Hospitality Committee Guru Poornima Meetings Prasanthi Nilayam July 2014.
Investor meetings July 2019 - Home - EnQuestInvestor meetings July 2019 EnQuest A clear strategy...
Transcript of Investor meetings July 2019 - Home - EnQuestInvestor meetings July 2019 EnQuest A clear strategy...
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