emerging plays & technologies - cenovus.com · 1.6 sor sap 4 - 8 wells per section 9,280 net...

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Emerging plays & technologies

Harbir S. ChhinaExecutive Vice-President, Enhanced Oil Development & New Resource Plays

Investor Day | Calgary - June 17 | New York - June 21

Developing our emerging plays

Huge potential

• Release of confidential lands

• 56 Bbbls of discovered BIIP

• 5.4 Bbbls of best estimate contingent resource

Developing a resource play

• Strat well drilling programs

Unlocking resource potential

• Project categories

– developing

– evaluating

– piloting & long-term opportunitiesCenovus land at Dec. 31, 2009.

ALBERTA

BorealisGreater Pelican

RegionBorealis Region

Christina Lake Region

Foster Creek Region

Cenovus land at Dec. 31, 2009.

ALBERTA

2

Oilsands land position1.3 MM net acres*

About a third of Cenovus lands were held under broker

Majority of broker lands have not been delineated

50% of total land position was not included in contingent resource disclosure

Key areas previously undisclosed are in Borealis and Christina Lake regions


Greater Pelican Region

Borealis Region

Foster Creek Region

ALBERTA

Cenovus land Cenovus confidential land*Includes bitumen lands at Pelican Lake and net pull down rights of 0.3 MM net acres.

Christina Lake Region

More than half of Borealis regional lands were previously held under broker

79% of land in this region does not have a well drilled on it

2.6 Bbbls of best estimate contingent resource in Borealis region

Explore and delineate over next 5 years

Borealis - huge untapped resource


ALBERTA

Telephone Lake

Steepbank

East McMurray

Cenovus confidential land

3

Christina Lake - additional land in great reservoir

Over 40% of Christina Lake Regional lands were previously held under broker

23% of land in this region has no wells drilled on it

1.2 Bbbls of best estimate contingent resource in Christina Lake Region

Expect to see similar high quality reservoir throughout this region

Plan to delineate and advance projects over the next 5 years Cenovus land at Dec. 31, 2009.

ALBERTA

Christina Lake

Narrows Lake

WinefredLake

West Kirby

Leismer

Hardy


Cenovus land

0.1 Bbbls best estimate contingent resourceLimited strat well drilling to date60,000 bbls/d (gross) productive potential

West Kirby - great land position

Cenovus land

Devon land

2010 strat well program

4

West Kirby winter drilling plans

Cenovus land

Devon land

2010 winter strat well program

Unlocking resource value

300 – 500 strat wells planned per year

0

200

400

600

2008 2009 2010F 2011F 2012F 2013F 2014F

Foster Creek Region Christina Lake Region Borealis Region Greater Pelican Region

# strat wells

5

0

500

1,000

1,500

2,000

0 w

ps

1 w

ps

2 w

ps

4 w

ps

8 w

ps

Pre

pare

Revie

w

Appro

val

Const

ruct

ion

Develo

ped

Oilsands acreage by development stage

Application

Number of sections based on a gross working interest.

Evaluation Delineation Development

# sections

Evaluation: 0 – 1 wells per section (wps)

First phase of drilling program establishes the location of the resource

Provides a general understanding of resource capability

In relation to reserves and resources we categorize this area as:

• Contingent resources (1 wps)

• Prospective resources (0 wps)

Evaluation

6

Delineation: 4 - 8 wells per sectionSecond phase of drilling program

• Prepare for an application

Provides information for:• Internal approvals

• External approvals

• Reserves

8 wells per section:• Refines map and allows the

start of development plans

• Collect information for Environmental Impact Assessment (EIA)

• Initiate engineering and submit application

EIA

Delineation

Development: 16 - 30 wells per section Final phase of drilling

• Increase well density for approval

• 16 wps or 8 wps + 3D seismic

Drill up to 30 wps for well placement and monitoring operations

• Lateral placement

• Vertical landing depth

• Observation

• Temperature/pressure

• Post steam combustion

Start construction post approval

EIA

Plant location

Well pairs

Development

7

0

500

1,000

1,500

2,000

0 w

ps

1 w

ps

2 w

ps

4 w

ps

8 w

ps

Pre

pare

Revie

w

Appro

val

Const

ruct

ion

Develo

ped

2010 2015F

Acreage by stage of development

Value

# sections

Number of sections based on a gross working interest.

Development

Application

Evaluation Delineation

Opportunity to develop resource base

Base growth plan

Growth

Long term plays

Currentproduction

Fost

er C

reek

&

Chris

tina

Lake

Addi

tiona

l

Opp

ortu

nitie

s

100% WITelephone Lake

100% WIGrand Rapids

50% WINarrows Lake

Growth

100% WIGrosmont

100% WISteepbank

100% WIEast McMurray

50% WIWest Kirby

50% WIWinefred Lake

50% WIClearwater

50% WIFoster Creek Other

Long term plays

8

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Steepbank

West Kirby

East McMurray

Foster Creek Other

Winefred Lake

Telephone Lake

Grand Rapids

Narrows Lake

Strategy & timingRegulatory approval Construction Steam & production

Steam and production includes ~6 months initial steaming with no production followed by 12 - 18 month production ramp up. Timing subject to regulatory approval and project sanction.

65,000

180,000

35,000

30,000

30,000

30,000

30,000

30,000

Initial applicationbbls/d net

430,000

Forecast

32 m of pay

Narrows Lake potential50% WI

130 Mbbls/d (gross) productive capacity

40 - 60 Mbbls/d first phase

2.1 SOR SAGD

1.6 SOR SAP

4 - 8 wells per section

9,280 net acres

0.5 Bbbls best estimate contingent resource

$45 - 55/bbl WTI supply cost

Reservoir similar to Christina Lake


ALBERTA

16-03-82-23W4Start-up2016F

Commissioning2015F

Approval/start construction 2012F

FEED & procurement2011F

Q3 2010 application2010

Milestones

9

Grand Rapids potential100% WI

180 Mbbls/d productive capacity

40 - 60 Mbbls/d first phase

3.0 - 3.5 SOR

1 well per section

52,480 net acres



Consistent and continuous reservoir

Leverages existing infrastructure

16-03-82-23W4

20 m of pay


ALBERTA

Start-up2017F

Construction2014F

Approval Q42013F

FEED/procurement2012F

SAGD pilot strat (1-4 wps) Q4 submit EIA2011F

Strat wells SAGD pilot application2010

Milestones

Telephone Lake potential100% WI


35 Mbbls/d first phase

2.5 SOR

4 - 16 wells per section

36,480 net acres



High quality reservoir

Looking at acceleration options

10-34-94-3W4


ALBERTA

37m of pay

Approval2013F

Additional application2012F

Amend existing application2011F

Strat well and water testing2010

Milestones

10

Strategy of our technology developmentTarget one innovation every year

• Reduce energy intensity

• Reduce footprints

• Perpetually replenish ‘hopper’of promising ideas

Creation of intellectual property• Maintain competitive advantage

• Assure technology user rights

• 14 total patents - 7 obtained, 7 pending

• More than 50 technical papers published

Sustainable funding – increasing from $20 - 40 million per year

Energy efficiency

~ 50 projects

rejectedleads

Environmental protection

Impro

ved

proce

ss

accepted technologies

Impact of technology development

26

28

30

32

34

36

38

40

42

44

46

48

Time

Supp

ly c

ost

redu

ctio

n (

US$/b

bl)

Solvent Aided Process

Electric Submersible Pumps

Liner improvements

Wedge wells

Wedge well optimization

Others

Low pressure SAGD

Reservoir tailored processes

Liner design optimization

Blowdownboilers

Insulated tubing

$10 - $15 reduction

target

forecasthistory

Non-condensable gas co-injection

0

2

4

6

8

10

14

16

18

12

Supply cost is defined as the average WTI or NYMEX price required for an after-tax cost of capital return of 9%.

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Cenovus’s Solvent Aided Process (SAP)SAP versus SAGD metrics

• 30% production rate improvement

• 15% incremental total oil recovery

• 3% reduction in annual fuel gas usage

• 0.05 bbls solvent (butane) purchased per bbl bitumen

• 30% increase to initial capital

• 10% decrease in annual sustaining capital

• 5 - 10% reduction in non-fuel operating cost

• ~$1.00/bbl netback uplift

Environmental benefits• Lower SOR and emission intensity

• Lower water usage & footprint

Steam & solvent (SAP)

Steam only (SAGD)

Pilot Foster Creek pad SAP2010 – 2011F

Q3 SAP & SAGD Narrows Lake2010

Christina Lake isolated test2009 – 2011F

Christina Lake SAP pilot2004 – 2005

Senlac SAP pilot2000 – 2001

Milestones

Cenovus’s combustion technology

Wabiskaw• Air injection pilot June 2006• 3.0 Bcf of gas recovered • Heated underlying bitumen• Q4 2010 conventional oil well

test• No contingent resource

assigned

Clearwater• Gas cap Air Injection for Thermal

Oil Recovery (GAITOR)• Pilot 2012• 197 MMbbls best estimate

contingent resource

Combustion front moves through gas

Air injector

Heat transfer into bitumen zone

Gas producer

Primary hwell producer

Air injector

Heatedoil

Heatedoil

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Risks and mitigation

Stakeholders• Continue to integrate stakeholder relations in our business

Regulatory• Prepare additional project applications targeting 400 – 500

Mbbls/d net in 2015

• Work with government to streamline and improve the approval process

Labour competition• Modularization (Nisku), small work packages, small

contractor strategy

Technical• Culture of innovation and experienced staff

Cenovus unleashes potential

Huge organic growth opportunity

• 56 Bbbls discovered BIIP

• Move projects to development stages to build net asset value

Proven record of applying new technologies

• Increases returns, improves operations, lowers footprint

• Low capital requirements for R&D potential generates higher value

Long track record of project execution and operational performance

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Winefred Lake potential50% WI

60 Mbbls/d (gross) productive capacity


2.5 - 3.0 SOR

2 wells per section

22,840 net acres


$60 - 65 bbl WTI supply cost

Reservoir similar to Christina Lake

1AA/05-16-076-04W4W4/0


ALBERTA

30 m of pay

Regulatory approval & construction2015F

8 wps submit application2013F

8 wps2012F

4 wps start EIA & application2011F

2 wps (drill 10 wells)2010F

Milestones

14

East McMurray potential100% WI



2.5 – 3.0 SOR

1 well per section

35,520 net acres



New Maps to ComeCenovus land at Dec. 31, 2009.

ALBERTA

07-20-90-5W4

23 m of pay

Submit EIA & application2015F

8 wps2014F

4 wps2013F

2 wps start EIA2012F

1 wps exploration2011F

Milestones

Grosmont potential100% WI

< 1 well per section

15,500 acres

Early stage resource characterization

Pilots to test recovery technologies

Carbonates not included in contingent resource estimate


ALBERTA

Pilot2015F

Strat well program2014F

Strat well program2013F

Pilot2012F

Strat wells, seismic, pilot application2011F

Strat well deepening2010F

Milestones

15

Emerging plays summary

124 – 1614 - 8Current well density (wps)

60 - 6560 - 6555 – 6560 - 7045 - 55Supply cost ($/bbl WTI)

0.70.30.70.90.5Best estimate contingent resource (Bbbls)

35,52022,84036,48052,4809,280Land position (net acres)

2.5 - 3.02.5 - 3.02.53.0 - 3.52.1 SAGD

1.6 SAPSOR

606050180130Potential size (Mbbls/d gross)

1005010010050Working interest (%)

East McMurray

WinefredLake

Telephone Lake

Grand Rapids

Narrows Lake

The resources estimates were prepared effective December 31, 2009 by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator (IQRE), and other than as disclosed herein are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook (COGEH). For further discussion regarding our economic contingent resources and our total bitumen initially-in-place and all subcategories thereof, see our April 22, 2010 news release and our June 16, 2010 news release, respectively, available at www.cenovus.com. Actual resources may be greater than or less than the estimates provided. Total Bitumen Initially-In-Place (BIIP) (equivalent to “total resources”) is that quantity of bitumen that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of bitumen 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. BIIP estimates include unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be recovered. Discovered Bitumen Initially-In-Place (equivalent to “discovered resources”) is that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations prior to production.The recoverable portion of discovered bitumen initially-in-place includes production, reserves, and contingent resources; the remainder is categorized as unrecoverable. There is no certainty that it will be commercially viable to produce any portion of the estimate. Undiscovered Bitumen Initially-In-Place (equivalent to “undiscovered resources”) is that quantity of bitumen that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered bitumen initially-in-place is referred to as “prospective resources,” the remainder as “unrecoverable”. There is no certainty that any portion of the estimate will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Exploitable Bitumen Initially-In-Place is the estimated volume of bitumen, before any production has been removed, which is contained in a subsurface stratigraphic interval that meets or exceeds certain reservoir characteristics considered necessary for the commercial application of known recovery technologies. Examples of such reservoir characteristics include continuous net pay, porosity, and mass bitumen content. This definition was derived from and is consistent with current draft proposed COGEH terminology. Contingent resources – those quantities of bitumen 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. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. For Cenovus, the contingencies which must be overcome to enable the classification of bitumen contingent resources as reserves include regulatory application submission with no major issues raised, access to markets and intent to proceed by the operator and partners as evidenced by major capital expenditures planned within five years. The estimate of contingent resources has not been adjusted for risk based on the chance of development. There is no certainty that it will be commercially viable to produce any portion of the resources. Economic contingent resources – those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. The IQRE used the same commodity price assumptions that were used for the 2009 reserves evaluation, which were determined in accordance with U.S. Securities and Exchange Commission requirements. Prospective resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. Unrecoverable is that portion of discovered or undiscovered BIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. Proved reserves are those quantities of bitumen, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. Probable reserves are those additional reserves of bitumen that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered. Our disclosure of annual reserves data is made in accordance with U.S. disclosure requirements pursuant to an exemption received from the Canadian Securities Administrators. Accordingly, the proved plus probable reserves data may differ from corresponding information prepared in accordance with NI 51-101. See “Note Regarding Reserves Data and Other Oil and Gas Information” in Cenovus’s 2009 Annual Information Form (AIF). Certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). BOE 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.

Oil & gas information

16

This presentation contains certain forward-looking statements and information about our current expectations, estimates and projections about the future, based on certain assumptions made by the Company in light of its experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct.

Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast” or “F”, “target”, “project”, “objective”, “could”, “focus”, “goal”, “proposed”, “scheduled”, “outlook”, “potential”, “may” or similar expressions suggesting future outcomes or statements regarding an outlook, including statements about our strategy, our projected future value or net asset value, schedules, land positions, production, including, without limitation, the stability or growth thereof, reserves and resources estimates, material properties, uses and development of our technology, risk mitigation efforts, commodity prices, shareholder value, cash flow, funding alternatives, costs and expected impact of future commitments in respect of our ongoing operations generally and with respect to certain properties and interests held by Cenovus. Readers are cautioned not to place undue reliance on forward-looking statements and information as our actual results may differ materially from those expressed or implied.

Forward-looking statements involve a number of assumptions, risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The risk factors and uncertainties that could cause actual results to differ materially, and the factors or assumptions on which the forward-looking information is based, include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions inherent in our current guidance; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; the effect of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; success of hedging strategies; maintaining a desirable debt to cash flow ratio; accuracy of our reserves, resources and future production estimates; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our ability to replace and expand oil and gas reserves; the ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate the North American integrated heavy oil business and to obtain necessary regulatory approvals; the successful and timely implementation of capital projects; reliability of our assets; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology and its application to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or the interpretations of such laws or regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on us, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats, hostilities, civil insurrection and instability affecting countries in which we operate; risks associated with existing and potential future lawsuits and regulatory actions made against us; our financing plans and initiatives; the historical financial information pertaining to our assets as operated by Encana prior to November 30, 2009 may not be representative of our results as an independent entity; our limited operating history as a separate entity and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. The forward-looking statements and information contained in this presentation, including the assumptions, risks and uncertainties underlying such statements, are made as of the date of this presentation.

Many of these risk factors are discussed in further detail in our 2010 First Quarter Report to Shareholders, our 2009 AIF/Form 40-F and our MD&A for the year ended December 31, 2009, each as filed at www.sedar.com and www.sec.gov, and available at www.cenovus.com. The Cenovus 2010 Corporate Guidance, including the assumptions on which it is based, is available at www.cenovus.com.

Non-GAAP measures (Operating Earnings, Operating Cash Flow, Cash flow, Free Cash Flow, Capitalization and Adjusted EBITDA) have been described and presented in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations. Please see our 2010 First Quarter Report to Shareholders for a full discussion of the use of each measure.

Forward-looking information

emerging plays & technologies - cenovus.com · 1.6 sor sap 4 - 8 wells per section 9,280 net...

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