The natural gas revolution
and energy self-reliance in
North America
Don McClure, Vice President
Government & Stakeholder
Relations & Legal
Miami, Florida
March 26, 2013
Future Oriented Information
In the interests of providing Encana shareholders and potential investors with information regarding Encana, including management’s assessment of Encana’s and its subsidiaries’ future plans and
operations, certain statements contained in this presentation are forward-looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as
“forward-looking statements.” Forward-looking statements in this presentation include, but are not limited to: projections contained in the 2012 Corporate Guidance (including but not limited to
estimates of cash flow, including per share amounts, natural gas, oil and natural gas liquids (“NGLs”) production, capital investment and its allocation, net divestitures, operating costs, and estimated
2012 sensitivities of cash flow and operating earnings); projections for 2013 (including but not limited to capital investment, net divestitures, net capital investment, natural gas, oil and NGLs and total
liquids production, cash flow, net debt, and cash balance as of year-end); 2012 projected net debt and cash balance as of year-end; projection for long-term natural gas prices to reflect marginal
supply cost; achieving a more balanced portfolio of production and cashflow; projected number of wells to be drilled in 2012 and their distribution among the Company’s plays; projected percentage
shift of capital investments to liquids rich plays from 2012 to 2013 and expected cash flow contribution from liquids production by 2013; the flexibility of capital spending plans and the sources of
funding therefore; the ability to maintain investment grade credit rating; ability to attract new joint venture capital and implement existing joint ventures; projection to maintain current level of dividends;
the effect of the Company's risk management program, including the impact of commodity price hedges in 2012 and 2013; projections, estimates and future plans and strategies for the Canadian and
USA Divisions, various properties, plays basins and other assets, including liquids content and production growth for 2012-2013, PIIP, COIP, NGIP and EUR, target well cost, drilling, completion and
tie-in (“DCT”) costs, operating cost, transportation cost, drilling plans and well inventories, reductions in supply costs and estimates of reserves and economic contingent resources; forecast date of
first natural gas production for Deep Panuke; projected coal to gas displacement for 2012 to 2013; expected coal unit retirements by 2025 and expected increase in potential natural gas demand;
expected increase in natural gas demand from transportation; projected North American LNG export opportunity up to 2020, including from Kitimat LNG Project; short-, medium- and long-term
projected increase in natural gas demand from various sectors; projected North American natural gas production from 2012 to 2013, including by product types; projected future North American
natural gas prices; projected U.S. and Western Canadian ethane and propane supply and demand up to 2017; and expectations for NGLs' prices, supply and demand in the future.
Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By
their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions,
forecasts, projections and other forward-looking statements will not occur, which may cause the Company’s actual performance and financial results in future periods to differ materially from any
estimates or projections of future performance or results expressed or implied by such forward-looking statements. These assumptions, risks and uncertainties include, among other things: volatility
of, and assumptions regarding natural gas and liquids prices, including substantial or extended decline of the same and their adverse effect on the Company’s operations and financial condition and
the value and amount of its reserves; assumptions based upon the Company’s current guidance; fluctuations in currency and interest rates; risk that the Company may not conclude divestitures of
certain assets or other transactions (including third-party capital investments, farmouts or partnerships, which Encana may refer to from time to time as “partnerships” or “joint ventures”, regardless of
the legal form) as a result of various conditions not being met; product supply and demand; market competition; risks inherent in the Company’s and its subsidiaries’ marketing operations, including
credit risks; 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; marketing margins; potential disruption or unexpected technical difficulties in developing new facilities;
unexpected cost increases or technical difficulties in constructing or modifying processing facilities; risks associated with technology; the Company’s ability to acquire or find additional reserves;
hedging activities resulting in realized and unrealized losses; business interruption and casualty losses; risk of the Company not operating all of its properties and assets; counterparty risk; downgrade
in credit rating and its adverse effects; liability for indemnification obligations to third parties; variability of dividends to be paid; its ability to generate sufficient cash flow from operations to meet its
current and future obligations; its ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the Company’s ability to secure adequate
product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations or the interpretations of such laws or regulations; political and
economic conditions in the countries in which the Company operates; terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the Company;
risk arising from price basis differential; risk arising from inability to enter into attractive hedges to protect the Company’s capital program; and other risks and uncertainties described from time to time
in the reports and filings made with securities regulatory authorities by Encana.
Although Encana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers
are cautioned that the foregoing list of important factors is not exhaustive. In addition, assumptions relating to such forward-looking statements generally include Encana’s current expectations and
projections made in light of, and generally consistent with, its historical experience and its perception of historical trends, including the conversion of resources into reserves and production as well as
expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this
presentation. Assumptions with respect to forward-looking information regarding expanding Encana's oil and NGLs production and extraction volumes are based on existing expansion of natural gas
processing facilities in areas where Encana operates and the continued expansion and development of oil and NGL production from existing properties within its asset portfolio.
Forward-looking information respecting anticipated 2012 cash flow for Encana is based upon, among other things, achieving average production for 2012 of 3.0 Bcf/d of natural gas and 30,000 bbls/d
of liquids, commodity prices for natural gas and liquids based on NYMEX $3.25 per Mcf and WTI of $95 per bbl, an estimated U.S./Canadian dollar foreign exchange rate of $1.00 and a weighted
average number of outstanding shares for Encana of approximately 736 million. Forward-looking information respecting anticipated 2013 cash flow for Encana is based upon achieving average
production for 2013 of between 2.9 Bcf/d and 3.1 Bcf/d of natural gas and 60,000 bbls/d to 70,000 bbls/d of liquids, commodity prices for natural gas and liquids based on NYMEX $3.50 per Mcf and
WTI of $90 per bbl, an estimated U.S./Canadian dollar foreign exchange rate of $1.00 and a weighted average number of outstanding shares for Encana of approximately 736 million.
Furthermore, the forward-looking statements contained in this presentation are made as of the date hereof and, except as required by law, Encana undertakes no obligation to update publicly or
revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this presentation are expressly qualified by this
cautionary statement.
2
Advisory Regarding Reserves Data & Other
Oil & Gas Information Disclosure Protocols
National Instrument (“NI”) 51-101 of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies such as Encana engaged in oil and gas activities.
Encana complies with the NI 51-101 annual disclosure requirements in its annual information form, most recently dated February 23, 2012 (“AIF”). The Canadian protocol disclosure is contained in
Appendix A and under “Narrative Description of the Business” in the AIF. Encana has obtained an exemption dated January 4, 2011 from certain requirements of NI 51-101 to permit it to provide certain
disclosure prepared in accordance with U.S. disclosure requirements, in addition to the Canadian protocol disclosure. That disclosure is primarily set forth in Appendix D of 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.
The estimates of economic contingent resources contained in this presentation are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook. Contingent resources do not
constitute, and should not be confused with, reserves. Contingent resources are defined as those quantities of petroleum estimated, on 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. Economic
contingent resources are those contingent resources that are currently economically recoverable. In examining economic viability, the same fiscal conditions have been applied as in the estimation of
reserves. There is a range of uncertainty of estimated recoverable volumes. A low estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the
actual remaining quantities recovered will exceed the low estimate, which under probabilistic methodology reflects a 90 percent confidence level. A best estimate is considered to be a realistic estimate of
the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, which under probabilistic methodology reflects a 50
percent confidence level. A high estimate is considered to be an optimistic estimate. It is unlikely that the actual remaining quantities recovered will exceed the high estimate, which under probabilistic
methodology reflects a 10 percent confidence level.
There is no certainty that it will be commercially viable to produce any portion of the volumes currently classified as economic contingent resources. The primary contingencies which currently prevent the
classification of Encana's disclosed economic contingent resources as reserves include the lack of a reasonable expectation that all internal and external approvals will be forthcoming and the lack of a
documented intent to develop the resources within a reasonable time frame. Other commercial considerations that may preclude the classification of contingent resources as reserves include factors such
as legal, environmental, political and regulatory matters or a lack of markets.
The estimates of various classes of reserves (proved, probable, possible) and of contingent resources (low, best, high) in this presentation represent arithmetic sums of multiple estimates of such classes
for different properties, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of reserves
and contingent resources and appreciate the differing probabilities of recovery associated with each class.
Encana uses the terms resource play, total petroleum initially-in-place, natural gas-in-place, and crude oil-in-place. Resource play is a term used by Encana to describe 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. Total petroleum initially-in-place (“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”). Natural gas-in-place (“NGIP”) and crude oil-in-place (“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 Canadian Oil & Gas Evaluation Handbook (“COGEH”) or by the SPE-PRMS, and/or 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. Some of this data may not have been prepared by qualified reserves evaluators or auditors and the preparation of any estimates may not be in strict accordance with COGEH.
Regardless, 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.
There is no certainty that it will be commercially viable to produce any portion of the estimated PIIP, NGIP, COIP or EUR. 30-day IP and short-term rates are not necessarily indicative of long-term
performance or of ultimate recovery.
In this presentation, certain oil and NGLs volumes have been converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). Cfe may be misleading, particularly if
used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well
head. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be
misleading as an indication of value.
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.
3
Canada and United States: Importance of Energy
Partnership
• Bi-Lateral Trade
• Oil
• Natural Gas
• Electricity
• Canada 6th largest oil producer in world (3 MMBbl/d in
2011)
• Canada 3rd largest oil reserves in world behind Saudi
Arabia and Venezuela
• Common objectives to further strengthen
environmental monitoring programs around air, land,
water, and biodiversity
North American* Shale Play Activity
* Canada and United States
Tremendous Asset Base
Leading North American Portfolio of Resource Plays
Biased to organic growth:
We have amassed large,
concentrated, contiguous land
positions in the core of many of
North America’s best resource
plays – at low entry costs.
Greater Sierra
(inc. Horn River)
Cutbank Ridge
Bighorn
Peace River Arch
Duvernay
Clearwater
Clearwater Oil
Collingwood/Utica
Jonah
Niobrara/Mancos
Piceance
Deep Panuke
DJ Niobrara
Mississippian Lime
San Juan
Haynesville
Texas
Eaglebine
Tuscaloosa
Resource Play
Emerging Play
Horizontal Drilling
Traditional Wells
Horizontal Drilling
7
7
Hydraulic Fracturing
Pumping fluid under high pressure to fracture formation

Creates fracture “highway” for
gas to be rapidly produced
from formation
Hydraulic Fractures
8
8
9
Increase in Initial Production Rates
The Result of Shale Development
2.0
1.8
1.6
1.4
1.2
1.0
0.8
0.6
0.4
0.2
0.0
2001
2002
2003
2003
2005
2004
2005
2007
2006
2009
2007
2011
2008
2009
Source: IHS Energy, Encana
9
10
Weekly Average NYMEX Prices
NYMEX Historical Prices
Prompt month traded significantly lower in 2012 than in the previous three years
due to high storage levels coming off a warm winter. A more normal winter
US$/MMBtu alleviated storage concerns, pushing prices back towards historical levels.
6.00
5.50
5.00
4.50
4.00
3.50
3.00
2.50
2.00
1.50
Jan
Feb
Mar
Apr
May
2009
Source: Encana Fundamentals, CME
May
2010
Jun
2011
Jul
Aug
2012
Sep
2013
Oct
Nov
Dec
Coal/Gas Comparison
Source: Energy Information Administration
11
CO2 Emissions
(Million Metric Tons of Carbon Dioxide)
Carbon Dioxide Emission from Energy Consumption
Year (January – October)
Source: Energy Information Administration
12
Encana’s Vision for the Future
Leading North American Resource Play Company
Abundance of natural gas enables an energy plan that will
include…
•
Natural gas as a preferred fuel for power generation
•
Natural gas as a transportation fuel
•
Expanded natural gas use in industrial applications
•
Accessing new markets – LNG export
13
U.S Natural Gas Demand Story
Strong Growth Continues
68
% of Total
Generation
60%
Natural Gas Consumption (Bcf/d)
Share of Power Generation
66
Coal
50%
64
40%
Natural Gas
30%
62
20%
60
10%
0%
Mar-12
Jan-12
Nov-11
Sep-11
Jul-11
May-11
Mar-11
2011
Jan-11
2009
Nov-10
2007
Sep-10
2005
Jul-10
2003
May-10
2001
Mar-10
25
1999
Jan-10
58
1997
Natural Gas Consumption Sectors (Bcf/d)
Electric
20
Industrial
15
Residential
10
Commercial
Plant/Pipeline
5
Transportation
0
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Source: Energy Information Administration (EIA); *3 year growth.
Coal-to-Gas Displacement
Historical and Implied by Natural Gas Prices
The forward curve implies a loss in coal-to-gas displacement of 2.9 Bcf/d
from 2012-2013.
Bcf/d
12
Year-Over-Year
Displacement
10
8
Year
Bcf/d
2011
1.3
2012
4.6
2013F
(2.9)
7.4
6
4.5
4
2.8
2
0
Jan
2011
Apr
2011
Jul
2011
Estimated Historical
Oct
2011
Jan
2012
Apr
2012
Jul
2012
Oct
2012
Implied by Forward Curve
Source: Encana Fundamentals, EIA, Ventyx, NYMEX
Jan
2013
Apr
2013
Jul
2013
Oct
2013
Average Annual Displacement.
Note: forward curve as of January 30, 2013.
Long-term: Coal Unit Retirements
5 Bcf/d Demand Opportunity
Between 2012 and 2025 50 GWs of coal-fired capacity retirements
have been announced, representing a 5.4 Bcf/d potential NG
demand opportunity.
Source: Encana Fundamentals, company announcements.
Transportation and Oil & Gas Opportunity
USA and Canada (Bcf/d)
CURRENT FUEL CONSUMPTION
BY MARKET SEGMENT
Displaceable Market Volume: 73 Bcfe/d
2022 SCENARIO
NATURAL GAS FUELS ADOPTION
Cumulative Demand ~ 4 Bcf/d
Largest Opportunity
47 Bcf/d
Most Commercially Ready
Influence on Early
Adoption
15 Bcf/d
4 Bcf/d
818 MM
kg CO2e
(25%)
317 MM
kg CO2e
(28%)
85 MM
kg CO2e
(28%)
4 Bcf/d
2 Bcf/d
85 MM
kg CO2e
(28%)
42 MM
kg CO2e
(28%)
1 Bcf/d
51 MM
kg CO2e
(28%)
Potential GHG Emission Eliminations
Source: Data and forecast from EIA, Encana
% – Forecast Segment Adoption Level
17
The North American Market is Responding
Infrastructure Growth and Recent Industry Announcements
Total NGV Station Count
1,200
1030
952
1,000
831
825
800
600
400
200
38
44
36
46
0
2008
2009
2010
CNG
2011
Industry Announcements
Station Infrastructure
96
• Shell/Travel Centers of America
− 100 LNG stations planned
• Clean Energy LNG station expansion
− “America’s Natural Gas Highway”
• Encana/Heckmann
− Mobile and fixed stations
• Over 100 new CNG stations planned
LNG
Growth Since 2008
197 CNG Stations & 8 LNG Stations
Total Capital ~$500 Million
New Natural Gas Vehicles and Engines
• “Big 3” offering pick-ups
• Volvo/Navistar – on road
• Cummins/Westport – on road
• Caterpillar/Cummins – off road
• Caterpillar/Westport – rail
Source: Energy Information Administration (EIA), 2010; Statistics Canada; U.S. Dept of Energy AFDC.
Projected New Natural Gas Demand Creation
Excellent Opportunities Diversified Across Many Sectors
Bcf/d
Short Term Medium Term
< 3 yrs
3 to 10 yrs
Long Term
10 years +
Announced Retirements
1 to 2*
2 to 4
4+
Incremental Power
0 to 1
7 to 9
10 to 14 +
Industrial
0 to 1
2 to 3
3+
LNG Export – USA
0
2 to 4
4 to 6
LNG Export – Canada
0
2 to 3
2 to 5
Transportation
< 0.1
1 to 2
2+
Gas to Liquids
0
<1
1+
1 to 4
16 to 26
26 to 35
Total
*A portion of this demand is currently being realized by natural gas.
20
Drilling for Oil
Rig Shift
Rigs
1,800
The number of oil-directed rigs has more than tripled since January 2010, while
the number of gas-directed rigs has dropped by approximately 58 percent.
1,600
1,400
1,200
1,000
800
600
400
200
0
Jan
Jun
2008 2008
Nov
Apr
2008 2009
Sep
2009
Feb
Jul
2010 2010
Oil Rigs
Source: Encana Fundamentals, Smith Bits
Dec May
2010 2011
Gas Rigs
Oct
Mar
2011 2012
Aug
2012
Jan
2013
21
22
The challenges
continue . . .
Challenges Post Election . . .
Regulatory Uncertainty and Public Misperceptions
Water
 Potential contamination

Uses too much

Use produces same amount
of energy regardless of
energy source

Fluid management
regulations
Land

Urban areas

Traffic


Air

Methane leaks

Volatile organic compound
emissions
Values

Industry does not care about the
environment
Noise

Industry is highly profitable
Surface disturbance

Industry gouges public with
excessive gasoline prices
24
Working through the challenges . . .
Engage, Educate, Execute
Advancing Resource Play Hub Development
Track Record of Continuous Supply Cost Reductions
• Substantial cost
reductions through
resource play hub model
• Multi-well pad using fitfor-purpose rig
• Highly efficient
repeatable process
• Cost savings with
minimal surface and
environmental impact
Formation core
Hydraulic pressure
fractures rock)
Productive
formation
Concentrated resource + Pad drilling + Repeatable process =
Resource Play Hub
Q&A
How Do We Protect Ground Water?
Safety at the Surface
Multiple Layers of Groundwater Protection
Surface Casing Cement
Aquifer
Steel Surface Casing
Production Casing Cement*
Steel Production Casing
Production Tubing*
28
*Geologic conditions do not always allow production casing cement to be circulated back to the surface; tubing not always utilized.
28
What’s in the Frac Fluid?
Guar gum /
Hydroxyethyl
cellulose
0.056%
Ammonium Persulfate
0.043%
Potassium carbonate
0.011%
Potassium chloride
0.06%
Sodium chloride
0.01%
Borate salts
0.007%
Isopropanol
0.085%
0.49%
ADDITIVES
Source: DOE, GWPC: Modern Gas Shale
Development In the United States: A Primer (2009)
29
Citric acid
0.004%
Petroleum distillate
0.088%
N,n-dimethyl formamide
0.002%
Acid
0.123%
Glutaraldehyde
0.001%
Other common uses: soap, cosmetics, icecream, toothpaste, water treatment,
disinfectants, medicines
29
Introduction
• The North American natural gas market has undergone a
transformation in which the ability of the industry to deliver gas
to the market has dramatically increased
– Technological advances have unlocked a vast resource
once thought uneconomic to develop
– Shale gas plays now account for about 26 percent of North
American natural gas production
– Resource deliverability is driven by rig count
• IHS Global Insight estimates that the shale gas industry
contributed over 600,000 jobs in 2010 and expects by 2015 that
number could increase to 870,000 jobs
• Immense resource is available with supply cost between $4.00
and $6.00/MMBtu
Note: North America refers to the United States and Canada unless noted otherwise
30
Vast Energy Resources in North America
Technology Continues to Unlock Shale Gas
Resource (Tcf)
At 2011 consumption rates for North
America (~27 Tcf) there is an estimated
86 to 149 years of supply
4,500
4,000
4,014
3,273
3,500
3,000
1,625
1,023
2,500
2,000
980
2,333
627
850
1,500
499
1,000
500
1,409
694
1,400
513
0
NPC 2011
MITei 2010
P90
P50
P10
PGC 2011
NEB
Source: National Petroleum Council, Potential Gas Committee, Canada National Energy Board, MITei, EIAConfidential
North American Annual Supply Deliverability
Assessing the Future Potential
Industry can deploy more rigs and deliver a larger volume of gas
to the market in the future with nominal increase in supply cost
Supply Cost $/MMBtu
(9% after tax return; 2011 costs)
$8.00
$7.00
$6.00
$5.00
$4.00
• Approximate 50/50 spilt oil and gas rigs
$3.00
• Assumes current spud to completion times
$2.00
• Assumes 2011 industry supply cost
structure
$1.00
$0.00
Rig’s
Running
0
5
10
1,500 US : 400 CAN
15
20
25
2,000 US : 600 CAN
30
35
40
2,500 US : 800 CAN
Deliverability from One Year of Drilling (Bcf/d)
Confidential
Source: Encana Fundamentals;
*Note: Does not consider the impact of hedging, JV capital or well inventory.
Piceance Resource Play Hub
Extended Reach S-shaped Wells
N
S
1500’
950’
6000’ from Surface to
Williams Fork Producing
Horizon
4800’
Pay zone = 3000’ thick
33
33
Piceance Resource Play Hub
Best Management Practices
• Multiple wells drilled from one pad
– Reduces surface impact and rig moves
– 52 wells on one 4.2 acre pad!
• Three-phase gathering via pipeline
– No tanks on location = no VOC emissions
• Centralized production facility
– Captures VOC’s
– Treat & recycle over 90% of produced water
• Frac water distribution via pipeline
– Reduces truck trips >150,000/year
• Closed-loop drilling system (all of
Colorado)
– Eliminates waste pit for drill cuttings
34
34
Ethane and its Derivatives
End-Use Demand
Primarily Petrochemical Demand
C2+ NGL
Stream
(Fractionation)
Ethane
C2H6
(DeHydrogenation)
(Turbo Expansion)
Natural
Gas
Crude Oil
Associated
Gas
Refinery/Industrial Fuel,
ResCom Fuel (left in
NG stream)
Ethylene
C2H4
% of Demand
59%
(Polymerization)
Packaging Film, Bags,
Bottles, Toys, Piping,
Fuel Tanks
Polyethylene
n-[C2H4]-n
HDPE, LDPE, LLDPE
(Oxidation)
MEG
Ethylene
Oxide
14%
+ O2
C2H4O
(Hydration)
Ethylene Glycol
+ H2O
HO–CH2CH2–OH
(Polymerization)
(Oligomerization)
Polyethylene Glycol
+ H2O
H-(O-CH2-CH2)n-OH
Alpha Olefins
3%
C4-C30
PVC
(Chlorination)
Chlorine
12%
Ethylene Dichloride
PolyVinyl Chloride
ClCH2-CH2Cl
ClCH2-CH2Cl
Engine coolant,
antifreeze, Polyester
Lubricants, Laxatives,
Skin creams,
Toothpaste
Lubricants, Surfactants,
Wax, Alcohols
Piping, Flooring, Siding,
Fabrics, Sports, etc.
(Alkylation)
7%
Benzene
Ethylbenzene
Styrene
PolyStyrene
C6H5CH2CH3
C6H5CH=CH2
[C6H5CH=CH2]
(Polymerization)
5%
Other Uses
Most widely used
plastic, food packaging,
foam packaging, etc.
Propane, Propylene & Derivatives
End-Use Demand
All Kinds of Demand
C2+ NGL
Stream
(Turbo Expansion)
Natural
Gas
Crude Oil
Associated
Gas
(Fractionation)
Space Heating,
Transport, Industrial,
Farm Use
Propane
C3H8
Refinery
Output
(DeHydrogenation)
Propylene
C3H6
% of Demand
62%
(Polymerization)
Polypropylene
n-[C3H6]-n
Packaging, Food
Containers, Banknotes,
Fabrics, Auto parts
(Oxidation)
8%
+ O2
Polyurethane, polyester
textiles, biological uses
Propylene
Oxide
CH3CHCH2O
(Hydrolization)
Propylene Glycol
H-(O-CH2-CH2)n-OH
(Oligomerization)
Oxo Alcohols
8%
Antifreeze,
Preservative, Textile
Base
Plasticizers
C4-C30
(Alkylation)
Benzene
Cumene
12%
C6H5CH(CH3)2
Plastics Building block
(Phenol)
(Ammoxidation)
10%
Ammonia
Acrylonitrile
C3H3N
ABS Plastic precursor,
acids manufacture
precursor, rubber
precursor
U.S. Natural Gas Liquids
Feedstocks for Petrochemical Production
Ethane
Ethylene
Polyethylene
C2
C2H4
(C2H4)n
Propane
Propylene
Polypropylene
C3
C3H6
(C3H6)n
Propane
C3
Propane
C3
Propylene Benzene
C3H6
+
C6H6
Benzene
Propylene
+
C6H6
C3H6
Source: Encana Fundamentals
Cumene
C6H6.C3H7
Cumene
C6H6.C3H7
Phenol
C6H5OH