000

70000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

* Guidance range for 2019 is an average of between 63,000 Boepd and 70,000 Boepd

Average net production (Boepd)

63

,00

0 -

70

,00

0*

32

Well set for substantial growthStrong CAGR (c.17.2% to 2019 mid-point)

Q&A

33

No material cash tax expected to be paid on UK operation activities for the foreseeable

future - UK corporate tax payable in financial statements mainly relate to profits

generated by Magnus assets pre-completion of acquisition of remaining 75% on 1

December 2018;

Small cash tax payments are expected in Malaysia on the PM8/Seligi PSC

UK Tax Allowances $m

Tax losses at 31 December 2017 3,121.3

2018 net additions plus RFES 42.8

Prior year true up (38.8)

Tax losses at 31 December 2018 3,125.3

Tax allowances carried forward 100.0

Total tax losses and allowances at 31 December 2018 3,225.3

Group tax positionNo material UK cash CT/SCT on operational activities expected

34

ETR % $m’s

Loss Before Tax 94.0

UK CT Rate 40% 37.6

RFES 68% (64.2)

UK and overseas tax rate differences 22% 20.3

Permanent items (23%) (21.7)

Prior year adjustments (2%) (1.4)

Other 4% (3.8)

2018 Tax Charge/(Credit) (35%) (33.3)

Group tax positionEffective tax rate reconciliation

35

Post-tax exceptional itemsYear to 31 December 2018

$49.1 million post-tax gain on exceptionals, primarily made up of:

Net uplift associated with the 25% interest ‘step-acquisition’ of $74.3 million, comprising

$123.9 million associated with PP&E; partially offset by

$49.6 million deferred tax liability

Post-tax unrealised gain on commodity derivatives of $59.9 million

Post-tax impairment of oil and gas assets $78.7million

36

The Dons

Heather/Broom

Greater Kittiwake Area

Thistle/Deveron

Kraken

PM8/Seligi

Alma/Galia

Magnus

EnQuest: 8 HubsA strong platform for growth

81

245263

(99)

-50

0

50

100

150

200

250

300

Net 2P reservesstart 2010

Production 2010-2018

Reserve additions2010-2018

Net 2P reservesend 2018

MMboe Net 2P Reserves

37

Strong reserves growth in first nine yearsReserve life c. 13 years

This presentation may contain certain forward-looking statements with respect to EnQuest’s

expectation and plans, strategy, management’s objectives, future performance, production,

costs, revenues, reserves and other trend information. These statements and forecasts

involve risk and uncertainty because they relate to events and depend upon circumstances

that may occur in the future. There are a number of factors which could cause actual results

or developments to differ materially from those expressed or implied by these

forward-looking statements and forecasts. The statements have been made with reference

to forecast price changes, economic conditions and the current regulatory environment.

Nothing in this presentation should be construed as a profit forecast. Past share

performance cannot be relied on as a guide to future performance.

Forward-looking statements