saturn of permian basin

ENCANA CORPORATION
MONTNEY INVESTOR DAY
NEW YORK CITY
MAY 17, 2016
Doug Suttles
President & Chief Executive Officer
ENCANA IN 2016
Well Positioned for Success
TOP TIER RESOURCE
MARKET
FUNDAMENTALS
• 95% of 2016F capital allocated
to core four
• 2016 program focused on core
acreage in each asset
• Maximizing realized prices
• Informs capital allocation
• Actively managing volatility
BALANCE SHEET STRENGTH
OPERATIONAL
EXCELLENCE
CAPITAL
ALLOCATION
• Significant D&C cost efficiencies
• Rapid application of innovations
across portfolio
• RPH* model unlocks value
• Driven from the top
• Significant flexibility to scale
capital based on commodity
prices
*Resource Play Hub: Encana’s development model using repeatable, transferable operations techniques to reduce costs and improve safety and environmental performance.
2
ENCANA
Multi-Basin Portfolio Advantage
Montney
10,000 well locations
Duvernay
1,000 well locations
• “Core of the core” positions in four of North
America’s top basins
– Over 16,000 high quality locations
• Operational excellence
– Rapid application of innovations across the portfolio
– Significant D&C cost efficiencies
•
22 - 44% improvement in Q1 2016
• Focused portfolio with significant financial
flexibility
– 95% of 2016 capex invested into core four assets
Permian
5,000 well locations
Eagle Ford
600 well locations
Montney inventory based on 440 - 880 ft spacing
ENCANA CORPORATION
EXECUTION EXCELLENCE
Michael McAllister
EVP & COO
3
ENCANA’S EXECUTION EXCELLENCE
Basin Leading Operator
INNOVATION
CONTINUOUS IMPROVEMENT
BASIN
LEADING
OPERATOR
PORTFOLIO ADVANTAGE
DISCIPLINED BENCHMARKING
TO COMPETITORS
5
INNOVATION AT A GLANCE
Driving Efficiency Across the Portfolio
6
ENCANA MONTNEY
Development History
2009 - 2011
• HZ development of
BC Montney
MMcf/d
1,000
2006
• First HZ well drilled
750
500
2007 - 2008
• Land capture in Pipestone
• HZ development in
Gordondale
2013 - 2016
• Focus on condensate rich areas
• Completions design
optimization
• Veresen KKR infrastructure deal
2012
• Cutbank Ridge
Partnership (CRP) joint
venture with Mitsubishi
2003 - 2005
• Unconventional Montney
resource evaluation
• Land capture in Montney BC
Prior to 2003
• Conventional
vertical
development
250
0
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
7
ENCANA IS THE MONTNEY LEADER
Combined Scale and Efficiency
• Largest producer in the Montney
• Drilling cost leader
– Over a decade of operations in the play
– Longest laterals with highest completion intensity
• Massive wells
– Wells up to 2.5 MMBoe, IP >2,500 BOE/d
– Condensate rich wells flowing >400 bbls/d
Largest Producer
600
400
200
0
3,000
2,500
0.20
Rate (BOE/d)
800
0.40
Drilling Cost (MM$/1000’)
Gross Operated Production
(MMcf/d)
1,000
Massive Wells
Cost Leader
1,200
2,000
0
1,500
50
mi
1,000
500
0.00
0
0
60
120
180
240
300
360
Producing Days
Peer acreage sourced from RS Energy Group, Inc. & Company Presentations
8
ENCANA CORPORATION
FUNDAMENTALS
Renee Zemljak
EVP Midstream, Marketing & Fundamentals
David Thorn
Vice President, Marketing – Northern Operations
NORTH AMERICAN NATURAL GAS FUNDAMENTALS
Demand Expected to Grow by 14 Bcf/d by 2020
North American Demand Growth
Bcf/d
16
12
8
4
0
-4
2016F
Power
Other
Source: Encana Fundamentals, EIA, Ventyx, IHS
2017F
Residental/Commercial
2018F
Industrial
2019F
Export to Mexico
2020F
Gulf Coast LNG
Total Supply
10
NORTH AMERICAN NATURAL GAS FUNDAMENTALS
Future Demand Growth will be Concentrated in the Gulf Coast
Canada
2.0
1.0
1.5
1.3
0.0
2010-2015 2015-2020
1.6
0.8
West
Midwest
2.0
1.2
0.5
0.0
Northeast
3.0
1.7
1.0
1.1
2.6
1.5
0.0
2010-2015 2015-2020
1.0
0.0
2010-2015 2015-2020
2010-2015 2015-2020
Gulf Coast
12.0
9.5
6.0
Southeast
3.0
1.5
3.8
2.2
0.4
0.0
2010-2015 2015-2020
0.0
2010-2015 2015-2020
Source: Encana Fundamentals
11
NORTH AMERICAN NATURAL GAS FUNDAMENTALS
Low-Cost Supply Basins Continue to Grow
Montney expected to grow to ~7% of North American natural gas production by 2020
Bcf/d
10
10%
8
8%
6
6%
4
4%
2
2%
0
0%
2005
2006
2007
2008
2009
2010
Montney
Source: Encana Fundamentals, IHS
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Montney % of NA
12
NORTH AMERICAN NATURAL GAS FUNDAMENTALS
Montney - Highly Competitive Break-even Cost
Break-even
($/MMBtu)
$6.50
$6.00
$5.50
$5.00
$4.50
$4.00
$3.50
$3.00
$2.50
$2.00
Arkoma
Woodford
Fayetteville
Piceance
2012
Utica
2013
2014
Haynesville
Marcellus
2015
Current
Deep Basin
Montney
Source: RS Energy Group, Inc. – “Hardcore Canada” May 2016
13
NORTH AMERICAN NATURAL GAS FUNDAMENTALS
Activity Maintained in Lowest Cost Basins
Montney represents ~21% 2016F North American gas rig count, while Northeast represents ~24 %
Rigs
900
800
700
600
Rig activity declining
in high cost plays
500
400
300
Activity remains strong
in low-cost basins
200
100
0
2011
2012
Other North America
Source: Encana Fundamentals, Baker Hughes (U.S. rigs), IHS (Canadian rigs)
2013
2014
Montney
2015
US Northeast
2016
14
WESTERN CANADIAN MARKET FUNDAMENTALS
Natural Gas Export Basin – Premium Condensate Market
Western Canadian Sedimentary Basin
(WCSB)
West Coast LNG
Potential
Montney
Nova Gas
Transmission
System
(NGTL)
Condensate
Imports
255 Mbbl/d
To Pacific
Northwest
4.1 Bcf
•
•
•
•
•
•
15 Bcf/d gas production
5 Bcf/d regional demand
500 Bcf working storage
11.7 Bcf gas export capacity
220 Mbbls/d condensate production
400 Mbbls/d condensate demand
To Eastern Canada
4.2 Bcf
Natural Gas Export Pipeline
To U.S. Midwest
*3.4 Bcf
Condensate Import Pipeline
Source: Encana Fundamentals *Net Effective Capacity (Bakken Access)
15
WESTERN CANADIAN NATURAL GAS FUNDAMENTALS
Montney is the Growth Engine for WCSB
Bcf/d
20
Historical peak production
Forecast
45%
18
40%
16
35%
14
30%
12
25%
10
20%
8
15%
6
4
10%
2
5%
0
• Montney expected
to grow to 7 Bcf/d in
2020, representing
38% of WCSB
production
• Montney expected
to lead WCSB
growth back toward
2006 historical peak
0%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Other WCSB
Source: Encana Fundamentals, IHS
Montney
Montney % of WCSB
16
WESTERN CANADIAN NATURAL GAS FUNDAMENTALS
Local Demand Growth Driven by Oil Sands
Bcf/d
8
Forecast
7
• >1 Bcf/d of growth from oil
sands & power sector expected
through 2020
• Strong historical local demand
growth has reduced reliance on
total takeaway capacity
• Demand growth plus base
declines add ~1.8 Bcf of
incremental market
6
5
4
3
2
1
0
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Local Distribution Companies/Other
Industrial
Power
Oil Sands
Source: Encana Fundamentals, Statistics Canada
17
WESTERN CANADIAN NATURAL GAS FUNDAMENTALS
Required Exports and Currently Available Capacity
Bcf/d
12
• Substantial existing physical
export capacity
– Exceeds required exports
by >1.5 Bcf/d
• Montney does not require
any new transport capacity
to grow
11
10
9
8
7
6
2015
2016F
WCSB Required Exports*
2017F
2018F
2019F
2020F
Current Physical WCSB Export Capacity
Source: Encana Fundamentals *Required Exports = Expected Supply Minus Expected Demand
18
WESTERN CANADIAN NATURAL GAS FUNDAMENTALS
What is AECO?
West Coast LNG
Potential
Montney
• AECO is benchmark price for volumes
traded on Nova Gas Transmission
system (NGTL)
Nova Gas
Transmission
System
(AECO Price)
• Equivalent to NYMEX at Henry Hub
• Largest and most liquid gas trading
hub in North America
• AECO Basis is price difference versus
NYMEX
To Pacific
Northwest
4.1 Bcf
To Eastern Canada
4.2 Bcf
• Basis set by marginal cost of
transportation to neighboring markets
• Financial derivative market as liquid as
any in North America
To U.S. Midwest
*3.4 Bcf
Source: Encana Fundamentals *Net Effective Capacity (Bakken Access)
19
AECO BASIS
Price-Setting Mechanism
WCSB Required Exports & Contracted Capacity
Bcf/d
8.0
7.0
6.0
5.0
4.0
Jul-13
$/MMBtu
1.0
Oct-13
Jan-14
Apr-14
Concurrent widening in
AECO basis when required
exports exceed contracts
Jul-14
Oct-14
Jan-15
Required WCSB Exports*
Apr-15
Jul-15
Oct-15
Contracted Capacity
AECO Nominal Basis
Jan-16
Apr-16
Oversupply resulting in
incremental required exports
and widening AECO Basis
0.5
0.0
(0.5)
(1.0)
(1.5)
(2.0)
Jul-13
Oct-13
Jan-14
Apr-14
*Required Exports = Expected Supply Minus Expected Demand
Jul-14
Oct-14
Jan-15
Apr-15
Jul-15
Oct-15
Jan-16
Apr-16
20
AECO BASIS
Forward Market Trends Toward Historical Levels
$US/MMbtu
$0.50
• AECO basis has historically
averaged $(0.50)
$0.00
• Basis has recovered rapidly
when it has widened before
($0.50)
• The market sees a
directional return toward
historical levels
($1.00)
($1.50)
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Forward Market
Historical Market
Source: Encana Fundamentals, NGX, CME Group
21
MONTNEY ACCESS TO NORTH AMERICAN MARKETS
Efficient Access to Market
Montney
Oil Sands/
WCSB Demand
NGTL
West Gate
Export
A/BC Border
Source: Encana Fundamentals
East Gate Export
Empress/McNeill
Border
• NGTL: ~11 Bcf/d of supply,
>15,000 miles of pipeline, and
thousands of receipt & delivery
points
• Required expansions are
inexpensive, timely, and provide
system-wide access
• Approach is efficient and
different than single system
connection seen in US
production areas
• Minimal regulatory impediments
• Alliance and Westcoast offer
additional flexibility
22
MONTNEY ACCESS TO NORTH AMERICAN MARKETS
Existing WCSB Export Infrastructure Allows for Growth
Bcf/d
12
11
10
9
8
7
6
2015
2016F
2017F
WCSB Required Exports*
2018F
2019F
2020F
Current Physical WCSB Export Capacity
Source: Encana Fundamentals *Required Exports = Expected Supply minus Expected Demand
23
MONTNEY ACCESS TO NORTH AMERICAN MARKETS
WCSB Transportation – Cost Advantage to Northeast Market
Existing capacity will outcompete new-build economics
to Eastern Canadian markets by
~$0.15-$0.30/MMBtu
Montney continues to
compete in Western
markets, capturing
demand growth and
offsetting declines in the
region
Existing Infrastructure
Greenfield Infrastructure
Source: Encana Fundamentals, Various Pipeline Websites
Northeast U.S. production
will continue to capture
South and Southeastern
demand via existing
pipelines and shorter
greenfield connectivity
24
FUNDAMENTALS
The Montney Competes on a Delivered Cost Basis
• Montney growth is required to balance increasing North American demand
– Highly competitive supply cost
– Advantaged into Western and Eastern (Dawn) markets
• Existing export pipeline capacity allows for competitive access to markets
– Minimal regulatory risk
– WCSB production should naturally meet western demand growth
– With a declining rate base and increased contracting, TCPL tolls will be
competitive in Eastern markets
25
ENCANA CORPORATION
RESOURCE IN CONTEXT
David Hill
EVP Exploration & Business Development
Blair Porter
Advisor, Engineering – Exploration & Business Development
MONTNEY – MOST ACTIVE GAS PLAY
Q1 2016 Average Rig Activity
Montney
Rig activity concentrated in
lowest cost basins
Marcellus/Utica
1Q16 Rig
Activity
Play
Montney
54
Marcellus/Utica
46
Rockies
33
Haynesville
17
Rockies
Haynesville
Gas Wells
Oil Wells
Oil and Gas Wells
Active Rigs
Sources: IHS, DrillingInfo, Nickles, EIA
‘Active Rigs’ data as of March 2016
27
MONTNEY GEOLOGY OVERVIEW
Depositional Environment
British Columbia
Dawson
South
AA
A
B
C
Pipestone
– Not a shale
D
E
F
G
H
Gas
Condensate Rich
Super Condensate
• Siltstone reservoir
Alberta
SEXSMITH
980’ Hydrocarbon Bearing Reservoir
Tower
• High quality condensate & gas
regions
– Robust performance across all
fluid windows
• Multiple stacked zones
– Deposited in thick, stacked layers
Basal
28
MONTNEY REGIONAL SCALE
Areal Extent Same as Marcellus
Marcellus
Montney
• Size and scale of Montney
same as Marcellus
Alberta
• Montney condensate
window larger and richer
British Columbia
Peak 30d Rate (BOE/d)
0 - 100
100 - 150
150 - 200
200 +
0
40
Miles
80
(375 x 130 miles)
Source: IHS
29
ENCANA’S MONTNEY ACREAGE
Massive Contiguous Land Position
Encana Montney Acreage
810,000 gross acres (525,000 net)
Alberta
0
Miles
20
Peer Acreage
Encana Acreage
Peer acreage sourced from RS Energy Group, Inc. & Company Presentations
30
MONTNEY RESOURCE POTENTIAL
Stacked Zones Comparable to the Permian
Montney (350 miles)
Permian Midland Basin (100 miles)
Upper Montney to Base Sexsmith
Middle Spraberry to Base Wolfcamp C
SE
NW
NW
SE
1,000’
2,000’
50 to 200 Bcf/section
Up to 6 stacked laterals
>150 MMbbls/section
>8 stacked laterals
Marcellus (350 miles)
Eagle Ford (200 miles)
NE
SW
W
E
250’
Hydrocarbon Filled Porosity
250’
30 to 40 MMbbls/section
Up to two stacked laterals
50 to 60 Bcf/section
Single lateral
31
MONTNEY PLAY
Three Distinct Regions
• Northwest
Northwest
Alberta
940 Hz wells drilled; 265 in 2015
– Narrow region of high performance
• Central
Central
2,100 Hz wells drilled; 260 in 2015
– Highest quality pay
– Prolific condensate window
– Thickest stacked reservoirs
Southeast
Conventional
Super Condensate Rich
(>100 bbls/MMcf)
Condensate Rich
(10-100 bbls/MMcf)
Gas
Peak 30d Rate (BOE/d)
0 - 100
100 - 150
150 - 200
200 +
• Southeast
450 Hz wells drilled; 130 in 2015
– High quality condensate
– Minimal activity in gas window
(<10 bbls/MMcf)
Source: IHS
32
MONTNEY REGIONAL SCALE
Encana’s Acreage is in the Core of the Basin
Encana Acreage
Alberta
Alberta
Northwest
Central
Peak 30d Rate (BOE/d)
0 - 100
100 - 150
150 - 200
200 +
Conventional
Super Condensate Rich
Condensate Rich
Gas
Southeast
Core Acreage
Source: IHS
33
NW
CROSS-SECTION OF THE MONTNEY
Stacking Adds Scale
Northwest
Central
Montney Regional Section: Hydrocarbon Filled Porosity
1,000’
Southeast
SE
NW
SE
Northwest
Central
Southeast
(Structural Complexity)
(Stacked, High Quality)
(Stacked, Condensate Rich)
Hydrocarbon filled porosity
34
WORLD CLASS GAS PLAY
Best Rocks Drive Performance
Average Gas Well Performance by Region
(Wells Since 2014)
Alberta
Northwest
6
Gas Rate (MMcf/d)
(Normalized to 8,200’)
Central
8
4
Central Core
Northwest Core
2
Central Non-Core
Northwest Non-Core
Conventional
Super Condensate Rich
Condensate Rich
Gas
0
0
0.5
1
1.5
2
2.5
3
3.5
Cumulative Gas Production (Bcf)
(Normalized to 8,200’)
Source: IHS, Encana data
35
CORE POSITION IN A WORLD CLASS GAS PLAY
Operational Excellence Driving Basin Leading Performance
Alberta
Northwest
Average Gas Well Performance by Region
(Wells Since 2014)
12
Conventional
Super Condensate Rich
Condensate Rich
Gas
Gas Rate (MMcf/d)
(Normalized to 8,200’)
10
Central
8
6
Encana 2015 Montney
(25 Wells)
4
Central Core
Northwest Core
Central Non-Core
Northwest Non-Core
2
0
0
0.5
1
1.5
2
2.5
3
3.5
4
Cumulative Gas Production (Bcf)
(Normalized to 8,200’)
Source: IHS, Encana data
36
MONTNEY COMPETES WITH CORE MARCELLUS
Encana Innovation Driving Productivity
Average Well Performance
Marcellus vs. Encana Montney
Gas Rate (MMcf/d)
(Normalized to 8,200’)
16
12
8
Marcellus NE Core
Encana 2015 Montney
4
Marcellus SW Core
0
0
1
2
3
4
5
6
7
Cumulative Gas Production (Bcf)
(Normalized to 8,200’)
Source: IHS, Encana data
37
SIGNIFICANT CONDENSATE OPPORTUNITY
Encana Delivering Strong Condensate Wells
Encana Recent Condensate Well Results
800
7,000
700
6,000
600
5,000
500
4,000
400
3,000
300
2,000
200
1,000
100
0
• Pipestone (Super-Condensate area >100 bbls/MMcf)
Gas Rate (Mcf/d)
(Normalized to 8,200’)
Condensate Rate (bbls/d)
(Normalized to 8,200’)
Montney 30 Day Peak Condensate Rates by Region
–
1,650 bbls/d of condensate & 2.6 MMcf/d
(~2,080 BOE/d)
• Tower (Condensate area 10 - 100 bbls/MMcf)
–
370 bbls/d of condensate & 5.5 MMcf/d
(~1,320 BOE/d)
• Dawson South (Condensate area 10 – 100 bbls/MMcf)
–
500 bbls/d of condensate & 8.4 MMcf/d
(~1,900 BOE/d)
0
SE
Central
Central
Central
Super Condensate Area
Condensate Area
Gas Area
>100 bbls/MMcf
10-100 bbls/MMcf
0-10 bbls/MMcf
Condensate
Natural Gas
Source: IHS (data limited to wells with substantial liquids volumes reported in condensate areas)
38
STACKED RESOURCE POTENTIAL
10,000 Inventory Locations
Stacking Development Layers (#)
Conventional
Super Condensate Rich
Condensate Rich
Gas
Gross Acres
Spacing
Inventory
Super Rich Condensate
82,000
440’
3,000
Condensate
125,000
660’
3,600
Gas
185,000
880’
Total Inventory
3,400
10,000
8,200' Well Length
39
ENCANA CORPORATION
Development Plans
Jim Roberts
Vice-President & General Manager, Northern Operations
ENCANA IN THE MONTNEY
A Premier North American Play
•
•
Large resource poised for significant growth
–
525,000 net acres in 3 contiguous core blocks
–
Over 1,000’ of pay, up to 6 stacked horizons
–
Up to 220 Bcf/section with up to 450 bbls/MMcf condensate
–
10,000 gross well inventory
Tower
Saturn
Gordondale
Dawson
South
Basin leading operator
–
Most efficient operator with track record of innovation
–
–
Pipestone
Encana Core Montney
Encana Non-core Montney
Cost reductions of 22% 2016 Q1 vs. 2015
Longest laterals with highest completion intensity
–
Generates superior economic performance
10,000 Well Inventory
• Flexible infrastructure plan
30%
–
Innovative midstream arrangement
–
800 MMcf/d of expansion under construction
–
Growing net production to over 75,000 bbls/d and 1.8 Bcf/d by 2026
Gas
(0 - 10 bbls/MMcf)
34%
Condensate
(10 - 100 bbls/MMcf)
Super-Condensate
(>100 bbls/MMcf)
36%
41
Estimated inventory based on 440 - 880 ft spacing
ENCANA IN THE MONTNEY
History of Well Design Innovation
2006
2007 - 2012
2013 - 2015
Present Day Design
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
4,200 ft lateral
300 lb/ft proppant
3.5 bbls/ft fluid
900 ft cluster spacing
900 ft stage spacing
4,200 - 7,800 ft lateral
300 - 1,000 lb/ft proppant
6 bbls/ft fluid
165 ft cluster spacing
660 ft stage spacing
7,200 - 9,000 ft lateral
650 - 1,800 lb/ft proppant
12 - 23 bbls/ft fluid
80 ft cluster spacing
410 ft stage spacing
8,200 - 9,000 ft lateral
1,000 - 1,200 lb/ft proppant
15 - 18 bbls/ft fluid
65 - 80 ft cluster spacing
330 - 410 ft stage spacing
42
ENCANA IN THE MONTNEY
Drilling & Completions
2006 – 2016
Lateral length (ft)
10,000
8,000
6,000
Lateral Length
Increased ~2X
4,000
2,000
0
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016F
Proppant (lb/ft)
2,000
1,500
Proppant Loading
Increased ~4X
1,000
500
0
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016F
D&C Cost ($/1,000’)
1.25
Completions
1.00
Drilling
0.75
Drilling and Completion Cost*
Decreased 50%
0.50
0.25
0.00
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2016F
43
*All data normalized to $0.75 FX
ENCANA IN THE MONTNEY
Well Performance and F&D
2006 – 2016
IP30 (BOE/d)
1600
1200
IP30
Increased ~5X
800
400
0
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016F
EUR (MBOE)
2,000
EUR
Increased ~8X
1,500
1,000
500
-
F&D ($/BOE)
2006
$8
$7
$6
$5
$4
$3
$2
$1
$0
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016F
22
F&D
Reduced ~6X
2006
2007
*All data normalized to $0.75 FX
2008
2009
2010
2011
2012
2013
2014
2015
2016F
44
ENCANA IN THE MONTNEY
Resource Play Hub at Work
•
Water Resource Hub: Centralized Water Handling Facility
– Capacity of 50,000 bbls/d, recycling and saline, non-potable source wells
– Made possible by concentrated, continuous activity and growth plan
– Environmentally sustainable: reduces demand on domestic water supplies
– Offers certainty for completions execution
– Reduces impact on stakeholders: traffic, dust, noise
•
>$32 MM in savings to date
– ~40,000 less truck loads
– ~$5.85/bbl operating cost savings
– ~$300K/well capital cost savings
•
Project ROR ~30%
45
Tower
CONDENSATE (10-100 bbls/MMcf)
Tower
Type Curve
IP180 Condensate = 370 bbls/d
IP180 Gas = 5.4 MMcf/d
EUR = 1.2 MMBOE
D&C = $4.4 MM
Lateral Length = 8,000 ft
3,000
2,500
Rate (BOE/d)
2,000
2-12 Pad
2016 Drill
5-1 Pad
50 to >100 bbls/MMcf
After 5 months 36% higher than type curve
1,500
5mi / 8km
1,000
Type Well Metrics – ECA Net
500
Leveraged
Unleveraged
>200
80
Btax Payout (Months)
10
16
Operating Margin ($/BOE)
14
14
2 Year Free Cash Flow ($MM)
2.5
1.0
Btax IRR (%)
Type Curve
Actuals
0
0
30
60
90
120
150
180
Producing Days
All metrics based on $3.0/MMBtu NYMEX, $50/bbl WTI, and $0.75 FX
46
CONDENSATE (10-100 bbls/MMcf)
Saturn
Type Curve
IP180 Condensate = 350 bbls/d
IP180 Gas = 7.5 MMcf/d
EUR = 1.3 MMBOE
D&C = $4.3 MM
Lateral Length = 8,200 ft
3,000
2,500
Rate (BOE/d)
Saturn
4-2, 6-2, 8-2 Pads
2016 Drill
16-28
After 8 months 70% higher than type curve
2,000
10-100 bbls/MMcf
1,500
5mi / 8km
1,000
Rate restricted due to facility limitations
Type Well Metrics – ECA Net
500
Leveraged
Unleveraged
>200
100
Btax Payout (Months)
10
15
Operating Margin ($/BOE)
11
11
2 Year Free Cash Flow ($MM)
3.1
1.6
Btax IRR (%)
Type Curve
Actuals
0
0
30
60
90
120
150
180
210
240
270
Producing Days
All metrics based on $3.0/MMBtu NYMEX, $50/bbl WTI, and $0.75 FX
47
CONDENSATE (10-100 bbls/MMcf)
Dawson South
New E4-17 Lower Montney IP
23% condensate
67% above type curve
3,000
2,500
Rate (BOE/d)
2,000
Dawson South
Lower Montney Type Curve
IP180 Condensate = 350 bbls/d
IP180 Gas = 7.1 MMcf/d
EUR = 2.1 MMBOE
D&C = $5.2 MM
Lateral Length = 9,800 ft
9-35 Pad
10-100 bbls/MMcf
12-23 Pad
2016 Drills
14-19 Pad
2016 Drills
4-17 Pad
12-5 Pad
New B11-17 Lower Montney IP
9% condensate
46% above type curve
2016 Drills
11-17 Pad
<10 bbls/MMcf
1,500
5mi / 8km
1,000
Lower Montney Type Well Metrics – ECA Net
Lower Montney Type Curve
Lower Montney Actuals
Upper Montney Actuals
500
0
0
60
120
180
Producing Days
All metrics based on $3.0/MMBtu NYMEX, $50/bbl WTI, and $0.75 FX
Leveraged
Unleveraged
>200
105
Btax Payout (Months)
10
14
Operating Margin ($/BOE)
12
12
2 Year Free Cash Flow ($MM)
3.8
2.1
Btax IRR (%)
240
300
360
48
SUPER-CONDENSATE (>100 bbls/MMcf)
Pipestone
2016 Drills
14-28 Pad
3,000
Pipestone
2-15
2016 Drills
14-1 Pad
Type Curve
IP180 Condensate = 610 bbls/d
IP180 Gas = 2.6 MMcf/d
EUR = 1.2 MMBoe
D&C = $5.4 MM
Lateral Length = 9,800 ft
2,500
New 14-1 Pad well IP
56% condensate
2,000
12-25
Rate (BOE/d)
>100 bbls/MMcf
1,500
5mi / 8km
1,000
Type Well Metrics – ECA Net
Type Curve
500
12-25 Actuals
2-15 Actuals
0
0
90
180
270
Producing Days
360
450
540
Btax IRR (%)
139
Btax Payout (Months)
10
Operating Margin ($/BOE)
25
2 Year Free Cash Flow ($MM)
8.6
All metrics based on $3.0/MMBtu NYMEX, $50/bbl WTI, and $0.75 FX
49
ENCANA MONTNEY TYPE CURVES
Total Gross Inventory
BRITISH COLUMBIA
ALBERTA
Gas
Condensate
Super Condensate
Condensate
IP30 (BOE/d)
1,500 - 2,000
1,400 - 1,800
900 - 1,100
1,850 - 2,050
600 - 800
IP180 (BOE/d)
1,400 - 1,700
1,300 - 1,700
800 - 1,000
1,450 - 1,650
900 - 1,100
Region
EUR/Well (Bcfe)
EUR/Well (MBOE)
Condensate Yield (bbls/MMcf)
D&C Cost/well ($MM)
Super Condensate
9 - 11
7-9
5.5 - 6.5
12 - 14
5.5 - 7.5
1,600 - 1,800
1,250 – 1,500
900 - 1,100
2,000 - 2,300
900 - 1,200
<10
10 - 100
>100
10 - 100
>100*
4.9
4.9
4.9
4.9
4.9
Average Lateral Length (ft)**
8,200
8,200
8,200
8,200
8,200
Total Gross Inventory
3,400
2,400
1,100
1,200
1,900
Estimated inventory based on 440 - 880 ft spacing. *Alberta Super-Condensate averages >300 bbls/MMcf **Actuals vary between 7,800-9,900’
50
MONTNEY PRODUCERS AT A GLANCE
Encana is the Largest Producer
Gross Operated Production (MMcf/d)
1,200
1,000
800
600
400
200
0
Peer acreage sourced from RS Energy Group, Inc. & Company Presentations
Rig Count
AAV
APA
ARC
BIR
CNRL
COP
Encana
MUR
NVA
Other
PPY
Progress
7Gen
RDS
TOU
Total
2015Q4
1
1
1
1
0
1
1
1
2
17
1
13
9
3
2
54
2016Q1
1
2
1
2
2
1
3
1
2
15
3
10
7
3
1
54
51
Source : Industry data. Rig counts displayed for the most active and key peers.
– ~35 % greater than industry average
• Continuous improvement and innovation
to reduce costs
8,000
6,000
4,000
2,000
0
2006
– Bit design & optimization
– Customized drilling parameters unique to reservoir
0.8
Drilling Cost (MM$/1000’)
– Competitor benchmarking
2008
2009
2010
2011
2012
2013
2014
2015
Industry Average
2014-15 Drilling Cost Comparison
– Vendor sourcing for volume discounts
– Load leveling
2007
Encana
– High performance motors
– Fluid system evolution
Lateral Length: ECA vs Industry
10,000
0.6
0.4
0.2
0.0
Source : Industry Data: The Well Completions and Frac Database (Canadian Discovery) and Industry Report
Southeast
0.8
Drilling Cost (MM$/1000’)
• Encana leading with longer laterals
Average Lateral Length (ft)
ENCANA MONTNEY VS. COMPETITORS
Drilling Performance
Central
0.6
0.4
0.2
0.0
52
Tower
ENCANA MONTNEY VS. COMPETITORS
Tower Performance and Economics
Completion Cost ($MM/1,000’)
2014-15 Completion Cost/1,000’ in Tower
Completion Comparison
0.80
Encana
Peer*
1,200
1,200
Fluid (gal/ft)
670
980
Stage Spacing (ft)
330
175
Proppant Density (lb/ft)
0.60
0.40
Cluster density
0.20
Completion Type
2
Cased
Cased
*Tower specific average
0.00
Tower Peer
ECA Tower
2016 Pacesetter
Production
1,200
ECA 5-1 Pad Type Curve
800
400
Tower Peer Type Curve
0
0
12
24
Months
ECA Tower wells
outperform IRR by 35%
and payout 10% faster
Production & Economic Comparison
Encana
Peer*
EUR/1000’ (BOE)
160
125
IP180/1000’ (BOE/d)
160
205
Btax IRR%
150
110
Disc Payout (years)
1.0
1.1
2 Year Netback ($/BOE)
15
16
1,600
Daily Rate (BOE/d)
5
36
48
All metrics based on $3.00/MMBtu NYMEX, $50/bbl WTI, and $0.75 FX *Source : Industry Data, The Well Completions and Frac Database (Canadian Discovery), and Company Presentations
Saturn
ENCANA MONTNEY VS. COMPETITORS
Saturn Performance and Economics
Completion Comparison
Completion Cost ($MM/1,000’)
2014-15 Completion Cost/1,000’ in Saturn
0.80
Encana
Peer*
1,200
675
Fluid (gal/ft)
670
475
Stage Spacing (ft)
330
190
Proppant Density (lb/ft)
0.60
0.40
Cluster density
0.20
Completion Type
ECA Saturn
-
Cased
Open Hole
ECA Saturn wells
outperform IRR by 70%
and payout 20% faster
2016 Pacesetter
Production
Production & Economic Comparison
2,000
Daily Rate (BOE/d)
5
*Saturn specific average
0.00
Saturn Peer
Encana
Peer*
1,600
EUR/1000’ (BOE)
200
110
1,200
IP180/1000’ (BOE/d)
205
125
800
Btax IRR%
85
50
400
Disc Payout (years)
1.4
1.7
2 Year Netback ($/BOE)
11
14
ECA 8-2 Pad Type Curve
Saturn Peer Type Curve
0
0
12
24
Months
53
36
48
All metrics based on $3.00/MMBtu NYMEX, $50/bbl WTI, and $0.75 FX *Source : Industry Data, The Well Completions and Frac Database (Canadian Discovery), and Company Presentations
54
ENCANA MONTNEY
10 Year Growth Plan
10 Year Production Forecast
• > 50,000 bbls/d & 1 Bcf/d by 2018
2,000
Decades of inventory remaining
• Utilizes 3rd party capital to fund infrastructure
growth
Unique fee-for-service arrangement
• Capital focused on higher return D&C activities vs.
facilities
–
Enables double the production growth
100,000
1,400
1,200
75,000
1,000
800
50,000
600
• Generates superior financial returns
–
1,600
Gas (MMcf/d)
–
125,000
Gas Rate
Liquid Rate
1,800
Liquids (bbls/d)
–
400
Free cash flow positive 2017+
–
$700 MM free cash flow per year within a decade
–
Resilient to commodity prices
25,000
200
0
0
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
55
INFRASTRUCTURE PLAN
Building Flexibility for Growth
• Encana utilizing ~1.0 Bcf/d of processing capacity
Fort St. John
– 3rd party midstream facilities
Spectra
McMahon
– ECA owned facilities
Spectra
West Doe
– Unique fee for service agreement with Veresen
Midstream Limited Partnership (VMLP)
Tower 3-7
BC Station 2
• Processing capacity expansions underway
Saturn 15-27
Phase 2
Spectra
Dawson Dawson
Creek
Sunrise 4-26
AltaGas
Gordondale
AECO
ECA
Sexsmith
– Bundled infrastructure model
•
Inlet and field compression, liquids handling, and gas
processing in one location
Veresen
Steeprock
– ~800 MMcf/d of additional gas processing by 2018
New Processing
Gas Capacity (MMcf/d)
Condensate Production (bbls/d)
NGL (C2-C4) Production (bbls/d)
On-stream Date
Tower
Sunrise
Saturn
200
400
200
10,000
1,600
4,000
8,300
4,200
13,200
Late 2017
Late 2017
Mid-2018
Veresen
Hythe
To North American
Market
Grande
Prairie
Existing
Future
COP
Wembley
To North American
Market
56
INFRASTRUCTURE PLAN
Bundled Infrastructure Growth
• Encana bundled infrastructure model
• Unbundled infrastructure model
–
–
–
–
–
Model typically used by industry
Field compression, liquids handling, and gathering away
from main processing facility
Benchmark processing facility cost ~$1MM per MMcf/d
of capacity
–
–
Bundled infrastructure cost: $1.6MM/MMcf/d
Larger and more efficient production growth
Smaller environmental footprint with less risk of
regulatory delays
Lower construction cost
Lower operating costs
Plant Cost: ~$1MM/MMcf/d
Sunrise 400 MMcf/d Plant Example
$1 MM/MMcf/d
gas processing
$400
Gathering, compression,
and liquids handling
+ $240
Total Cost (MM$ USD)
$640
Gathering
Well Head
Liquids Handling
Compression
Gas
Processing
Sales Meter
57
LANDMARK AGREEMENT WITH VERESEN MIDSTREAM (VMLP)
Innovative Fee-for-Service Structure
• Maximizing flexibility while managing execution
– In 2015, Encana and CRP sold infrastructure to VMLP and entered into gathering and processing arrangement for
Montney acreage
– Encana controls the pace and construction of facilities needed within ten years with VMLP funding
• Increased financial flexibility
– VMLP is guaranteed a simple payout of incurred cost eight years after facilities are on-stream
•
Production in the current development plan exceeds production required for simple payout of facilities cost
– Production from all sources* contribute to the simple payout calculation
• Fee-for-service with a top-up
– Tolls are based upon a pre-agreed fee structure
•
No exposure to unutilized demand charges beyond the simple payout of incurred cost
•
No escalation in capital component of fees
•
Encana manages the operating component of fees while operating facilities
*Sources include any Encana or third party production routed through VMLP funded facilities
58
INFRASTRUCTURE STRATEGY
Capital Efficiency Driving Higher Production Growth
• Midstream strategy allows Encana to focus capital on higher return D&C activities vs. facilities
• Delivers 2x growth
Encana Liquids Production Outlook
10-Year CAGR
ECA
Self Build
Liquids
9%
5%
60
40
20
10-Year CAGR
ECA
Self Build
Gas
10%
6%
1,500
1,000
500
0
0
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
ECA
ECA
Self Build
Self Build
Self Build = Theoretical Encana self build scenario where Encana incurs all facility construction costs
INFRASTRUCTURE STRATEGY
Growth Driving Incremental Value
59
ECA vs “Self Build”: Income Margin and Cum. Op. Cash Flow
$20
• Material improvements to cash flow and
returns
– 50% higher IRR
• F&D improvement outweighs margin impact
– ~30% better F&D with third party infrastructure
build
30%
Income Margin ($/BOE)
– ~30% higher operating cash flow over 10 years
$8,000
Notes
I.
Plot includes existing production
II.
Income Margin is Operating Margin less F&D
$15
$6,000
$10
$4,000
$5
$2,000
$0
$0
Cum. BT Operating Cash Flow ($MM)
80
Encana Natural Gas Production Outlook
2,000
Gas Production (MMcf/d)
Liquids Production (Mbbls/d)
100
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
2017–2026 Development Scenario
Capital ($MM)
ECA
Self Build
~$4,200
BTax IRR
125%
75%
Positive Cash Flow
1 year
1.5 years
F&D ($/BOE)
$50 Oil & $3.0 Gas
ECA Income Margin
Self Build Income Margin
ECA Cum BT Op. Cash Flow
Self Build Cum BT Op. Cash Flow
$4
$3
$2
$1
$0
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
ECA F&D
Self Build F&D
Self Build = Theoretical Encana self build scenario where Encana incurs all facility construction costs
60
MONTNEY DEVELOPMENT PLAN
Free Cash Flow Generator
Capital vs. Cash Flow at $50 WTI and $3.00 NYMEX
$MM
$1,600
• Self funding
$1,200
– Montney generates free cash flow after
development capital spending
$800
$400
• Sustainable value generation at lower
commodity prices
$2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Development Capital
– Free cash flow generation continues in a
lower price environment
– “Self Build” scenario requires 4.5 years to
achieve positive cash flow
Operating Cash Flow
Capital vs. Cash Flow at $40 WTI and $2.50 NYMEX
$MM
$1,600
$1,200
$800
$400
$-
Self Build = Theoretical Encana self build scenario where Encana incurs all facility construction costs
ENCANA MONTNEY
Positioned for Growth
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Development Capital
Operating Cash Flow
Development Plan & Upside* Growth Forecast
4,000
• Unique infrastructure model enables
sustainable growth
– Capital focused on higher return D&C activities vs.
facilities
• Exceptionally strong financial results
– Free cash flow generator
– Resilient to low prices
3,500
Gas Production (MMcf/d)
– 10,000 wells to drill
150,000
125,000
3,000
100,000
2,500
2,000
75,000
1,500
50,000
1,000
Liquids Production (bbls/d)
• Massive resource poised for significant growth
– Encana holds a commanding position in the core of
the Montney
61
25,000
500
0
0
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Gas
Estimated inventory based on 440 - 880 ft spacing *Upside scenario includes an incremental ~1,200 locations.
Gas (Upside)
Liquids
Liquids (Upside)
62
DELIVERING QUALITY RETURNS FROM A PREMIER ASSET
• Montney among the lowest supply cost basins
• Advantaged into Western and Dawn gas markets on a delivered cost
basis
• Encana is positioned in the core of the play
‒ Massive inventory poised for significant gas and condensate growth
‒ Basin leading operator
‒ Innovative, flexible infrastructure plan to support future growth
‒ Self funding development generates significant free cash flow
FUTURE ORIENTED INFORMATION
This presentation contains certain forward-looking statements or information (collectively, “FLS”) within the meaning of applicable securities legislation. FLS include:
•
•
Encana’s 2016 capital program, including the amount allocated to its core four assets
• number of wells and locations, decline rates, focus of drilling program and operating performance compared
anticipated capital and cost efficiencies, including drilling and completion, operating and corporate costs, and
to type curves and drilling and completions costs
future savings to be realized
• anticipated reserves and resources, including product types and stacked resource potential
• ability to scale or redirect capital program
• expected rig count and rig release metrics
• well performance, completions intensity, location of acreage and costs relative to peers and within plays
• increases to average IP30, EUR, proppant intensity and lateral length
• competitiveness of Montney within North America and commodity composition
• innovation and asset quality to drive capital productivity
• anticipated natural gas demand growth and sources of growth
• anticipated third-party incremental and joint venture carry capital
• anticipated production, growth profile completions intensity, free cash flow, capital coverage, payout, net
• anticipated hedging and outcomes of risk management program, including amount of hedged production
present value, rates of return and operating margins, including expected timeframes
• anticipated proceeds from divestitures, use of proceeds therefrom, satisfaction of closing conditions and
• expected net exports, available capacity, expansion in infrastructure and anticipated savings
timing of closing
• commodity price outlook
Readers are cautioned against unduly relying on FLS which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or for results to differ materially from those expressed
or implied. These assumptions include:
•
•
•
•
•
assumptions contained in Encana’s 2016 corporate guidance and in this presentation
data contained in key modeling statistics
availability of attractive hedges and enforceability of risk management program
results from innovations
expectation that counterparties will fulfill their obligations under gathering, midstream and marketing
agreements
•
•
•
access to transportation and processing facilities where Encana operates
effectiveness of Encana’s resource play hub model to drive productivity and efficiencies
expectations and projections made in light of, and generally consistent with, Encana’s historical experience
and its perception of historical trends, including with respect to the pace of technological development, the
benefits achieved and general industry expectations
Risks and uncertainties that may affect these business outcomes include: risks inherent to closing announced divestitures on a timely basis or at all and adjustments that may reduce the expected proceeds and value to Encana;
commodity price volatility; timing and costs of well, facilities and pipeline construction; ability to secure adequate product transportation and potential pipeline curtailments; business interruption and casualty losses or unexpected
technical difficulties; counterparty and credit risk; fluctuations in currency and interest rates; risk and effect of a downgrade in credit rating, including below an investment-grade credit rating, and its impact on access to capital markets
and other sources of liquidity; variability and discretion of Encana’s Board to declare and pay dividends, if any; the ability to generate sufficient cash flow to meet Encana’s obligations; failure to achieve anticipated results from cost
and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; Encana’s ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of
natural gas and liquids from resource plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; changes in or interpretation of
royalty, tax, environmental, accounting and other laws; risks associated with past and future divestitures of certain assets or other transactions or receive amounts contemplated under the transaction agreements (such transactions
may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as "partnerships" or "joint ventures" and the funds received in respect thereof which Encana may refer to from time to
time as "proceeds", "deferred purchase price" and/or "carry capital", regardless of the legal form) as a result of various conditions not being met; and other risks and uncertainties impacting Encana's business, as described in its most
recent MD&A, financial statements, Annual Information Form and Form 40-F, as filed on SEDAR and EDGAR.
Although Encana believes the expectations represented by such FLS are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties
referenced above are not exhaustive. FLS are made as of the date of this presentation and, except as required by law, Encana undertakes no obligation to update publicly or revise any FLS. The FLS contained in this presentation
are expressly qualified by these cautionary statements.
Certain future oriented financial information or financial outlook information is included in this presentation to communicate current expectations as to Encana’s performance. Readers are cautioned that it may not be appropriate for
other purposes. This presentation may contain references to non-GAAP measures, which do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies.
These measures are presented to provide shareholders and potential investors with additional information regarding Encana’s liquidity and its ability to generate funds to finance its operations. Rates of return for a particular play or
well are on a before-tax basis and are based on specified commodity prices with local pricing offsets, capital costs associated with drilling, completing and equipping a well, field operating expenses and certain type curve
assumptions. Pacesetter well costs for a particular play are a composite of the best drilling performance and best completions performance wells in the current quarter in such play and are presented for comparison purposes relative
to other companies.
For convenience, references in this presentation to “Encana”, the “Company”, “we”, “us” and “our” may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships
(“Subsidiaries”) of Encana Corporation, and the assets, activities and initiatives of such Subsidiaries.
64
ADVISORY REGARDING RESERVES DATA & OTHER OIL & GAS INFORMATION
National Instrument (“NI”) 51-101 of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. Encana complies with NI 51-101 disclosure
requirements in its most recently filed annual information form (“AIF”). Detailed Canadian protocol disclosure is contained in Appendix A and under “Narrative Description of the Business” of the AIF. Certain disclosure is also
prepared in accordance with U.S. disclosure requirements as set forth in Appendix D of the AIF. A description of the primary differences between the disclosure requirements under Canadian standards and under U.S. standards is
set forth under the heading “Reserves and Other Oil and Gas Information” in the AIF. Additional detail regarding Encana’s economic contingent resources disclosure is available in the Supplemental Disclosure Document filed
concurrently with the AIF.
All estimates are effective as of December 31, 2015, are derived from reports prepared by independent qualified reserves evaluators engaged by Encana and are prepared in accordance with procedures and standards contained in
the Canadian Oil and Gas Evaluation Handbook (“COGEH”), NI 51-101 and SEC regulations, as applicable. Information on the forecast prices and costs used in preparing the estimates are contained in the AIF. For additional
information relating to risks associated with the estimates of reserves and resources, see “Risk Factors” in the AIF.
Reserves are the estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: analysis of drilling, geological,
geophysical and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Proved reserves are those reserves which can be estimated with a high
degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than
proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less
certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Contingent resources do not constitute,
and should not be confused with, reserves. Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or
technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is uncertainty that it will be commercially viable to produce any portion of the
resources. All of the resources classified as contingent are considered to be discovered, and as such have been assigned a 100% chance of discovery, but have however been risked for the chance of development. The chance of
development is defined as the likelihood of a project being commercially viable and development proceeding in a timely fashion. Determining the chance of development requires taking into consideration each contingency and
quantifying the risks into an overall development risk factor at a project level. Contingent resources are categorized as economic if those contingent resources have a positive net present value under currently forecasted prices and
costs. In examining economic viability, the same fiscal conditions have been applied as in the estimation of Encana’s reserves. Contingencies include factors such as required corporate or third party (such as joint venture partners)
approvals, legal, environmental, political and regulatory matters or a lack of infrastructure or markets.
Encana uses the terms play, resource play, total petroleum initially-in-place (“PIIP”), natural gas-in-place (“NGIP”), and crude oil-in-place (“COIP”). Play encompasses resource plays, geological formations and conventional plays.
Resource play describes an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which when compared to a conventional play, typically has a lower geological and/or commercial
development risk and lower average decline rate. PIIP is defined by the Society of Petroleum Engineers - Petroleum Resources Management System (“SPE-PRMS”) as that quantity of petroleum that is estimated to exist originally in
naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be
discovered (equivalent to “total resources”). NGIP and COIP are defined in the same manner, with the substitution of “natural gas” and “crude oil” where appropriate for the word “petroleum”. As used by Encana, estimated ultimate
recovery (“EUR”) has the meaning set out jointly by the Society of Petroleum Engineers and World Petroleum Congress in the year 2000, being those quantities of petroleum which are estimated, on a given date, to be potentially
recoverable from an accumulation, plus those quantities already produced therefrom.
In this presentation, Encana has provided information with respect to certain of its plays and emerging opportunities which is “analogous information” as defined in NI 51-101. This analogous information includes estimates of PIIP,
NGIP, COIP or EUR, all as defined in the COGEH or by the SPE-PRMS, and production type curves. This analogous information is presented on a basin, sub-basin or area basis utilizing data derived from Encana's internal sources,
as well as from a variety of publicly available information sources which are predominantly independent in nature. Production type curves are based on a methodology of analog, empirical and theoretical assessments and workflow
with consideration of the specific asset, and as depicted in this presentation, is representative of Encana’s current program, including relative to current performance. Some of this data may not have been prepared by qualified
reserves evaluators or auditors, may have been prepared based on internal estimates, and the preparation of any estimates may not be in strict accordance with COGEH. Estimates by engineering and geo-technical practitioners
may vary and the differences may be significant. Encana believes that the provision of this analogous information is relevant to Encana's oil and gas activities, given its acreage position and operations (either ongoing or planned) in
the areas in question, and such information has been updated as of the date hereof unless otherwise specified. Due to the early life nature of the various emerging plays discussed in this presentation, PIIP is the most relevant
specific assignable category of estimated resources. There is no certainty that any portion of the resources will be discovered. There is no certainty that it will be commercially viable to produce any portion of the estimated PIIP,
NGIP, COIP or EUR. Disclosure regarding drilling locations is based on internal estimates, may include proved, probable and unbooked locations, and assume a number of wells that can be drilled per section based on industry
practice and/or internal review. The drilling locations which Encana will actually drill will ultimately depend upon the availability of capital, regulatory and partner approvals, seasonal restrictions, oil and natural gas prices, costs,
actual drilling results, additional reservoir information that is obtained and other factors.
30-day IP and other short-term rates are not necessarily indicative of long-term performance or of ultimate recovery. The conversion of natural gas volumes to barrels of oil equivalent (“BOE”) is on the basis of six thousand cubic feet
to one barrel. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Readers are cautioned that BOE may be
misleading, particularly if used in isolation.
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