Corporate Presentation

Transcription

2016 Investor Day
October 5 | New York City, NY
One. Agile. Driven.
ENCANA CORPORATION
Quality Growth
Doug Suttles
President & Chief Executive Officer
ENCANA
Clear Strategic Focus
• Foundation (2013 – 2015)
Montney
9,300 well locations
Duvernay
― Major portfolio transformation
― Overhauled capital allocation process
― Continued demonstration of operational excellence
― Reset costs and corporate culture
• Inflection (2016)
― Strengthened balance sheet to support growth
•
Further divestitures and equity issuance
― Industry leading efficiencies
• Growth (2017+)
― Premium portfolio + operational excellence + financial capacity
= low-risk, high-growth, quality corporate returns
Permian
Eagle Ford
600 well locations
*Total inventory is unrisked and assumes various spacing across each play
2
1
ENCANA
The Growth Phase Begins Now
TOP TIER
RESOURCE
• Strategy Elements
MARKET
FUNDAMENTALS
― Balanced commodity mix
― North American resource play focus
― Unconventional development expertise
― Multi-basin portfolio advantage
BALANCE SHEET STRENGTH
• Foundation Elements
― Culture of innovation
― Organizational structure aligned with strategy
― Financial and operational discipline
OPERATIONAL
EXCELLENCE
CAPITAL
ALLOCATION
3
ENCANA
Quality Returns & Leading Growth (2016 – 2021)
Delivering quality
returns
World class asset
portfolio
Resilient business
model
>300% cash flow* growth
>60% production* growth
5 year plan consumes
small fraction of premium
inventory locations
Competitive cost
structures
Corporate margin
doubles
Core four well returns
>35% ATROR**
* Assumes flat $55/bbl WTI and $3/MMBtu NYMEX; ** Assumes flat $50/bbl WTI and $3/MMBtu NYMEX .
Balanced commodity mix
Strengthened financial
capacity
4
2
PRODUCTION GROWTH TRAJECTORY
Production (MBOE/d)
Growing High Margin Volumes
650
• >60% total company production* growth
― Permian grows ~3x – 4x
550
― Montney liquids grow ~4x – 5x, gas grows ~2x
450
― Combination of Eagle Ford and Duvernay production
stays relatively flat
350
• 15% – 20% liquids CAGR
• Corporate margin doubles
250
2016F
2017F
2018F
2019F
2020F
2021F
Corporate Margin $/BOE*
― Core four becomes >90% of total company production
― Commodity mix becomes balanced between liquids and
natural gas
― >50% increase in corporate margin 2017 to 2018
*Assumes flat $55/bbl WTI and $3/MMBtu NYMEX. 2016 production does not include volumes from assets divested in 2016.
Refer to advisory for definition of corporate margin. **Impact of higher volumes on PMOT, T&P and Operating Expense.
55
5 YEAR CAPITAL & CASH FLOW OUTLOOK
Self-Funding Capital Program Post 2017
Cash Flow ($MM)
• >300% cash flow* growth
― Focus on high margin production amplifies cash
flow growth
• Self funding post 2017
― Cash flow exceeds capital program at $55 WTI
and $3 NYMEX
• Multi-basin portfolio advantage
― Enables flexible and efficient deployment of
capital
4,000
3,000
2,000
1,000
-
2016F
2017F
2018F
2019F
2020F
2021F
2020F
2021F 6
Capital ($MM)
4,000
3,000
2,000
1,000
-
* Assumes flat $55/bbl WTI and $3/MMBtu NYMEX
2016F
2017F
2018F
2019F
3
ENCANA
Delivering Quality Returns
• Leading growth
TOP TIER
RESOURCE
MARKET
FUNDAMENTALS
― >300% cash flow growth over 5 year plan
• World class assets
― 10,000 premium return inventory locations
• Efficiency
― Focus on innovation to continuously improve capital and
operating efficiency
• Returns and margins
― Grow cash flow by expanding margins and allocating capital to
assets that deliver strong corporate returns
• Actively managed balance sheet
― Provides flexibility and funding capacity
OPERATIONAL
EXCELLENCE
CAPITAL
ALLOCATION
7
4
ENCANA CORPORATION
Resource in Context
David Hill
Executive Vice President, Exploration and Business Development
ENCANA
TOP TIER
RESOURCE
MARKET
FUNDAMENTALS
• Leading growth
― 10,000 premium return locations
• Efficiency
― Grow cash flow by expanding margins and allocating
capital to assets that deliver strong corporate returns
OPERATIONAL
EXCELLENCE
CAPITAL
ALLOCATION
2
5
RESOURCE IN CONTEXT
Encana’s World Class Portfolio
Montney
Duvernay
• Core positions in four of North America’s premier basins
• Resource rich basins with significant upside
• Growing inventory through technical excellence in each play
since entering
Core Four Assets
Permian
Stacked resource potential located in
heart of oil-rich Midland basin
Eagle Ford
Oil weighted top-tier asset generating
significant cash flow with flexibility
Duvernay
A premier position in a leading, emerging
condensate rich play
Montney
Stacked resource potential with extensive
liquids and gas optionality
• Liquids rich & oil assets
• Competitive supply costs
• Running room and
scalability
• Access to markets
Permian
Eagle Ford
600 well locations
*Total inventory is unrisked and assumes various spacing across each play
3
RESOURCE IN CONTEXT
Encana Holds Core Positions in Premier Basins
Horizontal Rig Activity* by Play
180
150
120
ECA Core Asset
Active Basin Oil Rig
Active Basin Gas Rig
90
60
30
0
ECA portfolio focused entirely on unconventional plays
utilizing similar technology
Source: RigData, IHS, GeoScout, and RS Energy, Inc as of Sept 2016
4
6
BEST ROCKS APPROACH TO PORTFOLIO
Deliberate and Disciplined Evaluation
Geoscience, Engineering & Data Driven Approach
Basin Focus
Resource potential
Geologic setting
Market access
Play Focus
Geology
Petrophysics
Rock Mechanics
Engineering
Resource in place
Hydrocarbon phase
Highest deliverability
Position Focus
Best rocks
Scale with upside
Operational excellence
5
Highest Quality
Reservoir
CORE POSITIONS IN THE BEST ROCKS
Building of a Premium Return Inventory
Montney
Permian
10 - 45 MMBOE/sec
Up to 6 stacked laterals
>200 MMBOE/sec
Non-Reservoir
ECA Position
Glasscock
Tower & Dawson South
Howard
Midland
3,000’
1,000’
Pipestone
Martin
Duvernay
Eagle Ford
Up to 25 MMBOE/sec
Pinto
Edson
30 - 50 MMBOE/sec
Willesden Green
Karnes County
250’
140’
Simonette
6
7
ENCANA WELL INVENTORY
Significant Growth
Total Encana Inventory
25,000
• >20,000 locations
Current
Inventory • ~10,000 premium
locations
Inventory Count
20,000
15,000
10,000
2014
• ~10,000 locations
Inventory
5,000
0
2014
Permian
Current
Montney
Duvernay
Eagle Ford
7
Change in total inventory is a function of different variables including, but not limited to, spacing and stacking.
ENCANA’S PREMIUM RETURN INVENTORY
Only Premium Inventory Consumed In Growth Plan
Permian Basin
Montney
10,000 well inventory
2,750 premium locations
~1,000 wells drilled in 5 year plan
5,900 premium locations
~850 wells drilled in 5 year plan
Premium assumption
660’ spacing on average of 2 ¼ zones across
basin
Premium assumption
440’ spacing in very rich gas condensate
660’ spacing in rich gas condensate
Eagle Ford
Duvernay
600 well inventory
130 premium locations
500 premium locations
Premium assumption
330’ spacing
Premium assumption
1,000’ spacing
*Premium locations are >35% IRR at $50 WTI & $3.00 NYMEX
8
8
RESOURCE IN CONTEXT
Permian
Texas
• Premier North American oil play
– Heavily weighted to liquids (~80% of production)
– Productive intervals spanning over 5,000’ of stratigraphy
• Inventory continues to expand
– De-risking new zones
Midland
– Understanding stacking and spacing of laterals
• Exceptional performance from multiple zones
across the basin
– Acreage situated in core of the core of the Midland Basin
Encana Land
Basin Core
– Running room across the play provides upside as new zones
across the play emerge
30 miles
9
RECENT TRANSACTIONS SUPPORT QUALITY
2016 Industry Deals in Glasscock, Howard and Martin Counties
Texas
June 2016
QEP Resources / RK Petroleum
August 2016
SM Energy / Rock Oil
Implied Acreage Value: ~$59,000/acre*
August 2016
August 2016
Callon Petroleum / Big Star Oil and Gas
Concho Resources / Reliance Energy
Midland
August 2016
Parsley Energy / BTA
Encana Land
Basin Core
30 miles
*Implied acreage value calculated based on transaction value less the estimated value of purchased production based on $35,000/BOE/d
10
9
PERMIAN RESERVOIR
Massive Potential with Stacked Horizons
Zone
Martin
Midland*
Clear Fork















M. SPBY
L. SPBY
L. SPBY- 2nd
WCMP A
WCMP A- 2nd

WCMP B
WCMP C

WCMP D / Cline
Deep Targets
Glasscock
Howard












Total Inventory
1,800
3,300
1,300
3,600
Premium
650
1,140
260
700
*Midland includes Upton County
11
PERMIAN WELL PRODUCTIVITY
Encana Average IP180 >500 BOE/d
Core acreage matters – innovation and efficiency
distinguish operators within the core
700
IP180 (bbls/d, BOE/d)
600
500
400
300
200
100
0
Core Midland
Non Core Midland
Oil
Oil
Gas
Gas
Data sourced from IHS, Inc. Results normalized to 7,500’, includes all data from 2014 onward. Peers include APA, AREX, CPE, CVX, CXO, DVN, EGN, END, EOG, EPE, FANG, LPI, OXY, PE, PXD, QEP, RSPP, SM, and XOM
12
10
RESOURCE IN CONTEXT
Permian
• Core position with scale within a premier North
American play
Total Inventory
10,000 locations
• Encana’s innovation and efficiency are converting
inventory to premium return inventory
Premium
2,750 locations
Remaining
Inventory
– Continuous improvement of cost structure
– Downspacing pilots beyond 660’ have the potential to
significantly increase resource potential
40% of premium inventory
consumed through 2021
– Stacking of laterals is optimizing resource recovery
• Large part of Encana’s growth strategy
– Premium return inventory well beyond five year plan
Premium
Inventory
~140,000 net acres
13
RESOURCE IN CONTEXT
Eagle Ford
San Antonio
• Strategically positioned in the Karnes
Trough
Texas
– Best rock in the Eagle Ford
– Most active and profitable trend in the Eagle
Ford
• Well inventory improving since entry
– 600 total inventory locations
– 130 premium horizontal well inventory
– Stacked pay, infill spacing & Austin Chalk offer
premium inventory upside
Encana Land
Basin Core
30 miles
14
11
STACKING WELLS IN THE EAGLE FORD
Play Continues to Expand
Austin
Chalk
Gr
RD
RHOB
Austin Chalk
First Encana wells on stream for less than 30 days
No current inventory
Eagle Ford
Eagle Ford
250'
600 well inventory, 130 premium return locations
Upper Eagle Ford
Now developing Upper Eagle Ford targets optimized with
existing lower Eagle Ford development
Lower Eagle Ford
Infilling successfully at 330’ spacing or tighter
15
RESOURCE IN CONTEXT
Eagle Ford
• Positioned within the most active and
profitable trend
• Well inventory has significantly improved
since acquisition
• Inventory upside as Upper Eagle Ford
and Austin Chalk develop
Total Inventory
600 locations
Premium
130 locations
Remaining
Inventory
~100% of premium inventory
~43,200 net acres
16
12
RESOURCE IN CONTEXT
Duvernay
Alberta
Encana Land
Core
Reef
• Encana holds a large contiguous land base
within the core of the play
– Significant growth opportunity
– 1,000 total locations, 500 premium locations
Simonette
North
Fox
Creek
• Encana focusing on Simonette region as the
best rocks in play
• Industry leading condensate production from
high quality reservoir
Simonette
South
• Robust condensate market that receives WTI
pricing
12 miles
17
SIMONETTE IS THE CORE OF THE DUVERNAY
Encana Holds Large Core Position
Significant overpressure enhances deliverability
from thick resource rich section
Condensate Ratio
(bbls/MMcf)
Simonette North
Simonette South
Volatile Oil
>250


Very Rich Gas
Condensate
150 – 250


Rich Gas
Condensate
50 – 150


Gas
Condensate
20 – 50


12,500
12,460
Area
Inventory
1,000
Premium
Inventory
500
18
13
RESOURCE IN CONTEXT
Duvernay
• A premier position in a leading, emerging liquids
rich play
• Encana investing into 2 key areas
− Simonette North – leading the industry in cost performance
Total Inventory
1,000 locations
Premium
500 locations
Premium
Inventory
− Simonette South – deeper, more prolific, highest rate wells
in the play
Remaining
Inventory
• Encana’s innovation and efficiency in the play are
moving inventory to premium return inventory
− Continuous improvement of cost structure to wells costing
less than $7MM
− Down-spacing pilots beyond 1,000’ have potential to
significantly increase inventory
5 Yr Plan
~97,000 net acres*
(335,000 total net acres)
*Duvernay development focused on Simonette
19
RESOURCE IN CONTEXT
Montney
• Massive inventory
– Stacked resource parallels the Permian development
– Wells up to 2.5 MMBoe, IP >2,500 BOE/d
• Optionality among fluid windows
– Not a shale; highly productive across all fluid windows
Tower
– Condensate window offers substantial liquids rich opportunity
Dawson
South
Pipestone
• Pipestone is an emerging Alberta Montney
liquids core area with significant scale
20
14
MONTNEY STACKED RESOURCE
Growing Stack of High Quality Liquids Rich Montney
(up to 6 laterals)
(up to 4 laterals)
650’ Montney
Pipestone
1,000’ Montney
Tower/Dawson
Condensate rich zones fuel premium inventory
Zone
Condensate
Ratio
(bbls/MMcf)
Tower
Dawson
South
Pipestone
Volatile Oil
>250

Very Rich Gas
Condensate
150 – 250

Rich Gas
Condensate
50 – 150

Gas Condensate
20 – 50
Wet Gas
<20
Dry Gas
0







Inventory
9,300
Premium
Inventory
5,900
21
RESOURCE IN CONTEXT
Montney
• Premium return inventory economics driven
by liquids
– Condensate receives WTI pricing in Canada
– Liquids rich inventory amongst best wells in Encana’s
portfolio
• Liquids growth drives margin expansion over
the five year plan
• Significant gas optionality
Total Inventory
9,300 locations
Premium
5,900 locations
Premium
Inventory
Remaining
Inventory
~240,000 net acres*
(484,000 total net acres)
*Montney development includes Tower, Dawson South & Pipestone
22
15
ENCANA PORTFOLIO POSITIONED FOR GROWTH
Top Tier Resource Portfolio Aligned With Strategy
World Class Multi-Basin Portfolio
Permian
Eagle Ford
Duvernay
Montney
Massive Premium Return Inventory
>20,000 Well Inventory
10,000 Premium Return Wells
Unlocking Resource Potential
~15 Billion BOE
(Unrisked resource potential)
23
16
ENCANA CORPORATION
Operational Excellence
Michael McAllister
Executive Vice President & Chief Operating Officer
ENCANA
• Leading growth
TOP TIER
RESOURCE
MARKET
FUNDAMENTALS
– >300% cash flow growth
• Efficiency
CAPITAL
ALLOCATION
OPERATIONAL
EXCELLENCE
2
17
OPERATIONAL EXCELLENCE
Maximizing Capital & Operating Efficiency
PORTFOLIO ADVANTAGE
INNOVATION
Multi-play company creates enormous
flexibility
R&D lab is the field
CONTINUOUS IMPROVEMENT
COMPETITOR BENCHMARKING
Rapid adoption of best ideas &
technology in industry
Structured approach to change
Up to
40% reduction in D&C costs
from 2015 averages
3
SAFE OPERATIONS ARE EFFICIENT OPERATIONS
ECA Leading Safety Results
Total Recordable Injury Rate (TRIR)
2.5
2
1.5
1
0.5
0.28
0
TRIR
*Data sourced from the American Exploration & Production Council (AXPC). Includes all US E&P members of AXPC.
P10
P50
4
18
D&C Cost Momentum Continues to Build
Permian
Montney
$MM
$MM
7
8
6
5
4
3
ECA
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
2
Peer 8
Peer 1
ECA
Eagle Ford
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Duvernay
$MM
$MM
6
20
16
4
12
8
2
4
Peer 1
ECA
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
ECA
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Leading D&C cost performance
*All D&C cost data sourced from peer public presentations, normalized to industry standard lengths (Permian 7,500’, Eagle Ford 5,000’, Montney 9,000’, Duvernay 8,200’)
5
LOWER COSTS FASTER
D&C Cost Momentum Continues to Build
Permian D&C Costs*
10
• ~40% D&C cost reduction
over 6 quarters
9
• Improving at a faster rate
than peers
$MM
8
7
– Driven by innovation
6
• Pacesetters become the
new target
5
4
Q1
Q2
Q3
Q4
2015
Q1
Q2
2016
Encana
Peer
*All D&C cost data sourced from peer public presentations; data normalized to 7,500’; Peers include: EGN, FANG, LPI, OXY, PE, PXD, QEP and RSPP
6
19
D&C COST REDUCTIONS SINCE 2014
Drivers of Success
%
decrease
Drivers
Key Accomplishments
Reduced drilling days
25%
Faster trip times & improved bit and motor design
Drilling design breakthroughs
20%
Simplified casing design, improved cementing programs
Increased pumping time per day
10%
Zipper fracs, reduced maintenance turnaround times
Completion design breakthroughs
10%
Dissolvable bridge plugs, reduced coil tubing interventions
Streamlined logistics
5%
Water infrastructure, sand boxes
Service cost reductions
30%
Unbundling services and competitive bidding
7
WELL PRODUCTIVITY
IP180 Well Performance
Gas (BOE/d)
Oil (bbls/d)
Encana
Montney*
1250
500
1000
Permian
600
400
300
200
100
750
500
250
0
0
Duvernay*
Eagle Ford
1000
800
600
400
200
0
800
600
400
200
0
ECA
*Data sourced from RS Energy Group, raw data provided by geoSCOUT.
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
8
20
Reducing Operating Costs
Permian
Montney
$2.00
$20
$1.60
$/BOE
$/BOE
$15
$10
$5
$1.20
$0.80
$0.40
$0
Q1 15
Q2 15
Q3 15
Q4 15
Q1 16
$0.00
Q2 16
Q1 15
Q2 15
Q4 15
Q1 16
Q2 16
Q1 16
Q2 16
Duvernay
$10
$10
$8
$8
$/BOE
$/BOE
Eagle Ford
Q3 15
$6
$4
$6
$4
$2
$2
$0
$0
Q1 15
Q2 15
Q3 15
Q4 15
Q1 16
Q2 16
Q1 15
Q2 15
Q3 15
Q4 15
9
ENCANA INCOME MARGIN
All-In Profitability
2017-2021 ECA Income Margin
$/BOE
• Premium returns at the corporate level
– Locations in the plan deliver an average of
~$25/BOE operating margin
– NRI F&D ~$8.00/BOE
30
25
$8.00/
BOE
20
$0.60/BOE
– Non-well capital of $0.60/BOE
15
– G&A and interest expense ~$3.00/BOE
10
– Income margin at the corporate level of
over $13.00/BOE
$25.00/BOE
$3.00/BOE
>$13.00/
BOE
5
0
Operating Margin
Non-well Capital
Income Margin
F&D
Overhead
10
21
5 YEAR OUTLOOK
Self-Funding Post 2017
Production (MBOE/d)
650
550
• Focus on high margin production
450
• Continuous improvement drives high
returns
350
• Production growth of >60%*
• Leading D&C costs sets up self-funding
post-2017
250
2016F
2017F
2018F
2019F
2020F
2021F
Capital ($MM)
4,000
3,000
2,000
1,000
-
* Assumes flat $55/bbl WTI and $3/MMBtu NYMEX. 2016 production does not include volumes from assets divested in 2016.
2016F
2017F
2018F
2019F
2020F
2021F11
22
ENCANA CORPORATION
Market Access & Margin Expansion
Renee Zemljak
Executive Vice President, Midstream, Marketing & Fundamentals
ENCANA
• Leading growth
– >300% cash flow growth
MARKET
FUNDAMENTALS
TOP TIER
RESOURCE
• Efficiency
OPERATIONAL
EXCELLENCE
CAPITAL
ALLOCATION
2
23
DRIVING VALUE, EXPANDING MARGINS & DE-RISKING GROWTH
Strategic and Integrated Midstream and Marketing Approach
• Detailed and proprietary analysis of all North American basins
– Integrated cross-functional team
– Scenario-based with sensitivity analysis
– Long term production profiles of all commodities
• Market access and constraint risk analysis
– De-risk Encana’s growth opportunities
– Manage flow risk and optimize wellhead netback
• Commercial focus delivers risk-adjusted value
– Structures designed to minimize commitments and maximize flexibility
– Multiple transportation routes from plays and basins
– Diversified portfolio of physical sales
3
NORTH AMERICAN NATURAL GAS & OIL FUNDAMENTALS
Driving Value – Wellhead to Market
• Value drivers for our Canadian assets
– AECO Pricing dynamics
– Infrastructure connectivity and market access
– WCSB Condensate market fundamentals
• Key fundamentals related to our Texas assets
– Connectivity to market
– Permian infrastructure development
• Regional fundamentals and price risk mitigation
– AECO
– Midland differential
4
24
WESTERN CANADIAN MARKET FUNDAMENTALS
Natural Gas Export Basin – Premium Condensate Market
Western Canadian Sedimentary Basin
(WCSB)
Nova Gas
Transmission
System
Growing
WCSB
demand
•
•
•
•
•
•
Oil Sands
Demand
(Gas/diluent)
Condensate
Imports
~225 Mbbl/d
Condensate to
Edmonton
market center
To Pacific
Northwest (Malin)
4.1 Bcf
~15 Bcf/d of natural gas production
~5.5 Bcf/d of regional demand
500 Bcf of working storage
11.7 Bcf of gas export capacity
~225 Mbbl/d condensate production
~450 Mbbl/d condensate demand
To Eastern Canada
(Dawn) 4.2 Bcf
Natural Gas Export Pipeline
To U.S. Midwest
(Chicago) *3.4 Bcf
Condensate Import Pipeline
Source: Encana Fundamentals, RBC Capital Markets, Various Pipeline Postings; *Net Effective Capacity (Bakken Access)
5
WESTERN CANADIAN NATURAL GAS FUNDAMENTALS
Required Exports - Existing Infrastructure More than Sufficient for Growth
Bcf/d
13
12
11
Excess Capacity
10
9
8
7
6
Historical
Forecast
5
4
2012
2013
2014
2015
WCSB Net Exports
Source: Encana Fundamentals, IHS
2016F
2017F
2018F
2019F
2020F
Export Capacity
Available capacity exceeds required exports
throughout the forecast period
6
25
WESTERN CANADIAN NATURAL GAS FUNDAMENTALS
AECO Basis - Forward Market Trends Toward Historical Levels
$US/MMbtu
• AECO basis has averaged ~$(0.50) from
2009 through the present
$0.50
$0.00
• Current market dramatically affected by
winter 2015-2016 (one of the warmest
on record)
($0.50)
• Market sees a gradual tightening
toward more historical levels
($1.00)
($1.50)
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Forward Market
Historical Market
• Encana planning case reflects
conservative scenario $(0.90)
Planning Case
7
Source: Encana Fundamentals, NGX, CME Group
million bbls/d
WESTERN CANADIAN CONDENSATE FUNDAMENTALS
Premium Condensate Market
0.65
0.6
0.55
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
0
Forecast
Condensate
Demand
Implied
Condensate
Imports
Condensate
Production
2000
2002
Source: RBC Capital Markets and Government Data
2004
2006
2008
2010
2012
2014
2016E
2018E
2020E
Historical
Forecast
Condensate demand in Western Canada is expected to outstrip
indigenous supply – with imports bridging the gap
8
26
PERMIAN BASIN FUNDAMENTALS
Past & Future Pipeline Capacity Expansions Align with Growth
Forecast
Source: Wells Fargo Securities
9
MIDLAND DIFFERENTIAL
Basis Reconnects on Infrastructure Development
$US/Bbl
• Midland basis historically maintained
a close connection to WTI
$4.00
$2.00
$0.00
• Infrastructure additions have paced
supply since late 2014 yielding a
differential in line with historical
norms
($2.00)
($4.00)
($6.00)
($8.00)
• The market is expecting pipeline
development to continue to keep pace
with future growth
($10.00)
($12.00)
($14.00)
2010
2011
2012
2013
Forward Market
Source: Encana Fundamentals, CME Group
2014
2015
Historical Market
2016
2017
2018
Planning Case
10
27
DRIVING VALUE, EXPANDING MARGINS & DE-RISKING GROWTH
Summary of Midstream and Marketing Focus
• Ensure market access
– Creation of flexible and reliable midstream strategies and transactions
– Maintain diversified sales portfolio (including physical and synthetic transportation)
• Maximize price realizations
– Netback optimization, active management of sales portfolio
– Financial price risk mitigation (active basis and benchmark price hedge programs)
• Support growth objectives, maintain capital flexibility
– Minimize commitments in order to yield capex flexibility
– Risk management program reduces cash flow volatility and manages balance sheet risk
11
28
ENCANA CORPORATION
Permian Basin
Jeff Balmer, PhD
Vice-President & General Manager, Area Operations
PREMIER NORTH AMERICAN BASIN
Permian Basin
• Core acreage within top quality basin
–
Acreage situated in northern/central sweet spot of the Midland Basin
–
Productive intervals spanning over 5,000’ of stratigraphy
• D&C cost leader
–
D&C costs down from >$8 MM to less than $5 MM since entering the basin
–
Performing amongst the top operators
• Highly productive wells
–
Top tier well performance
• Innovation at work
–
Proving up multiple benches/stack
–
Pushing the envelope on completions design/spacing
• Operating performance
–
Operating costs down 35% since entering the basin
–
<$3.00/BOE for Hz wells
Total Inventory
10,000 locations
Premium
Inventory
Premium
2,750 locations
Remaining
Inventory
2
29
ENCANA IS THE 2nd LARGEST PRODUCER
Core Midland Basin Producers at a Glance
Midland Basin
Encana Gross Production vs Peers
Gross Operated Production (BOE/d)
60,000
Texas
104
50,000
40,000
Midland
30,000
20,000
10,000
Encana Land
Basin Core
0
30 miles
PXD ECA OXY FANG EGN XOM APA CVX QEP LPI RSPP END CXO CPE BBEP
Source: Drilling Info, Inc., all production from Glasscock, Howard, Midland and Martin
Drilling Days vs Depth
PERMIAN CAPITAL EFFICIENCY
Better Wells For Lower Costs
– Down from >$8MM/well since entering the basin
– Performing amongst the top operators
• 45% reduction in drilling days
Days
0
15
20
25
30
10,000
15,000
20,000
Normalized D&C Cost/1,000’ vs Peers**
– Shortened intermediate casing string
0.8
MM$/1000’
1.0
– Advanced survey tools
10
Pacesetter
2016 YTD Average
2015 Average
2014 Average
5,000
– Mud system improvements
– More efficient bottom hole assemblies and mud motors
5
0
Measured Depth (ft)
• Current D&C well costs of $4.9 MM/well
3
0.6
0.4
0.2
0.0
ECA
*Normalized to 7,500’. **Data sourced from latest peer IR presentations. Peers include APA, CPE, FANG, LPI, OXY, PE, PXD, QEP, RSPP, and SM
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8
4
30
WELL PRODUCTIVITY
Encana Wells Outpacing Peer Results
600
500
400
300
200
100
0
Gas
Oil
Data sourced from IHS, Inc. Results normalized to 7,500’, includes all data from 2014 onward. Peers include APA, AREX, CPE, CVX, CXO, DVN, EGN, END, EOG, EPE, FANG, LPI, OXY, PE, PXD, QEP, RSPP, SM, and XOM
5
WOLFCAMP
Midland/Upton County
Midland/Upton WCA Type Curve
IP30 = 700 BOE/d
6 mo. Oil Cum = 90 MBO
EUR = 900 MBOE
D&C = $5.1 MM
Lateral Length = 7,500 ft
RAB Davidson 14
Well Pad Average
Type Well Metrics – ECA Net
All metrics based on $3.0/MMBtu NYMEX, $55/bbl WTI
Atax IRR (%)
50%
Operating Margin ($/BOE)
$30
6
31
INNOVATION SUCCESS
Large Scale Pad Development
Davidson Pad Project Stats
Well Count
14
Target Zone
Wolfcamp
– Shared well site facilities
Average Spud-RR
16.4 days
– Minimized surface footprint
Average Lateral Length
8,630 ft
– Reduced non-productive time
Average Completion
1,500 ppf, 2,000 gal/ft
Average D&C Cost
$5.7 MM
Pad spud to first production
120 days
• $1.2 MM/well savings from pad development
– Logistical efficiencies
• Accelerated drilling learning curve
Davidson 14-well Pad Representation
• Increased completion intensity
• Eliminate future in-fill drilling
– Drain the basin without drilling through depleted reservoir
– Minimize interruptions on producing wells
7
LOWER SPRABERRY
Martin, Midland/Upton, Howard, Glasscock
Martin
Martin County Holt Ranch 1702H
(Currently Encana’s best well)
Martin Lower Spraberry Type Curve
IP30 = 600 BOE/d
6 mo. Oil Cum = 85 MBO
EUR = 850 MBOE
D&C = $5.1 MM
Howard
Midland County Abbie Laine H303M
Midland
Glasscock
Glasscock County Cooper 34 2H
Upton
Howard County Ward 17B H1705
Atax IRR (%)
45%
$30
8
32
INNOVATION SUCCESS
Identifying Optimal Completion Design and Geometry
– Better ultimate recovery
– Less interference between wells
Frequency X-Axis
1000
600
600
-200
Z Position (ft)
200
-600
-1000
-1000
Frequency Z-Axis
• High proppant completions maximizes
wellbore conductivity
High Proppant Concentration
Frequency X-Axis
Frequency Z-Axis
• Low proppant completions inefficiently
stimulate a large area
Low Proppant Concentration
1000
Z Position (ft)
• Microseismic work identified optimal
completion intensity
200
-200
-600
-600
-200
200
X Position (ft)
600
-1000
-1000
1000
-600
-200
200
X Position (ft)
600
1000
Lower Well Costs
and
Better Ultimate Recovery
9
EXPANDING MARGINS
• Improving efficiencies
– Company-wide effort
– Accountability at the operator level
• Working smarter
– >80% of produced water on pipe
– >70% of production on remote monitoring and control
• Negotiating the best price
Permian Operating Cost Reductions
$/BOE
$18
$16
$14
$12
$10
$8
$6
$4
~40%
Improvement in
operating costs
$2
$0
Q1
Q2
Q3
Q4
2015
Average
Horizontal Well Opex
Q1
Q2
2016
Vertical Well Opex
10
33
INNOVATION SUCCESS
Water Integration and Recycling
• Self sufficient water supply
–
Reduced dependency on third-party water supply
–
Flexibility to support development schedules
–
Reduced well costs and operating expense
Portable Water Treatment Plant
• Recycling pilots completed to determine
optimal design
–
3-well pad in Martin County
–
17% of water recycled during completions
–
Up to 25,000 barrels of water per day
11
PERMIAN INCOME MARGIN
2017-2021 Income Margin
– Locations in the Permian deliver ~$30/BOE
operating margin
$/BOE
35
30
25
20
15
– Permian income margin at the corporate level
of over $17.00/BOE
10
$30.00/BOE
$9.00/
BOE
$0.60/BOE $3.00/BOE
>$17.00/
BOE
5
0
Operating Margin
Non-well Capital
Income Margin
F&D
Overhead
12
34
MIDSTREAM AND MARKETING OVERVIEW
Permian
Gathering system
links production to
pipeline hubs
Colorado
City
Pipelines
connect to
Cushing and
Gulf Coast
Midland
Crane
Permian
Permian: Proximity to
market and environment
of responsive
infrastructure
development
Secured capacity on
Enterprise (Echo
Pipeline) adds
market diversity and
reduces physical risk
(2018)
• Majority of oil production gathered via
pipeline with access to multiple physical
markets
• Firm gas gathering and NGL processing
with access to WAHA and Mt. Bellvieu
markets
• Secured firm, low-cost pipeline capacity
to Gulf Coast refining/export markets
(Enterprise Echo Pipeline 2018)
• No take or pay commitments
13
ENCANA PERMIAN
5 Year Growth Profile
Five Year Production Profile
180
• >50% of Encana’s capital directed to the
Permian
160
• Permian production expected to grow 3-4x
140
‒ 5 year CAGR 30%
• No infrastructure or midstream limitations
• Minimal vertical program
120
MBOE/d
• Quality inventory with scale
100
80
60
40
20
2016F
2017F
2018F
2019F
2020F
2021F
14
35
ENCANA CORPORATION
Montney
Jim Roberts
Vice-President & General Manager, Northern Operations
ENCANA IN THE MONTNEY
A Premier North American Play
• Encana’s Montney is a condensate play
– 5,900 premium condensate-rich inventory*
• Stacked horizontal development
Tower
Dawson
South
– Over 1,000’ of pay, up to 6 stacked horizons
• 5 year growth plan
– Increase margins through condensate growth
•
Grow liquids to >50,000 bbls/d by end of 2018
•
30% liquids CAGR through 2021
– Consuming 15% of premium wells through 2021
• Basin leading operator
– Largest producer in the Montney
– Top well performance
– Most efficient operator with track record of innovation
– Longest laterals with highest completion intensity
*Estimated inventory based on 440 - 880 ft spacing
Pipestone
Encana Core Montney
Encana Non-core Montney
Total Inventory
9,300 locations
Premium
5,900 locations
Premium
Inventory
Remaining
Inventory
2
36
ENCANA IS THE LARGEST MONTNEY PRODUCER
Montney Producers at a Glance
Montney
Gross Production vs Peers
Gross Operated Production (MMcf/d)
1,200
1,000
800
600
400
200
0
ECA net production
ECA gross production
Peer gross production
Source : Industry data
3
CONTINOUS IMPROVEMENT
Reducing Drilling & Completion Costs
Quarterly D&C Performance*
• Significant reduction in drilling &
completion costs
– Increased lateral drilling efficiencies
6.4
6
$MM
– New bit designs
8
5.0
4.2
2016 Q2
Pacesetter
2
– 30% reduction in cycle time
0
– Domestic frac sand reducing costs ~55%
2015 Average
• Vendor cost reductions
2016 Q1
Peer D&C Costs
– 3.5% of the total well costs in 2016
1.0
0.8
$MM/1000’
– Revised rig contracts to reduce 2017 costs by
$150k per well
4.3
4
0.6
0.4
0.2
0.0
Peer 1
*D&C Costs normalized to 9,000 ft lateral length
ECA
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
4
37
WELL PRODUCTIVITY
Top Performance vs Peers
ECA 2017 focused on higher margin, higher
return condensate rich wells
1,400
1,200
ECA 2017 plan
85 bbls/MMcf
1,000
800
600
400
200
0
Oil
Gas
Data sourced from RS Energy Group, raw data provided by geoSCOUT.
5
ENCANA PIPESTONE
Significant Condensate & Oil Production
• Situated in core of Alberta Montney
Pipestone Acreage
Stacked HZ Dev.
• Oil resource of ~45 MMbbls/section
G
r
• ~90,000 contiguous acres, 98%WI
RD
RHOB
PIPESTONE
• ~2,400 premium well inventory
• Condensate ratios up to 300
bbls/MMcf
~650’
British Columbia
Alberta
• Up to 4 stacked HZ horizons
5mi / 8km
PIPESTONE
Encana Land
Basin Core
40mi / 65km
Condensate Rich/Oil Trend
Encana Pipestone Acreage
HZ Development
6
38
VOLATILE OIL (>250 bbls/MMcf)
Pipestone Well Performance
Type Curve
IP180 Condensate = 850 bbls/d
IP180 Gas = 2.7 MMcf/d
EUR = 1.4 MMBoe
D&C = $4.0 MM
500
Cumulative MBOE
400
Pipestone Acreage
12-25 Well
14-1 Pad
(5-31, 5-14)
12-25
300
14-1 Pad
5-14 and 15-31 wells
200
5mi / 8km
2017 Type Curve
12-25-071-09
15-31-071-08
05-14-072-09
100
0
0
30
60
90
120
150
180
210
240
270
300
Producing Days
330
Atax IRR (%)
120%
$19
7
All metrics based on $3.0/MMBtu NYMEX, $55/bbl WTI, and $0.75 FX, $0.90 AECO basis differential
ENCANA TOWER
Robust Condensate Production
• Located in core of central region
Condensate Acreage
– Active area for industry
– Condensate and oil development
TOWER
~1,000’
Condensate ratios up to 250 bbls/MMcf
~64,000 contiguous acres, 60% WI
~2,400 premium well inventory
Up to 6 stacked HZ horizons
British Columbia
Alberta
•
•
•
•
Stacked HZ Dev.
TOWER
Condensate Rich Trend
Encana Tower Acreage
Encana Land
Basin Core
40mi / 65km
HZ Development
8
39
RICH GAS CONDENSATE (50-150 bbls/MMcf)
Tower Well Performance
2-12 Pad
5-1 Pad
Type Curve
EUR = 1.4 MMBOE
D&C = $3.7 MM
Cumulative MBOE
500
400
2-12 Pad
5 well average
300
5-1 Pad
4 well average
5mi / 8km
200
Type Curve
Upper Montney Type Well Metrics – ECA Net
02-12 Pad
100
05-01 Pad
Atax IRR (%)
0
0
30
60
90
120
150
180
210
240
270
300
Producing Days
330
Leveraged
Unleveraged
>200%
60%
$13
$13
Operating Margin
($/BOE)
9
All metrics based on $3.0/MMBtu NYMEX, $55/bbl WTI, $0.75 FX, and $0.90 AECO basis differential
ENCANA DAWSON SOUTH
Emerging Condensate Rich Acreage
• Located in core of central region
Emerging Condensate Acreage
– Low risk, high value future growth potential
– Dry gas optionality
DAWSON
SOUTH
Encana Land
Basin Core
40mi / 65km
RD
RHOB
~1,000’
Condensate ratios up to 50 bbls/MMcf
~87,000 contiguous acres, 60% WI
~1,100 premium well inventory
Up to 5 stacked HZ horizons
G
r
British Columbia
Alberta
•
•
•
•
Stacked HZ Dev.
DAWSON
SOUTH
Condensate Rich Trend
Encana Dawson South Acreage
HZ Development
10
40
GAS CONDENSATE (20-50 bbls/MMcf)
Dawson South Well Performance
9-35 Pad
700
Type Curve
EUR = 1.6 MMBOE
D&C = $4.1 MM
600
Cumulative MBOE
500
400
12-05 & 9-35 Pads
(2 well average)
4-17 Pad
12-5 Pad
4-17 Pad
(1 well)
300
5mi / 8km
200
Lower Montney Type Well Metrics – ECA Net
Lower Montney Type Curve
100
Leveraged
Unleveraged
Atax IRR (%)
>200%
65%
Operating Margin
($/BOE)
$10.5
$10.5
04-17 Unconstrained
12-05 & 09-35 Pad
0
0
60
120
180
240
300
360
420
480
Producing Days
11
All metrics based on $3.0/MMBtu NYMEX, $55/bbl WTI, $0.75 FX, and $0.90 AECO basis differential
ENCANA MONTNEY
Operating Cost Performance
• Workforce collaboration across the asset
– Optimizing water handling
– Managing field work using work orders and integrated
scheduling
– Leveraging technology through the operation command
center field office
Significant Reduction in Operating Expense
• Evaluating key contracts with suppliers &
contractors
2.00
1.60
• Scope of work reductions
– Critical review of all repairs / maintenance and well
workovers
$/BOE
– Negotiating reduced rates and costs
1.20
0.80
0.40
0.00
Q1
Q2
Q3
2015
Q4
Q1
Q2
2016
12
41
MONTNEY INCOME MARGIN
– Montney delivers ~$14/BOE operating
margin
– G&A & interest expense ~$3.00/BOE
– Corporate level Montney income margin of
over $6.00/BOE
$/BOE
16
14
$14.00/BOE
$4.00/
BOE
12
$0.60/BOE
10
$3.00/BOE
8
6
>$6.00/
BOE
4
2
0
Operating Margin
Non-well Capital
Income Margin
F&D
Overhead
13
INFRASTRUCTURE PLAN
Liquids Handling Capacity Supports Growth
British Columbia
• Majority of upstream gathering, compression, and
processing is third party midstream
• Current capacity
Fort St. John
Spectra
McMahon
Spectra
West Doe
Tower 3-7.
– ~1.0 Bcf/d gas and ~10,500 bbls/d liquids
• Future processing capacity expansions underway
BC Station 2
– Adds ~800 MMcf/d compression/processing
– Adds ~55,000 bbls/d liquids handling
– On-stream late 2017 to mid-2018
Alberta
• Current production through Wembley and Sexsmith
• Current capacity
– ~150 MMcf/d and ~11,000 bbls/d liquids
• Future processing expansion at Wembley
– Adds ~12,000 bbls/d liquids handling
– On-stream in 2018
Capacity volumes are gross raw
Saturn 15-27
Phase 2
Spectra
Dawson Dawson
Creek
Sunrise 4-26
AltaGas
Gordondale
AECO
ECA
Sexsmith
To North American
Market
Existing processing
Future processing
Future C5 handling
Future water hub
Veresen
Steeprock
Veresen
Hythe
COP
Wembley
Grande
Prairie
To North American
Market
14
42
AGREEMENT WITH VERESEN MIDSTREAM
Fee-for-Service Structure
• Maximizing flexibility while managing execution
– Encana/CRP* sold a portion of Montney infrastructure to Veresen Midstream & entered into gathering arrangement
in 2015
– CRP controls pace of development and Encana executes facility construction for first ten years
– Veresen Midstream funds facility capital
• Financial structure enables flexibility
– Tolls based on pre-agreed rate of return on capital and production forecast – 30 year fee arrangement
– Variable monthly midstream costs based off toll calculation and actual production volumes
– No traditional take or pay obligation
•
CRP guarantees a return of capital spent less revenues Veresen Midstream receives from all Encana / CRP sources, and limited
third party sources, at 8 year after each facility project’s operational date; revenues collected are not "ring fenced" to any individual
facility project
•
Veresen Midstream receives acreage dedication
*CRP: Cutbank Ridge Partnership
15
Montney
Montney
• Flexible midstream and transportation
portfolio aligned with development
program
• Diversified physical markets and liquid
financial market
In-field gathering
system links to NGTL
NGTL
Condensate to
Edmonton market
center
To Pacific Northwest
(Malin)
Diversified physical
transportation
portfolio
‒ AECO is the benchmark price for the most
liquid physical trading point in North America
• Condensate sold via pipeline into
import-driven condensate market
To U.S. Midwest
(Chicago)
16
43
ENCANA MONTNEY
5 Year Growth Profile
Gas Growth Profile
1,400
• Development focused in condensate rich areas
• Liquids production to >70 Mbbls/d by 2019
1,000
MMcf/d
• Operating margin increases by >200% by 2021
1,200
800
600
400
200
‒ 50 Mbbls/d of liquids production in 2018
-
‒ Liquid weighting grows to >25% of total production by
2021
•
2016F
Mbbls/d
• Liquids handling expansions support growth plans
2019F
2020F
2021F
80
70
60
50
40
30
20
10
2016F
Volumes quoted are net to Encana
2018F
Liquids Growth Profile
~70% condensate
• Gas production to grow to 1.2 Bcf/d by 2019
2017F
2017F
2018F
2019F
2020F
2021F
17
44
ENCANA CORPORATION
Duvernay
Jim Roberts
Vice-President & General Manager, Northern Area Operations
PREMIER POSITION IN WORLD CLASS RESERVOIR
Duvernay
• Large contiguous land base within core of play
–
Significant growth opportunity
–
1,000 total locations, 500 premium locations
• Industry leading operating performance
–
Multi-well pads and in-place infrastructure significantly reduce cost
structures
–
Consistently delivering industry leading well performance
• Takeaway solution in place
–
Rich Gas Premium agreement with Aux Sable, gas transport on Alliance
–
Condensate transport on Pembina’s Peace Pipeline
• WTI pricing for condensate
*Estimated inventory based on 1000 ft spacing
Total Inventory
1,000 locations
Premium
500 locations
Premium
Inventory
5 Yr Plan
Remaining
Inventory
2
45
ENCANA IS THE LARGEST PRODUCER IN THE PLAY
Duvernay
Gross Production vs Peers
Duvernay Acreage
40,000
Gross Operated Production (BOE/d)
Alberta
Encana Land
Core
Reef
35,000
30,000
25,000
Simonette
North
Fox
Creek
20,000
15,000
Simonette
South
10,000
5,000
0
ECA
RDS
CVX
XTO
ECA net production
Source : Industry data.
APA
REP
ECA gross production
MUR
TET
12 miles
Other
Peer gross production
3
REDUCING COSTS
Duvernay
Duvernay D&C Costs*
15
12
$MM
• Lower cost structures driven by dual rig/dual frac crews
per pad
50% reduction in completion cycle time
6
–
Reduction of offset frac hits by 50%
3
–
Repeatable operations drive efficiency
0
Days
10
15
20
25
30
15,000
20,000
Pacesetter
2016 YTD Average
2015 Average
2014 Average
2016 Q1
2016 Q2
Pacesetter
2.5
MM$/1000’
Measured Depth (ft)
10,000
2015 Average
6.8
3.0
35
0
5,000
7.5
5
8.0
9
–
0
12.3
2.0
1.5
1.0
0.5
0.0
ECA
* D&C Costs normalized to 8,200 ft lateral length **Data sourced from peer investor presentations. Peers include APA, CVX, RDS, REP and TET
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
4
46
REDUCING COSTS
Focus on Sustainable Efficiencies
Increasing Fracs per Day
• 60% increase to fracs per day
~$0.5MM per well savings
7
–
Reduced pump time
6
–
Reduced non-productive time
Average Fracs Per Day
–
• 65% reduction to maintenance time
–
Pit-stop approach
–
Fewer maintenance periods
• Future opportunities
–
Innovative proppant delivery
–
Reduced maintenance periods
6.5
6.0
5
5.3
5.2
5
4
3.8
3
2
1
0
9-10 Pad 4-4 Pad 16-26 Pad 8-14 Pad 5-18 Pad 8-14 Pad
Phase 1
Phase 2
Continuous Improvement
and Innovation
driving down costs
5
WELL PRODUCTIVITY
Top Performance vs Peers
800
600
400
200
0
ECA
Peer 1
Peer 2
Peer 3
Oil
Peer 4
Peer 5
Gas
Data sourced from RS Energy Group, raw data provided by geoSCOUT. Peers include APA, MUR, RDS, TET, XOM
6
47
VERY RICH GAS CONDENSATE (150-250 bbls/MMcf)
Simonette North
Simonette North Type Curve
EUR = 1.0 MMBOE
D&C = $6.8 MM
500
450
Cumulative Production (MBOE)
400
350
300
250
200
150
Simonette North Type Well Metrics – ECA Net
100
50
0
Atax IRR (%)
0
50
100
150
200
250
300
350
400
Operating Margin
($/BOE)
Producing Days
SN-VRGC Actuals
SN-VRGC Type Curve
Leveraged
Unleveraged
165%
50%
$25
$25
All metrics based on $3.00/MMBtu NYMEX, $55/bbl WTI, and $0.75 FX
7
VERY RICH GAS CONDENSATE (150-250 bbls/MMcf)
Simonette South
Simonette South Type Curve
EUR = 1.4 MMBOE
D&C = $9.6 MM
800
700
600
500
400
300
Simonette South Type Well Metrics – ECA Net
200
100
Atax IRR (%)
0
0
50
100
150
200
250
300
350
Producing Days
SS-VRGC Actuals
All metrics based on $3.00/MMBtu NYMEX, $55/bbl WTI, and $0.75 FX
SS-VRGC Type Curve
400
450
500
Operating Margin
($/BOE)
Leveraged
Unleveraged
155%
50%
$25
$25
8
48
EXPANDING MARGINS
Operating Cost Performance
Duvernay Operating Cost Reductions
• Dramatic reduction in operating costs
$/BOE
• Three plants on-stream since 2014
$10
– Optimized for liquids handling
$8
– Reduced trucking from location
$6
$4
>60%
$2
Improvement in
operating costs
High CGR Gas
Plants
Q3
Q4
Q1
$0
Q1
Q2
2015
Q2
2016
9
DUVERNAY INCOME MARGIN
– Locations in the Duvernay deliver ~$25/BOE
operating margin
– Duvernay income margin at the corporate level
~$13.00/BOE
$/BOE
30
25
$25.00/BOE
$8.50/
BOE
20
$0.60/BOE
15
$3.00/
BOE
~$13.00/
BOE
10
5
0
Operating Margin
Non-well Capital
Income Margin
F&D
Overhead
10
49
STRATEGIC INFRASTRUCTURE INVESTMENT
Investment in Infrastructure Reducing Operating Costs
• Plants inter-connected through pipeline network
• Can operate in NGL recovery or rejection mode
Gross Facility Capacity
Gas Capacity
Liquids Handling
155 MMcf/d
30,000 bbls/d
• Requires minimal equipment on well sites
• Gross infrastructure capacity
– 155 MMcf/d & 30 Mbbls/d
10-29
Keyerra
Simonette
• 2017+ potential build-out
– Expansion planned at the end of the decade
15-31
5-31
– Debottleneck existing plants to maximize liquids throughput
40 mi Production/Fuel Gas Trunk Line
36 mi Water Distribution Line
Semcams KA
High CGR Gas
Plants
11
Duvernay
• Condensate sales via pipeline to premium
Edmonton market center
Duvernay
Condensate to
Edmonton market
center
• Firm market access aligned with
development program
• Achieved liquids price upgrade while
minimizing midstream capex via Alliance
pipeline
Alliance Pipeline to
U.S. Midwest
(Chicago)
• Diversified pricing exposure for liquids and
natural gas in Chicago market
12
50
ENCANA DUVERNAY
Significant Future Growth Potential
• 500 premium return locations
with potential to expand
• Innovation driving significant
cost reductions
• Facilities expansions planned for
end of the decade
Dual completions crews on location in the Duvernay
13
51
ENCANA CORPORATION
Eagle Ford
Eric T. Greager
Vice-President & General Manager, Western Operating Area
EAGLE FORD
Core Position in the Oil Window
• Largely contiguous position in the Karnes Trough
– Most active and profitable trend in the Eagle Ford
• Continued well cost improvements
– Leading industry with well costs below $4 MM
• Well inventory improvement
– 130 premium horizontal well inventory
– Stacked pay, infill spacing, Austin Chalk offer premium
inventory upside
• High value, high rate wells
– >80% of production is high value oil
Total Inventory
600 locations
Premium
130 locations
Remaining
Inventory
– Top quartile performance within industry
~100% of premium inventory
2
52
CORE POSITION WITHIN THE EAGLE FORD
Top Karnes County Producers
Eagle Ford
Gross Encana Production vs Peers
100,000
Gross Operated Oil Production (bbls/d)
90,000
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
MRO
EOG
ECA
COP
PXD
MUR
DVN
Data sourced from Drilling Info, Inc. Gross operated production in June, 2016, for Karnes County, TX.
3
EAGLE FORD CAPITAL EFFICIENCY
Better Wells For Lower Costs
0
– Drilled pacesetting 8.5 day well
Days
15
20
25
30
Pacesetter
2016 YTD Average
2015 Average
2014 Average
5,000
10,000
15,000
20,000
1.5
$MM/1000’
• Real time geosteering
• Custom lateral completions
• Faster coil tubing operations
10
0
Measured Depth (ft)
• Current D&C cost* of $3.9 MM/well
• Rapid reduction in drill days
5
1.0
0.5
0.0
*Normalized to 5,000’. **Data sourced from latest peer IR presentations. Peers include BTE, DVN, EOG, MRO, MUR, and SN.
Peer 1
ECA
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
4
53
WELL PRODUCTIVITY
Top Quartile Performance vs Peers
900
800
700
600
500
400
300
200
100
0
Peer 1
Peer 2
Peer 3
ECA
Peer 4
Peer 5
Peer 6
Peer 7
Peer 8
Oil
Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Peer 17 Peer 18
Gas
5
Data sourced from IHS, Inc. Includes all data from 2014 onward. Peers include BHP, CHK, COG, COP, CRZO, DVN, EOG, EPE, MRO, MTDR, MUR, NBL, NEU, PVA, PXD, SM, STO, and TLM
MARGINS & RETURNS
South-Central Karnes
Type Curve
IP30 = 1,300 BOE/d
6 month cumulative oil = 155 MBO
EUR = 580 MBOE
D&C = $4.1 MM
Lateral Length = 5,000’
400
350
300
250
200
150
100
50
0
0
100
200
300
400
500
Days on Production
South-Central Karnes Average Well Results
Type Curve
600
700
Atax IRR (%)
85%
$32
6
54
INNOVATION SUCCESS - FRAC COMPLEXITY
Thinner Fluids & Tighter Clusters
PRESENT
PA S T
Improved Fracture Complexity Driving
Outperformance
70
60
50
40
30
20
10
0
0
30
60
90
Producing Days
Many Thin Propped Fractures
Overwhelmed Interior Clusters
Early completions
× Bypassed pay
Tight spacing
× stress shadowing
× overwhelmed interior
clusters
Complex system
 Many thin propped
fractures
Parameters
• >60’ Clusters
• High Viscosity Fluid
Parameters
• 25’ Clusters
• High Viscosity Fluid
Parameters
• <20’ Clusters
• Low Viscosity Fluid
Completions
Parameter
Historical
Standard
Cluster Spacing (ft)
Proppant (lbs/ft)
Fluid System Viscosity
>60
<1,000
High
ECA Design
Complex
Fracture
<20
>2,000
Low
7
EAGLE FORD TIGHTER SPACING
Improving Fracture Effectiveness
Encana Innovation Enhances Well Productivity
• Successful downspacing in Eagle Ford
400
– Greater overall resource recovery
– Greater stimulation intensity
– Increased fracture complexity
•
Tighter cluster spacing
•
Increasing proppant concentration
•
Greater fracture surface area
300
200
100
0
660’ Spacing 330’ Spacing
Variance
Cluster Spacing (ft)
64
34
-47%
Proppant (lbs/ft)
787
1829
132%
EUR (MBOE)
629
858
36%
0
3
6
9
12
15
18
21
24
Months
330' Spacing
660' Spacing
Type Curve
8
55
EAGLE FORD STACKED AND STAGGERED
Triple Stacking with Complex Fractures
Eagle Ford Wells
• Optimizing spacing both vertically and
horizontally
• Upper Eagle Ford wells on trend with Lower wells
• Premium inventory expansion potential
2H
4H
1H
250
6H
200
150
100
50
0
0
3
6
9
12
15
Months
Lower Eagle Ford
Upper Eagle Ford
Original Lower Eagle Ford
9
EAGLE FORD STACKED AND STAGGERED
Austin Chalk Results
Austin Chalk Pad location
50
45
40
35
30
25
20
15
10
5
Early time flow data
0
0
5
10
15
Korth A 7
Korth A 8
20
outpacing the premium
Eagle Ford type curve
Days
Lower Eagle Ford Type Curve
10
56
EXPANDING MARGINS
Eagle Ford Operating Cost Reductions
• Leveraging company-wide effort
• Optimized repairs, maintenance, and workovers
$/BOE
$9
– In-house repairs, decreasing roustabout requirement
$8
• Supply management gains
$7
– Lower costs on chemicals, water hauling
• Improved artificial lift performance
$6
$5
~40%
$4
Q1
Improvement in
operating costs
Q2
Q3
Q4
Q1
2015
Q2
2016
11
EAGLE FORD INCOME MARGIN
$/BOE
30
– Locations in the Eagle Ford deliver ~$28/BOE
operating margin
25
– NRI F&D ~$10.00/BOE
20
15
– Eagle Ford income margin at the corporate
level of over $14.00/BOE
10
$28.00/BOE
$10.00/
BOE
$0.60/BOE
$3.00/
BOE
>$14.00/
BOE
5
0
Operating Margin
Non-well Capital
Income Margin
F&D
Overhead
12
57
Eagle Ford
Close proximity to market and welldeveloped infrastructure
Eagle Ford
Three
Rivers
Houston
• Firm gas gathering and NGL processing
aligned with asset development program
• Infield gathering and extensive market
assets in place to ensure flow and
downstream connectivity
• Diverse physical marketing portfolio with
access to Gulf Coast refining markets
Corpus
Christi
• Proximity to market minimizes
transportation cost and related
commitments while maximizing netbacks
13
ENCANA EAGLE FORD
Tremendous Flex Asset
• 30-40,000 BOE/d by end of plan
• Free cash flow generator
• 5 year plan consumes current premium
inventory
• Focus on transitioning remaining inventory
into premium locations
14
58
ENCANA CORPORATION
Financial Strength & Discipline
Sherri Brillon
Executive Vice President & Chief Financial Officer
ENCANA
• Leading growth
TOP TIER
RESOURCE
MARKET
FUNDAMENTALS
– >300% cash flow growth over 5 year plan
― 10,000 premium return locations
• Efficiency
― Grow cash flow by expanding margins and allocating capital to
assets that deliver strong corporate returns
OPERATIONAL
EXCELLENCE
CAPITAL
ALLOCATION
2
59
CORPORATE FINANCE
Providing Financial Flexibility & Liquidity to Execute our Strategy
Maintaining Financial
Strength
Disciplined Capital
Allocation
Ensuring ample access to a variety of funding
sources
Driven by strategy
Disciplined & dynamic approach
Prudently managing debt levels
Focused on capital efficiency to drive returns
Driving down corporate costs
Delivering profitable growth
Mitigating commodity price risk
Capital discipline reinforced with dividend
3
MAINTAINING FINANCIAL STRENGTH
$1.15 Billion Equity Issuance
•
•
Confidence to unlock massive growth potential
•
Accretive to cash flow, reduces leverage metrics
― Maintains operational momentum in core four plays
–
Double digit accretion to 2017 and 2018 cash flow per share
― Significantly accelerates 2017 activity in the Permian
–
Improves D/DACF by >1x in each of 2017 & 2018
•
De-risks 2017 capital program
Cash Flow per Share Impact
2017F CFPS
2018F CFPS
Credit positive, maintains financial flexibility
Leverage Impact
2017F D/DACF
2018F D/DACF
4
60
DISCIPLINED FINANCIAL MANAGEMENT
Debt Portfolio as at September 30, 2016
•
Significant financial flexibility with no debt maturities until 2019
•
~75% of fixed rate long-term debt not due until 2030 and beyond
•
Total debt reduced by ~$3 billion since year-end 2014
•
Investment grade credit rating
Fixed Debt Maturity Schedule
(US$ MM)
1,000
750
500
250
2041
2040
2039
2038
2037
2036
2035
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
0
5
DISCIPLINED FINANCIAL MANAGEMENT
Access to Ample Liquidity Through 2020
ECA Ratio Well Within Covenant Threshold
• $4.5B fully committed, unsecured, revolving credit
facilities
Debt to Adjusted Capitalization Ratio
– $4.5B available at September 30, 2016
80%
– Committed to July 2020
70%
– No use of credit facility to back-stop long term commitments
60%
– Single financial covenant
50%
•
Debt cannot exceed 60% of adjusted capitalization
•
Adjusted capitalization = debt + equity + $7.7B equity adjustment*
•
<25% pro forma June 30th, 2016**
•
Debt to adjusted capitalization ratio has improved since 2013
40%
60% Threshold
36%
30%
30%
28%
<25%**
20%
10%
0%
YE 2013
YE 2014
*Add back equity adjustment for cumulative historical ceiling test impairments recorded YE 2011 in conjunction with adoption of US GAAP; see MD&A for additional detail on ratio calculation.
** Includes impact of equity issuance and divestiture proceeds received during Q3 2016.
YE 2015
Pro Forma Q2
2016
6
61
BUILDING ON OUR TRACK RECORD
Delivering Corporate Cost Savings
Quarterly Interest Expense*
$MM
140
• Normalized interest* on long term debt run rate
~$70 - $75 MM/quarter
120
100
80
– Interest expense reduced as a result of debt redemptions and
retirements
60
40
20
– Down ~40% from 2012 average
0
• Normalized G&A** run rate ~$40 - $45 MM/quarter
– Down ~55% from 2012 average
2012 Avg
$MM
100
• Current staffing levels can support accelerated
activity levels in 2017
-
Column1 Column2
2016F
Quarterly G&A Expense**
80
• Full-year impact of cost savings to be realized in 2017
60
• Continuously looking for opportunities to further
reduce corporate costs
40
20
0
2012 Avg
-
*
*2
2016F
7
*Excluding restructuring and long-term incentive costs. ** Excluding one time payments. (Quarterly averages)
G&A & INTEREST $/BOE PEER COMPARISON
Top Quartile Cost Performance
$12
2016 Interest/BOE
2016 G&A/BOE
$10
Trending to ~$3.00/BOE
over growth plan
$/BOE
$8
$6
$4
$2
$0
Peer 10
Peer 9
Peer 8
Peer 7
Peer 6
Peer 5
Peer 4
Peer 3
ECA
Peer 2
Peer 1
Source: IHS Company Insights; ECA internal figures. Peers include: CNQ, CXO, EGN, EOG, FANG, LPI, MRO, MUR, PXD, RSPP, SN
.
8
62
REDUCING LONG TERM T&P COMMITMENTS
Legacy Costs Continue to Drop
Transportation & Processing Commitments*
$MM
$1,200
$1,000
$800
$600
$400
$200
$0
2014
2015
2016F
2017F
Non-core
2018F
2019F
2020F
2021F
Core
*Represents historical and current forecasts of long-term transportation and processing commitments associated with Encana’s core four assets (Permian, Montney, Eagle Ford
& Duvernay) and non-core assets (all other assets).
9
HEDGING STRATEGY
Mitigating Commodity Price Risk
Programs designed to manage exposure to commodity price volatility
Supports management of balance sheet risk
Portfolio approach to derivatives for both WTI and NYMEX
Active management of regional natural gas basis & oil differentials
Integrated hedging decision framework
10
63
HEDGING PROGRAM
Adds Greater Certainty to Cash Flow
Oil Positions
Natural Gas Positions
100
Volume (Bcf/d)
1.00
$2.22 x $2.46
/Mcf
0.75
$2.70/Mcf
0.50
$2.72/Mcf
$2.27 x $2.75 x $3.07
/Mcf
0.25
0.00
Volume (Mbbls/d)
1.25
75
50
$50.86/bbl
25
$2.75 x $3.55 /Mcf
$3.07/Mcf
2016*
NYMEX Fixed Price Swap
NYMEX 3-Way Option
$47.04 x $55 x $62.96
/bbl
2017
$37.35 x $48.48 x $59.03
/bbl
$55.18/bbl
$49.49/bbl
0
NYMEX Costless Collar
NYMEX Fixed Price Swaption
2016*
2017
WTI 3-Way Option
WTI Fixed Price Swap
WTI Fixed Price Swaption
Hedge positions as at September 30, 2016. *October to December 2016 positions.
The NYMEX fixed price swaptions give the counterparty the option to extend 2016 fixed price swaps to December 31, 2017 at the strike price. As of Sept. 30, 2016, the options had not been exercised.
The WTI fixed price swaptions give the counterparty the option to extend Q1 2017 fixed price swaps to June 30, 2017 at the strike price. As of Sept. 30, 2016, the options had not been exercised.
11
2016 GUIDANCE UPDATE
Cost Performance Continues to Improve
2016 Guidance
Feb 24, 2016
July 23, 2016
Oct 5, 2016
900 – 1,000
1,100 – 1,200
1,100 – 1,200
1,300 – 1,400
1,300 – 1,400
1,300 – 1,400
120 – 130
120 – 130
120 – 130
% Oil & Condensate*
75 – 80%
75 – 80%
75 – 80%
% Natural Gas Liquids
20 – 25%
20 – 25%
20 – 25%
340 – 360
340 – 360
340 – 360
PMOT ($/BOE)
0.75 – 0.85
0.75 – 0.85
0.75 – 0.80
Upstream Operating** ($/BOE)
4.60 – 4.90
4.15 – 4.35
3.95 – 4.10
Transportation & Processing ($/BOE)
6.80 – 7.20
6.60 – 6.70
6.45 – 6.60
G&A** ($/BOE)
1.25 – 1.35
1.30 – 1.40
1.30 – 1.40
Capital Investment
Continued progress
improving operating
efficiencies and
lowering costs
Capital Investment ($MM)
Production
Natural Gas (MMcf/d)
Total Liquids (Mbbls/d)
Total Production (MBOE/d)
Cash Costs
* Includes plant & field condensate .**Excluding restructuring and long-term incentive costs
12
64
2017 – 2018 OUTLOOK*
Kick-Starting the Growth Plan
Projected
2017
Program
• $1.4 - $1.8 B total capital
• Self-funding capital program
–
Permian: $850MM to $1.0B
• >400 MBOE/d total annual
–
–
Montney: $200 to $300MM
EF + Duvernay: $300 to $450MM
Projected
2018
Program
• >90% of capital to DC&T
• Growth in core four begins mid-year
production
• >30% growth in core four
production 4Q/17 to 4Q/18
• >50% increase in corporate margin
• 15-20% core four production growth
• Leverage drops to ~2x D/DACF
4Q/16 to 4Q/17
13
*Assumes flat $55/bbl WTI oil price, flat $3/MMBtu NYMEX natural gas price.
PRODUCTION GROWTH TRAJECTORY
Production (MBOE/d)
Growing High Margin Volumes
650
• >60% total company production* growth
― Permian grows ~3x – 4x
550
― Montney liquids grow ~4x – 5x, gas grows ~2x
450
― Combination of Eagle Ford and Duvernay production
stays relatively flat
350
• 15% – 20% liquids CAGR
• Corporate margin doubles
250
2016F
2017F
2018F
2019F
2020F
2021F
Corporate Margin $/BOE*
― Core four becomes >90% of total company production
― Commodity mix becomes balanced between liquids and
natural gas
― >50% increase in corporate margin 2017 to 2018
*Assumes flat $55/bbl WTI and $3/MMBtu NYMEX. 2016 production does not include volumes from assets divested in 2016.
Refer to advisory for definition of corporate margin. **Impact of higher volumes on PMOT, T&P and Operating Expense.
14
65
5 YEAR CAPITAL & CASH FLOW OUTLOOK
Self-Funding Capital Program Post 2017
Cash Flow ($MM)
• >300% cash flow* growth
4,000
― Focus on high margin production amplifies cash
flow growth
3,000
2,000
• Self funding post 2017
1,000
― Cash flow exceeds capital program at $55 WTI
and $3 NYMEX
• Multi-basin portfolio advantage
― Enables flexible and efficient deployment of
capital
-
2016F
Capital ($MM)
4,000
2017F
2018F
2019F
2020F
2021F
2020F
2021F15
3,000
2,000
1,000
-
* Assumes flat $55/bbl WTI and $3/MMBtu NYMEX
ENCANA
• Leading growth
2016F
2017F
TOP TIER
RESOURCE
2018F
2019F
MARKET
FUNDAMENTALS
• Efficiency
― Grow cash flow by expanding margins and allocating capital
to assets that deliver strong corporate returns
OPERATIONAL
EXCELLENCE
CAPITAL
ALLOCATION
16
66
ENCANA CORPORATION
Supplemental
PERMIAN – 2016 PROGRAM
Focused Development to Drive Efficiencies
FY 2016 Plan
Acreage (net acres)
Glasscock
Howard
Martin
Midland
Other
Average Working Interest (%)
Average Royalty Rate (%)
Capital (net)
Rig Count
Horizontal
Vertical
Wells Drilled (net)
Horizontal
Vertical
Wells on Stream (net)
Horizontal
Vertical
Production Split
Oil/condensate** %
NGLs %
Natural gas %
146,000
18,500
58,500
30,000
33,000
6,000
91%
20 – 25%
~$650 million
• Development focus in the Midland/Martin/Upton
• Longer laterals and more wells per pad to drive efficiency
• Maintain land position through a reduced vertical drilling
program
• Multi-rig and frac spreads accelerating D&C cost reductions
4
0.5
75 - 85
10
60 - 70
20 - 25
64%
18%
18%
**Includes plant and field condensate; Encana reports plant condensate as NGL
2
67
ENCANA PERMIAN
Gross Premium Return Inventory
County
Midland
Zone
Martin
Howard
Glasscock
WOLFCAMP
SPRABERRY
SPRABERRY
WOLFCAMP
SPRABERRY
WOLFCAMP
SPRABERRY
IP30 (BOE/d)
700
900
700
825
675
825
675
IP180 (BOE/d)
550
600
525
575
500
575
500
EUR/Well (MBO)
500
475
600
500
500
500
500
EUR/Well (MBOE)
900
750
850
850
700
850
700
2,900
2,200
1,900
2,600
2,000
2,600
2,000
910
230
650
500
200
170
90
GOR (MCF/bbl)
Gross Premium
Return Inventory
Estimated inventory based on 660 ft spacing, 7,500’ lateral length.
3
MONTNEY – 2016 PROGRAM
Focused On Oil and Liquids Development
• Fill existing infrastructure to maintain production
FY 2016 Plan
Acreage (net acres)
484,000
British Columbia (CRP)
293,000
Alberta (PRA)
191,000
Working Interest (%)
Capital (net) $Million
Rig Count
67%
• Development focused in the liquids rich zones and
acreage
• Maintain highest quality land position in Alberta
10 – 15%
~$120
2
Wells Drilled (net)
17-19
17-19
Production Split
Oil/condensate** %
9%
NGLs %
5%
Natural gas %
86%
4
68
MONTNEY
Cutbank Ridge Partnership (CRP)
• Partnership with a subsidiary of Mitsubishi
Tower
Encana: 60% interest
– Mitsubishi: 40% interest
–
Saturn
• Development areas
Montney: Tower, Dawson North, Dawson South and Tumbler Ridge
Cadomin
– Steeprock Doig
–
Dawson
South
–
Tumbler Ridge
Cadomin/Montney
• Investment structure (C$2.9B)
–
–
C$1.45 billion upfront in 2012
Further investment of C$1.45 billion during the commitment period
• Third party capital expected to extend through 2018
Steeprock
Doig
2016F third party capital ~C$80 million
– 2017+ third party capital C$675 - $725 million
–
•
CRP All WI
Mitsubishi also funds its 40% of the Partnership's future
capital investment
5
ENCANA MONTNEY
Region
Type
IP30 (BOE/d)
IP180 (BOE/d)
Tower
Wet Gas
Gas
Condensate
1,000 – 1,350 1,150 – 1,550
Dawson South
Rich Gas
Condensate
850 – 1,100
Gas
Condensate
Rich Gas
Condensate
Very Rich Gas
Condensate
Volatile Oil
1,450
1,670
1,820
840 – 1,250
1,600 – 1,750
1,150
1,300
1,450
600 – 1,050
1,065 – 1,700 1,320 – 1,875
1,610
1,700
2,010
630 – 1,400
Wet Gas
Gas
Condensate
Pipestone
1,350 – 2,170 2,350 – 2,500
725 – 1,000
1,100 – 1,550
750 – 1,000
EUR/Well (MBOE)
710 – 970
1,075 – 1,440
880 – 1,130
Condensate Yield
(bbls/MMcf)
<20
20 - 50
50 - 150
<20
20 - 50
20 - 50
50 - 150
150 - 250
>250
Gross Premium
Return Inventory
225
1625
550
450
650
530
900
180
790
Estimated inventory based on 440 - 880 ft spacing, 9,000’ lateral length.
910 – 1,330
6
69
EAGLE FORD – 2016 PROGRAM
Enhancing Well Inventory
• Achieving substantial cost reductions
• Enhancing well inventory
FY 2016 Plan
Acreage (net acres)
Rig Count
Wells Drilled (net)
Production Split
Oil/condensate** %
NGLs %
Natural gas %
43,200
91%
20 – 25%
~$200
1
25-35
40-50
– Delineating Upper Eagle Ford & Austin Chalk potential
– Optimizing completion design for Graben wells
– Confirm chevron downspacing for undeveloped acreage
73%
12%
15%
7
ENCANA EAGLE FORD TYPE CURVES
Type Curve
Lower Eagle Ford
IP30 (BOE/d)
950
IP180 (BOE/d)
650
EUR/Well (Mbbls)
370
EUR/Well (MBOE)
570
GOR
Estimated inventory based on 330 ft spacing, 5,000’ lateral length.
2,500
130
8
70
DUVERNAY – 2016 PROGRAM
Lowering Costs, Increasing Productivity
• Advance downspacing and completion pilots
FY 2016 Plan
Acreage (net acres)
Simonette
Willesden Green
Edson/Pinto
Rig Count
Wells Drilled (net)
Production Split
Oil/condensate** %
NGLs (C2 – C4) %
Natural gas %
335,000
97,000
200,000
38,000
50%
5 – 15%
~$120
3
20-22
21-24
• Increasingly material to production and cash flow
• 2/3 of activity focused in Simonette North
• Basin leading operating efficiencies
–
Dual rig/dual frac crews per pad
–
Water and road infrastructure allowing for year-round operations
48%
7%
45%
9
DUVERNAY JOINT VENTURE
• Brion (formerly Phoenix, a subsidiary of PetroChina)
agreed to invest C$2.18 billion for 49.9% working
interest
–
C$1.18 billion up front cash in 2012
–
Further investment of C$1.0 billion during the commitment
period
• JV carry capital reduces Encana’s capital & leverages
economics
–
2016F carry capital ~C$150 million
–
2017+ carry capital C$95 - 115 million
10
71
ENCANA DUVERNAY
Region
Type
Simonette South
Simonette North
Rich Gas Condensate
Very Rich Gas Condensate
Rich Gas Condensate
Very Rich Gas Condensate
IP90 (MMcf/d)
4-6
3-5
3.5 – 4.5
2.5 – 3.5
EUR/Well (MBOE)
1,400
1,400
1,100
1,000
Di Gas (decline factor)†
59
57
57
57
Di Condensate (decline factor)*
66
67
68
68
b-factor (gas)*
1.2
1.2
1.2
1.2
b-factor (oil)*
1.0
1.0
1.0
1.0
50 - 150
150 - 250
50 - 150
150 - 250
150
120
60
170
Condensate Yield (bbls/MMcf)
*Di factor & b-factor for use with Arps’ decline equation, † Di factor influenced by 3 month flat initial gas rate. Gas heat content of 1,300 Btu/scf.
Estimated inventory based on 1,000 ft spacing, Simonette North at 8200’ lateral length, Simonette South at 8,860' lateral length.
11
LIQUIDS VALUE CHAIN
Projected Composition of Total Liquids Production
Canada
US
2016F*
(Mbbls/d)
20 – 25
2016F Pricing
(%WTI)
97%
2016F*
(Mbbls/d)
70 – 75
2016F Pricing
(%WTI)
88%
Butane
2–5
45%
3–6
43%
Propane
3–6
5%
6–9
33%
Ethane
1–4
22%
5–8
7%
Oil and Condensate**
Liquids primarily comprised of
higher-value products
*2016F based on company guidance as at October 5, 2016; production ranges are not additive
**Includes plant condensate
12
72
NON-GAAP MEASURES
Certain measures in this presentation do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP
measures. These measures may not be comparable to similar measures presented by other companies. These measures have been provided for
meaningful comparisons between current results and other periods and should not be viewed as a substitute for measures reported under U.S. GAAP.
For additional information relating to non-GAAP measures, see Encana’s most recent MD&A as filed on SEDAR and EDGAR. Non-GAAP measures
include:
• Cash Flow, Cash Flow Per Share (CFPS) and Corporate Margin –
Cash Flow is defined as cash from operating activities excluding net
change in other assets and liabilities, net change in non-cash working
capital and cash tax on sale of assets. CFPS is Cash Flow divided by
the number of common shares outstanding. Corporate Margin is Cash
Flow per BOE of production. Management believes these measures
are useful to the company and its investors as a measure of operating
and financial performance across periods and against other
companies in the industry, and are indication of the company’s ability
to generate cash to finance capital programs, to service debt and to
meet other financial obligations. These measures are used, along with
other measures, in the calculation of certain performance targets for
the company’s management and employees.
• Debt to Debt Adjusted Cash Flow (D/DACF) – D/DACF is Encana’s
consolidated debt versus Cash Flow excluding interest expense after
tax. This measure is monitored by management and is commonly
used in the oil and gas industry as an indicator of the company’s
overall financial strength.
• Debt to Adjusted Capitalization – Debt to Adjusted Capitalization
adjusts capitalization for historical ceiling test impairments that were
recorded as at December 31, 2011. Management monitors Debt to
Adjusted Capitalization as a proxy for Encana’s financial covenant
under its credit facility agreements which require debt to adjusted
capitalization to be less than 60 percent. Adjusted Capitalization
includes debt, total shareholders’ equity and an equity adjustment for
cumulative historical ceiling test impairments recorded as at
December 31, 2011 in conjunction with the Company’s January 1,
2012 adoption of U.S. GAAP.
• Normalized Interest – Normalized Interest is interest expense on longterm debt, excluding one-time charges associated with early
retirement. Management believes Normalized Interest is a useful
indicator of ongoing interest costs associated with long-term debt that
is more comparable between periods as it eliminates certain one-time
costs.
• Normalized G&A – Normalized G&A is administrative expense
excluding long-term incentive and restructuring costs. Management
believes Normalized G&A is a useful indicator of ongoing controllable
base administrative costs that are more comparable between periods
and against other companies in the industry as it eliminates certain
one-time and non-cash impacts.
1
FUTURE ORIENTED INFORMATION
This presentation contains certain forward-looking statements or information (collectively, “FLS”) within the meaning of applicable securities legislation. FLS include:
•
•
•
•
•
•
•
•
•
•
•
expectation of meeting or exceeding the targets in Encana’s corporate guidance
anticipated capital program, including focus of development, amount of sustaining capital, the amount allocated to
its core four assets, number of wells on stream and expected return
well performance, completions intensity, location of acreage and costs relative to peers and within plays
anticipated production, cash flow, capital coverage, payout, net present value, rates of return, production efficiency,
commodity mix, operating and corporate margins, netbacks and growth, including expected timeframes
number of well locations (including identification of premium return locations), well spacing, decline rate, focus of
drilling and timing, commodity composition, rates of returns, and operating performance compared to type curves
pacesetting operational metrics being indicative of average future well performance and costs, including success of
technological innovation and sustainability thereof
ability to scale or redirect capital program and innovation and asset quality to drive capital productivity
expected capacity and transportation and processing commitments and restrictions
anticipated reserves and resources, including product types and stacked resource potential
competitiveness and pace of growth of Encana’s plays within North America and against its peers
anticipated third-party incremental and joint venture carry capital
•
•
•
•
•
•
•
•
•
•
•
•
anticipated capital and cost efficiencies, including drilling and completion, operating, corporate, transportation and
processing costs, associated staffing levels, and sustainability of costs thereof
expected net debt, associated interest expense savings and quarterly run rate on interest and G&A
growth in long-term shareholder value and timing thereof
expected rig count and rig release metrics
commodity price outlook
anticipated hedging and outcomes of risk management program, including amount of hedged production
management of Encana’s balance sheet and credit rating, including access to and commitment of credit facilities
and upcoming debt maturities
expectation to continue to strengthen Encana's balance sheet and create additional financial flexibility
expected proceeds from divestitures, expectation that the closing conditions and regulatory approvals will be
satisfied, the timing of closing thereof and the use of proceeds therefrom
running room and scale of Encana’s plays and anticipated vertical and horizontal drilling
anticipated dividends
amount of well inventory versus long-term plan and consumption thereof
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
enforceability of transaction agreements
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.
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. Drilling
and completions costs have been normalized as specified in this presentation based on certain lateral lengths for a particular play. Premium return locations are defined as locations with expected after tax returns greater than 35% at $50/bbl WTI
and $3/MMBtu NYMEX.
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.
2
73
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 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 and 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 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 (“IQREs) 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. 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
resource potential”). 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.
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, 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 of estimated well locations include proved, probable,
contingent and unbooked locations. These estimates are prepared internally based on Encana's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal
review. Approximately half of all locations in our core four plays are booked as either reserves or resources, as prepared by IQREs using forecast prices and costs as of December 31, 2015. Unbooked locations do not have attributed
reserves or resources and have been identified by management as an estimation of Encana's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no
certainty that Encana will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The locations on which Encana will actually drill wells, including
the number and timing thereof is ultimately dependent upon the availability of capital, regulatory and partner approvals, seasonal restrictions, equipment and personnel, oil and natural gas prices, costs, actual drilling results, additional
reservoir information that is obtained, production rate recovery, transportation constraints and other factors. While certain of the unbooked locations have been de-risked by drilling existing wells in relative close proximity to such locations,
many of other unbooked locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations
and if drilled there is more uncertainty that such wells will result in additional proved or probable reserves, resources or production.
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.
3
74
2016F ENCANA CORPORATE GUIDANCE
US$, U.S. GAAP
October 5, 2016
2016F
Capital Investment ($ billions)
Total Capital Investment
1.1 – 1.2
Production (1) (after royalties)
Natural Gas (MMcf/d)
1,300 – 1,400
Liquids (Mbbls/d)
120 – 130
% Oil & Condensate (2)
75 – 80%
% Natural Gas Liquids
20 – 25%
Total Production (MBOE/d)
340 – 360
Operating Costs ($/BOE at 6:1 ratio)
Production, Mineral and Other Taxes
0.75 – 0.80
Upstream Operating Expense (3)
3.95 – 4.10
Transportation and Processing
6.45 – 6.60
Administrative Expense (3)
1.30 – 1.40
1. Assumes ~20,000 BOE/d for the first seven months of 2016 (11,500 BOE/d annualized) production from DJ Basin and ~22,000 BOE/d for the first seven months of 2016 (13,000 BOE/d annualized)
production from Gordondale.
2. Includes plant & field condensate.
3. Excludes long-term incentives and restructuring charges.
ADVISORY: This document contains certain forward-looking statements or information (collectively, “FLS”) within the meaning of applicable securities legislation. FLS include:
•
capital investment
•
anticipated commodity mix
•
natural gas, liquids and total production, including anticipated production from the DJ Basin
•
operating costs
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:
•
data contained in key modeling statistics
•
enforceability of transaction agreements and the ability of the parties to such transactions to
•
availability of attractive hedges and enforceability of risk management program
satisfy closing conditions and regulatory approvals
•
results from innovations
•
the value of adjustments to the expected proceeds from the transactions
•
expectation that counterparties will fulfill their obligations under gathering, midstream and •
expectations and projections made in light of, and generally consistent with, Encana’s historical
marketing agreements
experience and its perception of historical trends, including with respect to the pace of
•
access to transportation and processing facilities where Encana operates
technological development, the benefits achieved and general industry expectations
•
effectiveness of Encana’s resource play hub model to drive productivity and efficiencies
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,
greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential future lawsuits and regulatory actions made against Encana; 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 document and, except as required by law, Encana undertakes no obligation to update publicly
or revise any FLS. FLS contained in this document are expressly qualified by these cautionary statements. FLS included in the 2016F Encana Corporate Guidance dated prior to the date hereof are
revoked in their entirety and should not be relied upon.
Certain future oriented financial information or financial outlook information is included in this document to communicate Encana’s current expectations as to its performance in 2016. Readers are cautioned
that it may not be appropriate for other purposes.
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.

Corporate Presentation

Transcription

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