This presentation deals with the impact of cleantech on the economics of oil and gas operations. It covers and in-depth look at the cleantech industry as it relates to oil and gas, shale gas, hydraulic fracturing, disposal of waste fracturing fluid, water use in the oil sands, as well as the future of water management in Alberta and the oil sands.

1. The Impact of Cleantech on the Economics
of Oil and Gas Operations
AIPN Banff International Conference
September 15, 2011
Presented by: John Goetz
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2. What is “Cleantech”?
• Clean technology, or “cleantech,” should not be confused with enviro‐
technology or “green tech”
• Cleantech is new technology aimed not only at providing solutions to global
challenges, but also at providing competitive returns for investors and
users*
• Examples of greentech or enviro‐tech are “end‐of‐pipe” technology like
smokestack scrubbers – these technologies are typically required by
regulation and represent a cost rather than an efficiency opportunity ‐
limited opportunity for return*
• Cleantech typically addresses the roots of problems with efficient and
economically based science and technology solutions – may re‐configure
existing technology in a different way to leverage efficiency
* Cleantech Group: What is Cleantech? Clean is more than green www.cleantech.com/what‐is‐cleantech
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3. What is “Cleantech”?
• Where greentech has typically represented small, regulatory‐driven
markets, Cleantech is driven by productivity‐based purchasing, and
therefore enjoys:
– Greater financial upside
– broader market appeal ‐ more rapid adoption
– sustainability*
• Cleantech represents a diverse range of products, services, and processes,
all intended to:
– Provide superior performance at lower costs
– Significantly reducing or eliminating negative ecological impact
– Improving the productive and responsible use of natural resources*
* Cleantech Group: What is Cleantech? Clean is more than green www.cleantech.com/what‐is‐cleantech
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4. Cleantech in Oil & Gas
Some Key Benefits and Objectives of Cleantech
• Reduce the overall environmental footprint of oil & gas operations,
including reducing the amount of:
• land utilized – horizontal drilling and SAGD operations
• Water utilized – water treatment and recycling
• Energy utilized ‐ energy efficient motors, pumps, etc.
• Emissions generated – less fuel burned, CCS, EOR
• Reduce the cost of operations while achieving the above objectives
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5. Examples of Cleantech in Oil & Gas
Electric Submersible Pumps
• Cenovus has introduced electrical submersible pumps (ESPs) into its SAGD
operations as an alternative to using natural gas to bring the oil to the
surface.
• One of the benefits of using ESPs is a reduction in Cenovus’ steam to oil
ratio (SOR) ‐ the amount of steam it takes to produce a barrel of oil.
• As a result of using ESP’s and other cleantech solutions, Cenovus reports its
SOR is one of the lowest in the industry at 2.5 (2.5 barrels of water to
produce one barrel of oil)
• A low SOR results in: lower water usage, more efficient use of steam, a
reduction of emissions per barrel of oil recovered and an overall reduction
in operating costs.
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6. Examples of Cleantech in Oil & Gas
Devon’s Coleman Gas Plant
• plant produces 50 million cubic feet of natural gas per day
• 9 million gallons of water per year – all from Crowsnest River
• Water use slashed by implementing a water recycling system and by
switching from a steam‐driven pump to an electrical pump. Result:
– a nearly 40 percent reduction in both fresh water taken from the river and
wastewater requiring disposal.
• After filtration, much of the produced water is clean enough to re‐use.
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7. Examples of Cleantech in Oil & Gas
Devon’s Coleman Gas Plant
• Reducing wastewater provides several environmental benefits.
– virtually eliminated the need to haul waste water through several towns to the
disposal site 120 miles away.
– Saved approx. 3.6 million gallons of fresh water each year
– Eliminated approx. 4,100 five hour round hauling trips
– Saved approx. $1,064,000 in hauling fees annually
– Saved water disposal/injection costs for 3.6 million gallons
– Reduced greenhouse gas emissions, environmental impact and road wear
– Offsets generated by GHG emission reductions can be measured and
monetized or used to achieve Devon’s own emission reduction requirements
• Replacing the plant’s steam‐driven motor reportedly saved nearly 4,700
gallons of water per day. Rain water that falls onsite is also captured and
used to make steam and then is recycled.
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8. Shale Gas and Cleantech
• Shale Gas development has enormous potential in North America and other
parts of the world
• Conventional gas production in North America declining significantly
• New Technology is providing access to previously uneconomically shale gas
formations
• Increased availability and production of shale gas a game changer in North
America and potentially the world
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9. Shale Gas and Cleantech
• Shale Gas development has raised environmental concerns
• Environmental groups out in front of issue again citing negative experience
in U.S.
– Fresh Water Use
– Hydraulic Fracturing Chemicals
– Potential Groundwater Contamination
– Disposal of Waste Fracturing Fluid
• Fracking being done or proposed to be done in areas that do not have long
history of oil and gas activities
– Quebec
– New York
• “Gasland”
– http://www.energyindepth.org/2010/06/debunking‐gasland/
– http://gaslandthemovie.com/
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10. Shale Gas and Cleantech
• EPA research on fracking and drinking water protection under way with goal
to complete research by end of 2012
• Awaiting results of government inquiries/hearings (eg. Quebec)
• Shareholder Association for Research & Education (SHARE) recently advised
investors to mitigate their risks when investing in companies engaged in
hydraulic fracturing
• Issues being raised will demand Cleantech Solutions
• Technologies like Devon and Seair are using are the beginning of addressing
at least some of the environmental issues that could hinder or stop shale
gas development in North America and elsewhere
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11. North American Shale Gas Plays
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12. Hydraulic Fracturing – “fracking”
• Common method of extracting gas from tight shale formations
• Shale formation artificially fractured by pumping fluid into wellbore at
extremely high rates and pressures
• Fluid usually contains suspended “proppant” (e.g sand)
• Once cracks/fractures created, most of fluid pumped out of well and
proppant left behind, propping open the fractures
• Fluid pumped out is disposed of or may be recycled
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13. Disposal of Waste Fracturing Fluid
• Typically in Western Canada, disposed of by re‐injection into saline zones
using water disposal wells
• Some times it is re‐used for industrial purposes
• If areas do not have disposal wells, water may be treated and disposed of in
other ways pursuant to provincial regulation (e.g. trucked to
industrial/hazardous waste disposal facilities)
• Environmental groups believe diluted waste fracking fluids are being
injected into areas near DWAs even when fluids contain chemicals that
require disposal as hazardous waste
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14. Shale Gas and Water*
Devon’s Cleantech Solution in Barnett Shale
• Capturing natural gas from the Barnett Shale in northern Texas requires at
least 4 million gallons of water per well.*
• Recycling the required water costs about 40 % more than traditional
disposal methods
• Through its recycling partner, new clean technology allows Devon to recycle
175,000 gallons a day (63 million gallons/year)
• Innovative process involves boiling flow‐back water to create steam and
separate the salty concentrate
• Through late‐2010, Devon had recycled nearly 500 million gallons ‐ enough
water to fracture shale at more than 100 wells
• The result: Distilled water that is suitable for drinking, but instead is
transported to other nearby Devon well sites, where it is used again
* http://www.dvn.com/CorpResp/initiatives/Pages/Initiatives‐WaterRecycling.aspx
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15. Shale Gas and Water*
Devon’s Cleantech Solution in Barnett Shale
• Reduces the need for obtaining water from farm ponds, streams or
municipalities and cost of purchasing water
• Because the fracturing process requires fresh water, which is a dear
commodity in most drilling locations, Devon is exploring ways to incorporate
this process in other areas and make the process more cost‐effective –
possibly by sharing the cost of each recycling unit among multiple gas
producers.
• Devon’s technology partner wants to expand the technology further by
developing a pipeline network to use treated sewage in the fracturing
process to further reduce demand on community water resources.
* http://www.dvn.com/CorpResp/initiatives/Pages/Initiatives‐WaterRecycling.aspx
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16. Cleantech in the Oilsands
• Oil Sands development is increasing and is expected to double from current
levels by 2020
• Fastest Growing Source of GHG emissions in Canada
• Fastest Growing water use sector in Alberta
• Multiple Water Quality and Treatment issues arising
• Increased national and international focus and criticism of oil sands
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17. Water Use in the Oil Sands
• Water allocations in Alberta are growing the fastest in the Athabasca River
basin where oilsands operations are concentrated ‐ nine times faster than
the provincial average.
• Water Allocations have increased by 88 per cent since 2000
• The largest sector use of water in the Athabasca River basin is for oil and
gas, representing about 64.5 per cent of total allocations in 2008
• Between 2000 and 2008, allocated volumes for the oil and gas sector
increased by over 200 per cent, due to rapid oil sands development
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18. Water Use in the Oil Sands
• In 2008, the oil sands industry withdrew about 151 million cubic metres of
water from the Athabasca River
• Other sources of water include precipitation captured in the active mine
area and groundwater that is pumped to prevent the mines from filling
with water
• Oil sands mining is expected to grow to 3.5 million barrels/day by 2020 and
use up to 2.5% of the natural flow of the Athabasca River.
• Oil sands in situ recovery currently uses approx. 17 million cubic meters of
fresh water per year. Industry has begun using more saline water and
saline exceeded fresh water in 2007
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19. Water Use in the Oil Sands
• The amount of fresh water required with forecast growth is expected to
reach 22 million cubic meters per year by 2015 (this is equal to about ½ the
fresh water use of a city the size of London, Ontario)
• CAPP expects in situ producers to use less than ½ a percent of Alberta’s
current water allocation by 2020, and still produce 40% of Canada’s crude
oil at that level.
• Devon’s Jackfish Project uses 100% saline water and typical in situ projects
recycle 90% of the water produced with the oil.
• Fresh water is defined as having less than 4000 mg/L total dissolved solids
(TDS) and saline water has > 4000 mg/L TDS
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20. Water Use in the Oil Sands
• There is seasonality in river flows which require managed withdrawals
during low flow periods (winter)
• AENV/DFO regulate max. oil sands water withdrawals weekly, depending
on the river flow
• During the winter low flow period (October 29 – April 22) water availability
is capped at a level where the maximum withdrawal rate is less than the oil
sands mining demand.
• Water conservation and storage from higher flow periods (within license
limits) is utilized in these periods.
• Industry is investing hundreds of millions of dollars into additional water
storage facilities to work within low flow limits
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21. Water Use in the Oil Sands
Tailings Ponds
• There is currently approximately 500 million cubic meters of water and
dissolved waste in tailings water inventory
• Tailings ponds cover approx. 170 square kilometers (approx. ¼ of the size of
the City of Calgary
• Life of tailings ponds can be 30 – 40 years with only one (Suncor’s Pond 1)
reclaimed thus far
• New technologies are being developed and implemented to treat tailings
water and recycle it instead of storing it in ponds
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22. Water Use in the Oil Sands
Tailings Ponds
• AENV, SRD and ERCB all involved in regulatory initiative for tailings
management including ERCB Directive 074 (oil sands mining)
• all oil sands mining companies must submit an tailings management plan to
satisfy ERCB that they can achieve compliance
• Operators must submit tailings performance reports to ensure they are
meeting their targets
• Regulations may need to change to encourage water recovery from tailings
ponds
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23. Water Use in the Oil Sands
Tailings Ponds
• Under the directives in place or under consideration, water that is
recovered from tailings ponds or other industrial operations is considered
fresh water.
• This provides little incentive for In‐Situ operators to utilize recovered
tailings water
• Due to the difference in operations, it is more efficient to recover tailings
water for In Situ than if a mine were to treat the water for re‐use.
• Directive 074 (Tailings Management) provides indirect incentive by
requiring reductions in water tailings
• Flexibility with the intent of promoting net environmental benefit must be
engrained in the policy, terminology and text.
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24. Conventional Oil and Gas
Dewatering of Surface Mines/Oil Sands
– Seair’s surface mining water treatment systems provide
high volume on‐site processing of underground water in
connection with preparation or operation of surface mines.
– After treatment using Seair technology, underground water
meets standards for discharge into the environment
– Dramatically decreases water infrastructure costs by
eliminating diversion and storage of non‐compliant
underground water (into dedicated ponds or tailing ponds)
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25. Conventional Oil and Gas
Dewatering of Surface Mines/Oil Sands
– Tailing pond capacities are effectively increased without any
physical changes or expansion
– Economic payback of less than 6 months – useful life well
over 10 year
– Each diffusion unit is capable of treating 1‐6 m3/min while
lifetime storage could be $2/m3
– Operating costs are essentially nil total savings of $2 per
cubic meter
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26. Conventional Oil and Gas
Seair’s Cleantech Solution in Shale Gas formations
• Produced water recycling ‐ creating a closed loop oil field
water treatment system (mobile/on‐site or centralized
facility)
• Treated water suitable for reuse in a variety of
applications (e.g., brine water for top hole drilling or fresh
water for hydraulic fracturing)
• Gas‐based system has very low energy consumption
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27. Conventional Oil and Gas
Seair’s Cleantech Solution in shale gas formations
• Treatment gas generated on‐site and very limited
consumables in treatment process
• Reduces total cost of water (disposal and fresh water costs)
relative to conventional procurement and disposal practices
• Decrease/eliminate water trucking (pick‐up and disposal)
• Eliminate water procurement cost
• Decrease/eliminate biocides
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28. Conventional Oil and Gas
Seair’s Cleantech Solution in shale gas formations
• Eliminate water disposal costs
• Potential revenue stream from reselling treated water
• Higher hydrocarbon recovery rates from wastewater due to
superior oil/water separator
• Normally difficult to remove hydrocarbons are captured and
sold partially offsetting treatment costs
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29. Water Management Frameworks, Policies and
Regulations
Examples of some of the new policies and regulations currently under development or implemented include
but are not limited to:
• Lower Athabasca Regional Plan under the Land Use Framework
• Phase 2 update to the AENV/DFO Water Management Framework: In Stream Flow Needs and
Water Management System for the Lower Athabasca River
• AENV Tailings Water Management Framework (being drafted)
• Groundwater Management Framework
• ERCB Requirement for Water Measurement, Reporting, and Use for Thermal Insitu Oil Sands
Schemes (Draft Directive)
• ERCB Directive 074 Tailings Performance Criteria and Requirements for Oil Sands Mining
Schemes
• AENV Assessment and Management of Non‐saline Groundwater in Direct Contact with
Bitumen for In situ Oil Sands Operations
• Lower Athabasca Watershed Planning and Advisory Council (future recommendations)
• Minister’s Advisory Group Recommendations for Improving Alberta’s Water Management and
Allocation
• Alberta Water Council Recommendations for Improving Alberta’s Water Management System
for the Lower Athabasca River
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30. The Future of Water Management in Alberta and the
Oil Sands
• Alberta is taking numerous steps to manage its water
resource through out the province with its Regional Plans
and Water Management Frameworks for specific regions
and basins
• Approach has been to involve industry in studies, plans and
frameworks and also to get industry investing in
technologies that will assist in managing water use and
water quality
• Expect more regulation in the area as Regional Plans and
Water Management Frameworks are completed and refined
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31. Addressing Oil Sands CO2e Emissions
• Oil sands GHG emissions were 37.2 Mt (1 Mt = 1 million tonnes)
in 2008.
• This represents:
– 15 per cent of Alberta emissions
– 5 per cent of Canadian emissions
– less than 0.1 per cent of global emissions
• Canada's total emissions grew by 155 Mt between 1990 and
2007
• Oil sands emissions responsible for 14 per cent (22 Mt) of this
increase
• Transportation responsible for 36 per cent (55 Mt) of increase
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32. Addressing Oil Sands CO2e Emissions
Cogeneration
• Cogeneration is an important aspect of oil sands operations. It allows
facilities to create their own steam and electricity needs at the same time –
achieving significant energy savings.
• Facilities use less fuel with this method than if the steam and electricity
were created separately, thereby reducing the amount of GHG emissions
released to the atmosphere.
• Surplus electricity from cogeneration (if any) is fed into the provincial grid,
reducing the need for additional coal‐fired generation.
• Cogeneration projects have been responsible for a significant portion of
Alberta industry’s real emission reductions
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33. Addressing Oil Sands CO2e Emissions
Carbon Capture and Sequestration (CCS)
• CCS is expected to be the major source of emission reductions for the oil
sands
• Alberta is investing $2 Billion into CCS Pilot Projects
• Four key projects – Two are oilsands and enhanced oil recovery (EOR)
related:
Quest Project (Shell, Chevron and Marathon)
– Carbon Capture facilities at Scotford Oilsands project that would
capture carbon dioxide (CO2) from all three of the Upgrader's hydrogen
plants.
– The hydrogen plants combine steam and natural gas (methane) to
produce hydrogen used for upgrading.
– The proposed project would involve capturing up to 1.2 million tonnes
per annum of CO2 at the Scotford Upgrader.
– CO2 would be compressed into liquid form for pipeline transportation
– No current plan to use CO2 for EOR – so no economic benefits
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34. Addressing Oil Sands CO2e Emissions
CCS and EOR
Alberta Carbon Trunkline Project (Enhance Energy)
• Potentially world’s largest carbon‐capture and storage project
• Create a pipeline system to transport CO2 to mature oil reservoirs for EOR
• Enhance says its project will sequester 14.6 MT’s of CO2 each year when it
reaches full capacity (equivalent of removing 2.6 million cars from the road
annually)
– help solve the CO2 emission challenges of many oilsands operations, power
plants, fertilizer plants and refineries
– Generate incremental EOR production, revenues and royalties for years to
come
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35. Addressing Oil Sands CO2e Emissions
CCS and EOR
Alberta Carbon Trunkline Project (Enhance Energy)
• Potential Emission reduction value of $200 million annually @ $13.75 per
tonne (based on 14.6 MT/yr. reductions)
• Enhance will receive $495 million from Alberta and $63 million from Canada
to build an infrastructure that will:
– help solve the CO2 emission challenges of many oilsands operations, power
plants, fertilizer plants and refineries
– Generate incremental EOR production, revenues and royalties for years to
come
• Enhance expects the ACT to reduce the carbon footprint per barrel of
oilsands synthetic crude to one of the cleanest in the world
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36. Addressing Oil Sands CO2e Emissions
CCS and EOR
Alberta Carbon Trunkline Project (Enhance Energy)
• The CO2 is captured and compressed into liquid form and moved in a 240‐
kilometre pipeline to the Clive oil field, where it will be injected to produce
light oil using EOR technology.
• Using EOR technology, Enhance and its partner expect to access up to 25
million barrels of oil that remains in the ground ($900 million ‐ $1.8 Billion @
$75/bbl)
• ACT infrastructure will bring on additional sources of CO2 supply over time
and allow other EOR projects to access CO2 more easily and economically,
which will make currently uneconomical projects profitable and potentially
stimulate other EOR projects and more oil and gas production
* Enhanced Oil Recovery Through Carbon Capture and Storage, An Opportunity for Alberta, Alberta Economic Development Authority, January 2009.
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37. Addressing Oil Sands CO2e Emissions
CCS and EOR
Alberta Carbon Trunkline Project (Enhance Energy)
• Proven technology ‐ EOR process was pioneered in
Saskatchewan by PanCanadian Energy Corp. to revitalize its
Weyburn oil field. Enhance’s CEO Project Manager
• Original oil in place in Weyburn field estimated at 1.4 billion
barrels
• Prior to EOR, 370 million barrels had been recovered
• With EOR, now producing approx. 28,000 boe/day and
expected to produce an incremental 160 million barrels over
the next 30 years. * ($12 Billion @ $75/barrel)
* Enhanced Oil Recovery Through Carbon Capture and Storage, An Opportunity for Alberta, Alberta Economic Development Authority, January 2009.
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38. Cleantech in Conventional Oil and Gas
• Cleantech continues to have an impact on conventional oil and gas drilling
and production
• CVT Corp has developed a variable speed generator that has been able to
provide dramatic fuel savings for pump jack operations
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39. Cleantech in Conventional Oil and Gas
CVT VariGen‐50 kW (Iveco Engine)
• Installed for Petrobank at Estevan, Saskatchewan
• Client was using a 125 KW Diesel genset
• The motor size was 30HP
• 125 KW Diesel fuel consumption averaged 5.5 GPH
• Replaced unit with the VariGen‐50
• Fuel consumption on the Varigen‐50 was 2.0 GPH
• resulting in a 64% drop in fuel consumption
• Using current fuel pricing ‐ savings of $250/day ($90,000/yr)
• Consider savings when employed on multiple pump jacks
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40. Cleantech in Conventional Oil and Gas
VT VariGen‐50 kW (Kubota Engine)
• Hunt Oil and Gas Pump Jack at Grande Prairie, Alberta
• Using a 100 KW Rental Package with an Isuzu 6B1 engine. The load
requirement varied between 17‐55 amps on 480V power
• Motor size ‐ 30HP
• Measured fuel use averaged 2.7 GPH
• Installed VariGen‐50 kW on the same load
• Fuel consumption measured 1.9 GPH
• 30% drop in fuel consumption. ‐ savings of $1500/month.
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41. Impact of Emission credits
associated with Cleantech
Regulated and non‐regulated markets
• Alberta has an operating regulated market (only one in
Canada)
• Generated $63 million in emission reductions and required
emitters to spend $126 million in 2010.
• EU has a regulated emissions market that allows offsets
• Kyoto signatories can use offsets to meet their targets
• Offsets sell from $13.00 ‐ $14.00 per tonne in Alberta and have
recently ranged between €7.00 – €14.00 for Certified Emission
Reductions (CER’s)
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42. Impact of Emission credits
associated with Cleantech
• Voluntary market for emission reductions has slowed but
voluntary market credits have ranged between $5.00 ‐ $10.00
and sometimes higher
• Integrating an emission reduction project (measurement,
monitoring, verification and monetization) can enhance the
economics of most Cleantech projects that involve reduction
of fossil fuel use and resultant reduction of CO2e emissions
• Regulatory and Voluntary markets exist around the world,
allowing potential opportunities for Cleantech projects
implemented in participating jurisdictions
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43. Cleantech’s Economic Impact
• Cleantech is by definition, geared toward providing economic returns on
investment and deployment
• The sampling of projects sited have generated $millions in savings and have
the potential to generate $billions in increased production, emission
offsets and cost savings
• These numbers represent hard dollars/Euros, not soft environmental
accounting
• Microsoft and Google are investing in Cleantech in a major way for a
reason – they believe companies that adopt Cleantech solutions as a key
operating principle will be building a foundation for profitability – the proof
is in the pudding
• Harvard Business Review says Cleantech investment will reach tens of
trillions of dollars in the next 30 years.
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44. For Further Information
Contact:
John C. Goetz
(403) 268‐7167
John.Goetz@fmc‐law.com

45. John Goetz is a partner in the Energy Group at Fraser Milner Casgrain LLP. John has extensive experience advising clients in
the energy sector, including in‐house experience at a major oil company. John co‐leads the Cleantech and Emissions Trading
Group and brings his energy and cleantech experience and insights to this emerging area of practice.
John works closely with energy clients on their corporate commercial matters and has significant experience with large oil
sands construction and infrastructure projects, cleantech projects and technology commercialization, mergers and
acquisitions and operational matters. John also advises energy and cleantech clients on climate change strategy, emissions
trading and renewable energy projects.
As a leading climate change and cleantech practitioner, John has advised on three of Alberta's first carbon capture and
sequestration projects and has co‐authored a report for Alberta Economic Development Authority on Enhanced Oil Recovery
in Carbon Capture and Storage. For more information on John’s practice, go to www.fmc‐law.com/People/GoetzJohn.aspx

46. The preceding presentation contains examples of the kinds of
issues companies dealing with Cleantech technologies could face.
If you are faced with one of these issues, please retain
professional assistance as each situation is unique.