Investor meetings

July 2019

EnQuestA clear strategy with a focused business model

1

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”

2

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; debt reduction on track

3

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)

De-lever

✔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

4

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

5

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

6

$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

7

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

8

$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

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

9

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

10

Debt structureEnQuest capitalisation and enterprise value

$m 30-Apr-19

Available Drawn CHANGE Drawn Maturity Rating

Tranche A Loan1 799 799 (105) 694 USD L+475 Oct-21

Tranche B Loan 75 0 USD L+475 Oct-21

Oz Management facility1 179 179 USD L+630 Sep-23

Other loans 72 72 Various Various

Total secured debt2 1,125 1,050

USD PIK Toggle SNs (HYB)1 746 746 7.00% Apr-23 B3 / B-

GBP PIK Toggle SNs (Retail)1 219 219 7.00% Apr-23

TOTAL DEBT 2,090 2,015

Cash and cash equivalents (241) (241)

NET DEBT 1,774 (50) 1,724

Equity 984

Capitalisation 2,999

Market Capitalisation 472 460

EV 2,246 2,184

1 Includes PIK (Tranche A Loan $14m; Oz Management Facility $4m; HYB $96m; Retail Bond $21m)2 Excludes outstanding vendor loan due to BP which is secured over the Magnus asset

31-Dec-18 Interest /

Coupon

11

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

EnQuest 2019 performance and outlookYear to date April: Continued delivery and de-leveraging

12

Production up c.25% at 69,973 Boepd

Magnus and PM8/Seligi ahead of expectations

Recent Kraken performance materially improved; initiatives ongoing

Full year guidance remains unchanged

Group production of 63,000 – 70,000 Boepd (net); Kraken production of

30,000 – 35,000 Bopd (gross)

Operating costs and capital expenditure programmes on track

Net debt reduced to $1,724 million

Strong operational performance & supportive oil price more than offsets

anticipated unwind of c.$50 million end 2018 favourable working capital

April amortisation met as scheduled; drawn credit facility now $680 million

7.1 MMbbls oil hedged for remainder of 2019 to underpin cash flow

6.2 MMbbls at average floor price of $66/bbl

On track for year end net debt:EBITDA ratio below 2x1

1 Subject to the recent oil price environment continuing

Deliver

✔

De-lever

✔

2019 operational delivery to end AprilStrong performance at Magnus; pipeline projects on schedule

13

Northern

North Sea

Magnus

Heather/Broom

Thistle/Deveron

The Dons

Strong performance at Magnus

high production efficiency through reservoir

management; well interventions and plant

de-bottlenecking

future prospects under evaluation

Heather: single compressor operations

Stable production and water injection efficiency at

Thistle and the Dons

Dunlin bypass project progressing as planned

19,851

34,766

2018 2019

Net production (Boepd)

Central

North Sea

Scolty/Crathes

Alma/Galia

Kittiwake

Alba

High production efficiency and impact of 2018 ESP

replacement programme at Alma/Galia

Scolty/Crathes replacement pipeline project on

schedule for Q3 2019 completion

Evaluation of sub-sea tie-back development

options for the Eagle discovery continue 6,044 6,742

2018 2019

Net production (Boepd)

2019 operational delivery to end AprilKraken improving; PM8/Seligi programmes underway

14

Malaysia

PM8/Seligi

Tanjong Baram

Excellent production efficiency at PM8/Seligi

Idle well restoration programme ahead of

schedule; restored 5 wells to production

Asset rejuvenation activity progressing as planned

2-well programme to commence in 3Q

Future drilling targets being assessed

8,751 8,693

2018 2019

Net production (Boepd)

Kraken

Significant improvement in production in Mar/Apr

vs. Jan/Feb

Higher production efficiency: power engine

performance; plant stability; topside power

pumps and spares management

DC4 wells online; producing ahead of

expectations

Further improvement initiatives ongoing

Western flank targets being appraised

21,431 19,77

2

2018 2019

Net production (Boepd)

15

Production

63,000-70,000 Boepd

c.20%

Cash capex

30,000-35,000 Bopd

Net debt:EBITDA

Below 2x1

Operating expense

c.$600 million

Hedging

c.$275 million

Hedging

c.12.5 MMbbls for 20192

Operational performance and financial discipline

Focused on debt reduction; underpinning cash flow

Deliver

De-lever

Group production (net) Kraken production (gross)

Operating expense Cash capex

1 Subject to the recent oil price environment continuing2 For the last eight months of 2019, EnQuest has hedges in place for c.7.1 MMbbls of oil. Approximately 6.2 MMbbls are hedged at an average floor price of c.$66/bbl,

with a further c.0.9 MMbbls hedged with an average floor price of c.$56/bbl in accordance with the Oz Management facility agreement

2019 outlookOn track to meet targets; debt reduction remains the priority

Longer-term development optionsThree world-class assets: Magnus, Kraken and PM8/Seligi

16

50

38 43

68

Magnus Kraken Other UK PM8/Seligi

2C resources (MMboe) at 31/12/18

2P reserves of 245 MMbbls, an increase of 17% over 2017

Significant resource base in existing fields; delivered largely through drilling

Magnus: 75% acquisition added c.40 MMboe to year end 2C resources

Kraken: reserves remain materially unchanged; material opportunities in the Western

Flank and Maureen sands

PM/8 Seligi: drilling/intervention programmes drive 2P delivery and 2C migration

2C resources accessible through drilling with existing infrastructure

17

Magnus is one of 3 giant oil-fields in NNS;

c.2bn boe HIIP

c.50% RF; large volume of remaining mobile oil

Secured early wins: plant de-bottlenecking, drilled 2

wells; barrel-adding well interventions

Improved reservoir understanding utilising recent

seismic

Unlocking future potential through improved

reservoir management, drilling and well intervention

and higher operating efficiency

Initial drilling performance has been top quartile

MagnusA giant field

18

2C resources

2P reserves

2 low-cost, platform drilled infill wells planned in late 2019

Continuation of successful well interventions

Plant debottlenecking and improved water handling

capacity

Identified low-cost annual 2-well drilling programme with

strong economics

Further drilling upside with target maturation in progress

Production and reservoir management

Effective late-life cost management

Future upside

c.270 MMbbls of mobile oil in place; development

programme will be economic over several years

Magnus opportunitySignificant 2P reserves and 2C resources

19

DC3 Central

West

NW Area -

Barra

Central Area

Upper Storey

Pembroke

Trend

Antrim Far

West

Worcestershire

Area

Maureen

Black = existing/drilling wells Green = proposed producer

Blue = proposed injector

2C resources

2P reserves

Drilling and subsea infrastructure complete

Focus on Production Efficiency and cost management

Western Flank has c.100 MMbbls STOIIP

Worcestershire area high-graded

seismically identical to main-field area

spare producer and injector slots at DC2

11-19 MMstb STOIIP

Pembroke trend under review

potential side-track of DC2 producer and spare DC4

injector slot

c.16 MMstb STOIIP

Longer-term EOR through polymer flood

c.30MMbbls STOIIP

Future upside

20-40 MMbbls STOIIP in Maureen sands under evaluation

KrakenFDP drilling complete; upside opportunity in the Western Flank

20

2C resources

2P reserves

Low-cost annual 2-well drilling programme planned

Ongoing well intervention activities

Facility reliability programme to maintain high PE

Large opportunity hopper: additional low-cost drilling and

workovers; PM8 gas opportunity

Improved recovery through gas injection / water flood

Strong economics

Future upside

Significant potential gas development at Seligi

potential future 2C of >3.5 tcf GIIP

gas infrastructure in place; exported 100 MMscfd in

peak times over last 3 years

requires commercial agreements with PETRONAS

c.2bn boe STOIIP; 12 stacked reservoirs; c.35% RF

Historically strong production performance through well

interventions; only 2 new wells drilled

Acquisition of c.17MMboe net 2P reserves; by end 2018

further c.13 MMboe net 2P reserves added with net

production of c.10MMboe

Echo

25 Targets

Bravo

7 Targets

Hotel

0 TargetsAlpha

9 Targets

Golf

7 Targets

Foxtrot

14 Targets

Delta

18 Targets

Charlie

19 Targets

2019

Focus

Area

J18/20 Reservoir Outline with Initial Fluid Contacts

PM8/SeligiA giant field with significant upside potential

21

2C resources

EnQuest 100%

High quality Fulmar reservoir discovered in 2016

through a single exploration well

Analysis shows

reservoir with a vertical thickness of 67ft

excellent reservoir properties

no oil water contact was encountered,

representing potential upside volumes on the

flank of the structure

Development under evaluation

sub-sea tie-back to a suitable host

producer well with a resource appraisal element

robust base case economics

Cook analogue (per WoodMac)

c.62MMbbls STOIIP

80% RF to date suggesting in place volumes

larger than mapped

Sub-sea tie-back opportunitiesEagle discovery

22

Ythan - 2C resources

Don NE - 2C resources

100% EnQuest

Development concept and economics under

evaluation

single producer in an undeveloped fault

block of the former Don field

drilled from the Don SW subsea drill centre

sub-sea tie-back to the Northern Producer

FPF

EnQuest 60%

Ythan development (2015) has outperformed

FDP expectations with the initial well proving up

additional oil-in-place

Development concept and economics under

evaluation

second producer well drilled from the Don

SW subsea drill centre

sub-sea tie-back to the Northern Producer

FPF

211/13c 211/14

211/19b

211/18i

211/18b

211/18e

211/18c211/18h

211/18f

211/18g

211/19c

211/19a

18a-24

N05Z

18a-21

14-7

S9

18a-22

S5

18-15

S4Z

S3Z

18a-12

S4

S2Z

N06X

S6

S13

S15

S12S10Z

S10

S8

S2

S11

S8Z

S14

S12ZS10Y

S7

14-2Z

N04

18a-23

13a-8

14-1

14-7

N03

N02

N01

13a-8Z

N07

InjectionProduction

421200 421600 422000 422400 422800 423200 423600 424000 424400 424800 425200 425600 426000 426400 426800 427200

421200 421600 422000 422400 422800 423200 423600 424000 424400 424800 425200 425600 426000 426400 426800 427200

6812400

6812800

6813200

6813600

6814000

6814400

6814800

6815200

6815600

6816000

6816400

6816800

6817200

6817600

6818000

6818400

6818800

6819200

6819600

6820000

6820400

6820800

6821200

6821600

6812400

6812800

6813200

6813600

6814000

6814400

6814800

6815200

6815600

6816000

6816400

6816800

6817200

6817600

6818000

6818400

6818800

6819200

6819600

6820000

6820400

6820800

6821200

6821600

0 250 500 750m

1:25300

Blanked GB_WGC_SSBLU_Top_Brent_Oct_2016_Autotrack_Greater_Dons_v3_regrid_REGIONAL_VELOCITY_MODEL_TIED_CG

Dons P2137 - Accumulations and Top Brent Depth Contours June 2018

Proven Hydrocarbons

Likely Hydrocarbons

Don NE

NA

NB

Penguin E

NA

Don SW

Ythan

ND N2/3

N4

N1

Blocks Dev eloped

by BP

Sub-sea tie-back opportunitiesDon NE and Ythan near field

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

Appendices

81

245

263

(99)

0

50

100

150

200

250

300

350

400

Net 2P reservesstart 2010

Reserve additions2010-2018

Production2010-2018

Net 2P reservesend 2018

MMboe Net 2P Reserves

25

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

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*

26

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

Q&A

27

The Dons

Heather/Broom

Greater Kittiwake Area

Thistle/Deveron

Kraken

PM8/Seligi

Alma/Galia

Magnus

EnQuest: 8 HubsA strong platform for growth

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 ✔ ✔ ✔ ✔

29

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

Kraken subsurface

Kraken field water cut evolutionField data indicates effective reservoir sweep

31

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

32

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