The Future of Natural Gas CAPL June General Meeting Luciano Dalla-Longa | Group Lead, Natural Gas Economy Calgary, Alberta | June 22nd | 2011

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: years of drilling inventory and number of drilling locations; North American estimated years of supply of gas and total resource potential; estimates of future natural gas prices; expected economics of new power generation using natural gas; forecast North American gas production for 2011 and beyond; and projected increase in demand for natural gas for power generation and transportation. 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: the risk that the company may not conclude potential joint venture arrangements with others; volatility of and assumptions regarding commodity prices; assumptions based upon the company’s current guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the company’s and its subsidiaries’ marketing operations, including credit risks; imprecision of reserves and resources 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; 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 replace and expand gas reserves; 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; 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. Forward-looking statements with respect to anticipated production, reserves and production growth, including over five years or longer, are based upon numerous facts and assumptions, including a projected capital program averaging approximately $6 billion per year that underlies the long-range plan of Encana, which is subject to review annually and to such revisions for factors including the outlook for natural gas commodity prices and the expectations for capital investment by the company achieving an average rate of approximately 2,500 net wells per year, Encana’s current net drilling location inventory, natural gas price expectations over the next few years, production expectations made in light of advancements in horizontal drilling, multi-stage well completions and multiwell pad drilling, the current and expected productive characteristics of various existing and emerging resource plays, Encana’s estimates of proved, probable and possible reserves and economic contingent resources, expectations for rates of return which may be available at various prices for natural gas and current and expected cost trends. 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. Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation, and, except as required by law, Encana does not undertake any obligation to update publicly or to revise any of the included 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.

Who is Encana? 

Leading North American energy company – Calgary, Alberta – Denver, Colorado



100% production and reserves located in North America



One of the largest producers of North American natural gas – Current Production: 3,300 MMcfe/d – 23,000 Net Drilling Locations – $24B Market Capitalization (May 2011)

Natural Gas Economy Our mission is to establish natural gas as the foundation of North America’s energy portfolio

– Abundant! – Affordable! – Clean! – Reliable! – Domestic Solution!

4

AGENDA 

Supply



Demand



Price



Power Generation



Environmental Regulation



Summarize

Vast Energy Resource in North America Technology Continues to Unlock Shale Gas Canada and U.S. Resource Estimates Years of Supply

North American Natural Gas Basins

Tcf 3,300

120

85

Abundant and Widespread 80

88

92

97

102

2,750 2,200

60

1,650 1,100

40

550 0

0 PGC 2006

EIA/NEB Navig't 2007 2008

Reserves

ICF 2008

EIA/NEB 2009

PGC 2009

Resource

• 2,600 Tcf of Total Resource • 100+ Year Supply at 70 Bcf/d • 70+ Year Supply at 100 Bcf/d

Sources: EIA, CSUG, IHS, Encana

North American Technology Renaissance Rapidly Increasing Production

Bcf/d

Projection

Actual

100

Conventional Reservoirs 9% Growth

80

60

40

Shale Gas Reservoirs 20

0 2000

Production is growing due to horizontal drilling and fracturing

2002

2004

2006

2008

U.S. Conventional U.S. Unconventional

Source: IHS & NEB historic data, Encana projection at $6.50 NYMEX

2010

2012

2014

2016

2018

2020

Canada Conventional Canada Unconventional

United States Natural Gas Demand Historical Perspective The natural gas market has seen little demand growth over the last 15 years. Bcf/d

70 Fuel

60 50 40 30

Use Act

c tri c e l nE r i e th ow Pow r G

Electric Power Gains, Industrial Declines

s os r ac s s ga tor f c o n se o y i pt an o m Ad

20 10 0 1949 1954 1959 1964 1969 1974 1979 1984 1989 1994 1999 2004 2009 Source: Encana, EIA

Cost of Supply – 2011 Many plays economic below $4 - All are economic below $6/mmbtu

$/mmbtu

Increasing Expected Ultimate Recovery (EUR) of gas by 10 - 20% would further reduce the average break-even economics by ~$0.30/mmbtu and ~$0.50/mmbtu respectively.

Current Economics 10% EUR Increase 20% EUR Increase

Natural Gas Prices Past, Present, and Future Natural gas prices have risen over time with increased use, except for periods of oversupply during the 1990s and more recently 2009-11. $9

$/MMBtu

$8 $7

Supply Unable to Keep Pace with Demand

$6

Supply/Demand Return to Balance

$5

1970’s Oil Crisis

$4 $3 $2

2009 Recession

$1 $0 1950

Gas Bubble Era 1960

1970

1980

Historical Wellhead Price Source: EIA

1990

2000

2010 AEO 2011

2020

Natural Gas Can Make the Greatest Impact Canada and US Energy Consumption by Sector - 2009 Input Energy Consumption (281 Bcfe/d)

Annual CO2 Emissions (6.1 Billion Metric Tonnes)

79 Bcfe/d Transport 28%

Industrial 21%

Transport 33%

110 Bcfe/d

Electric 39%

2.0 Billion MT

2.3 Billion MT

Electric 39% Commercial 5%

Residential 7%

Industrial 18%

Residential 6% Commercial 4%

Need to focus on Electric Power and Transportation Sectors (70% of total emissions) to move the “Emission Reduction Needle” Source: EIA AEO 2010 Preliminary Release, CANSIM, Environment Canada, ECA Calculations

Cleaner, Healthier Air Comparing Natural Gas to Diesel and Gasoline in Transportation Estimated Emissions Reductions Summary

* Compared to traditional diesel and gasoline engines Source: NGVAmerica, Encana estimate, EPA

Natural Gas - Cleaner, Healthier Air Estimated Emissions Reductions vs. Coal for Power Generation

Source: Naturalgas.org, EPA

Canada and US Electrical Generation What if 25 Bcf/d of additional Natural Gas is used? Mix Vision (4,290 TWH)

Current Mix (4,290 TWH) Renewables 18%

Nuclear 21% Oil 1%

Gas 17%

Renewables

18%

+25 Bcf/d Domestic Gas

Gas 49%

Nuclear 21%

Coal 43%

Oil Coal 1% 11%

930 MM tons of CO2 reduced plus large reduction in NOX and SO2

2,000 1,500

10

1,000

5

500

0

0 CO2 GHGE NOX

SO2

CO2E Emissions

15

NOX / SO2 (x10^2) Emissions

CO2E Emissions

2,500

2,500 2,000

15

37% 39% Reduction Reduction

1,500 1,000 500

10 73% Reduction 52% Reduction

0

5

NOX / SO2 (x10^2) Emissions

Emissions (Million Metric Tons) 20 3,000

Emissions (Million Metric Tons) 3,000 20

0 CO2 GHGE NOX

Sources: EIA Annual Energy Outlook 2010, EIA GHG Emissions Overview, Statistics Canada

SO2 14

Gas Generation’s – Competitive Advantage Natural Gas Parity with Coal Without $25 per tonne CO2

Coal adjusted for efficiency and CO2 Cost @ $25/t

Coal adjusted for efficiency penalty vs Natural Gas

Historical Price per MMBtu $16

$16

$14

$14

$16

$12

$12

$14

Natural Gas

Natural Gas $12

$10

$10

Coal

$10

$8

$8 $8

$6

$6 $6

$4

$4

Natural Gas

$4

$2

Coal

$0 Dec01

Dec- Dec02 03

Dec04

Dec- Dec05 06

Dec07

Dec- Dec08 09

Dec10

Gas prices are higher than coal for the raw commodity

$2

Coal

$2 $0 Dec01

Dec02

Dec03

Dec04

Dec05

Dec06

Dec07

Dec08

Dec09

Dec10

Adjusted for efficiency, coal is now on par with gas

Sources: NYMEX Oil, Coal and Gas Spot Prices

$0 Dec01

Dec02

Dec03

Dec04

Dec05

Dec06

Dec07

Dec08

Dec09

Dec10

Coal is currently higher cost than gas

Power Generation Intro Physics & Operations

Energy Watt-Hour Directly convertible into BTUs

 

=

Power

x

Watts Instantaneous rate of energy use

Hours The length that the energy use is sustained

Consumer Example (retail)

Power Plant Example (wholesale) A 500 Megawatt power plant for 3 hours at maximum load

Time



A 300 Watt computer running 1 year = 300 Watts x 24 Hours x 365 Days

– = 500 MW x 3 hours

= 2600 kilowatt-hours (Kwh)

– = 1,500 Megawatt Hours (MWh) of electrical energy

= 2.6 Megawatt Hours (MWh)

A 100 MW combined-cycle natural gas plant (as baseload) requires 12-15 mmbtu/d of natural gas to operate

Power Generation Levelized Cost Introduction 

What does Levelized Cost mean? (Compares ‘apples to apples’ based on output energy)



The average cost of the energy produced from an electric power generator over its service life, considering all costs in the lifecycle of the plant, including the following:



Capital expenditure and construction costs



Fuel costs



Maintenance and other charges



(think of a fixed mortgage payment over the energy produced)

Economics of NEW Power Generation AEO 2011 Reference Case – Reflects $15/ton CO2 Price US$/kWh $0.40 $0.35 $0.30 $0.25 $0.20 $0.15 $0.10 $0.05

d W in

So l

ar

Th e

rm

al -O ffs ho re IG So C C la C rP o C a V l on w it h ve nt C io C S na l A G dv as an C ce T d N uc le ar B io m as s IG A C dv C C an oa ce l d G as C T G eo th W er in m al d -O C ns on A ho dv ve re an nt io ce na d lC N G oa C C l w it h C C S C on ve H nt yd io ro na lG A as dv C an C ce d N G C C

$0.00

Levelized Capital Cost Variable O&M (incl. fuel) Sources: EIA, Annual Energy Outlook 2011.

Fixed O&M Transmission Investment

Coal Electricity Generation Train Wreck

Uncertainty of environmental regulation has dramatically increased the cost of new and existing coal fired generation, creating massive capital costs. 19 Public Power Magazine Jan/Feb 2011

Pending EPA Health and Environmental Regulations 

2011



Clean Air Transport Rule (June 2011)



Utility MACT HAPS (Hg) (November 2011)



2012



Green House Gas Rules (May 2012)



Coal Combustion Residuals - Ash (July 2012)



Cooling Water Regulations (July 2012)

Incremental Coal Unit Retrofit Costs No Carbon Cost

Environmental retrofits approach the cost of a new gas generation

New Gas Combined Cycle Cost (EIA 2011)

Source: ICF International Estimates

Levelized Power Cost Regulatory - Light $125

Base Operating Cost*

SCR Costs

FGD Costs ACI Costs

DSI Costs Ash Costs

Incr. Opex

CO2 Cost

~6.4 GW (37%) of Capacity at Risk

$57.60/MWH Levelized Cost of New NGCC Assets

$100

$75

$/MWH

$50

$25

*Includes fixed, variable and fuel costs

Source Data: AEO 2011, Ventyx, Andover Technology Partners

35

34

U nit

U nit

32

33

U nit

31

U nit

30

U nit

29

U nit

28

U nit

27

U nit

26

U nit

25

U nit

24

U nit

23

U nit

22

U nit

21

U nit

20

U nit

19

U nit

18

U nit

17

U nit

U nit

15

16

U nit

14

U nit

13

U nit

12

U nit

11

U nit

U nit

9

U nit

10

8

U nit

7

U nit

6

U nit

5

U nit

4

U nit

3

U nit

2

U nit

U nit

U nit

1

$0

Levelized Power Cost Regulatory - Heavy Base Operating Cost* SCR Costs DSI Costs Water Cooling Costs Incr. Opex

$125

Fabric Filter FGD Costs ACI Costs Ash Costs CO2 Cost

~ 12.6 GW (76%) of Capacity at Risk $63.56/MWH Levelized Cost of New NGCC Assets

$100 $/MWH

$75

$50

$25

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 Unit 6 Unit 7 Unit 8 Unit 9 Unit 10 Unit 11 Unit 12 Unit 13 Unit 14 Unit 15 Unit 16 Unit 17 Unit 18 Unit 19 Unit 20 Unit 21 Unit 22 Unit 23 Unit 24 Unit 25 Unit 26 Unit 27 Unit 28 Unit 29 Unit 30 Unit 31 Unit 32 Unit 33 Unit 34 Unit 35

$0

*Includes fixed, variable and fuel costs

Source Data: AEO 2011, Ventyx, Andover Technology Partners

Switching Opportunity Total US Coal Capacity: 314 GW (Net Summer)

ANNOUNCED 28 GW

30-50 GWs of coal (10-16%) likely to shutdown representing enormous gas demand potential. (3.5 -4.0 Bcf/day)

Retirement Studies

Credit Suisse Bernstein GS Barclays Moderate CATR Low 27 GW 37 GW 38 GW 32 GW

GS High 45 GW

Fitch “At Risk” 51 GW

NERC CATR Harsh 56 GW

Credit Suisse All Regs: Harsh 108 GW Wall Street

GWs Everyone Else PIRA Moderate 31 GW

ANGA/B&V NERC Light Moderate 41 GW 42 GW

PIRA Harsh ANGA/B&V Base 54 GW

Wood Mackenzie 60 GW

ANGA/B&V Heavy 112 GW

1 GW of capacity can produce enough power for 750,000 homes

Canadian Coal Generation 

Opportunities for Natural Gas Generation



Nearly all coal plants nationally will retire by 2020 due to Federal regulations



Total Potential Demand Creation from Coal to Gas: 1.7 Bcf/d



Saskatchewan 4000 MW (300 MMcf/d Potential)





–

Expectation that inexpensive mine-mouth co al poses a challenge to gas economics

–

Only 3 coal plants exist, 2 of which are “young” (30 or less years)

Ontario 31,300 MW (500 MMcf/d Potential) –

Has plans to retire all coal by 2014

–

All coal is marginally economic with no retrofits

–

Applying similar US air quality rules in Canada would cause all units to retire (except for 2 Lambton units which are marginally positive)

Alberta 12,800 MW (800 – 1,000 MMcf/d Potential) –

Very inexpensive mine-mouth coal ($1.20/MMBTU or less)

–

Relatively high power prices ($60/MWH for Generation)

–

Even with a CATR-like standard, no coal would economically retire

–

Need to reduce carbon emissions may increase cost significantly

Encana’s Advocacy for Natural Gas 

Colorado 1365: Clean Air Clean Jobs Act – Led successful industry coalition – Retirement of 900 MW of coal fired electricity generation capacity – New demand for ~150 mmcf/d of gas

Quantitative Analysis: Coal Unit Shutdown Potential

– Landmark result to influence other jurisdictions 

Coal to Gas Switching Strategy – Quantitative analysis identified U.S. opportunity 

3.7 – 8.3 Bcf/day – varies with regulatory scenario

– Venue analysis identified “high value” targets 

Michigan, Tennessee Valley Authority

– Collaborative and Industry Regulations Approach 

Other Advocacy – Provincial / Municipal efforts 

Alberta, Saskatchewan, Ontario

– Federal Canadian and U.S. efforts 

Rebuttal on pending regulations in Canada on Coal Generation retirement regulations



Collaboration with U.S. Merchant Coal generators



Providing comment and rebuttal on US EPA rules

Strong shutdown risk Moderate shutdown risk Weak shutdown risk

North American Opportunities and Challenges 

New abundance of natural gas will change North America’s energy portfolio. – Natural gas will displace coal for power generation.



Benefits of increased natural gas demand – Economic Development benefits – Jobs and spinoff (70,000 jobs per 1bcf/d) – Natural gas economy and energy security – Air quality and climate change benefits



Challenges – Lack of and misinformation on coal vs benefits of gas fired generation – Technology to drill wells is poorly understood throughout society. Industry needs to take ownership 

Communicate and regulate towards best practices

Questions?