Building Support for the “Arctic” Project November 18, 2002 Houston, Texas, USA Jim Harrington Houston Energy Group, LLC
Jan 23, 2016
Building Support for the “Arctic” Project
November 18, 2002 Houston, Texas, USA
Jim HarringtonHouston Energy Group, LLC
2
“Arctic” Project: Briefing Outline
Houston Energy Group 2
ENVIRONMENT Gas Supply
Options Gas Value Chain
ARCTIC STUDY History, Scope and
Conclusions Route Options Supply/Demand
Assessment Economic
Assessment Environmental
Considerations
Technological Advancements
Regulatory Challenges
Findings/Recommendations/Conclusions
BEYOND THE STUDY New ‘Project’ Matters Building Project
Support
This briefing is not advocating Alaska versus Mackenzie, or ‘Over the Top’ versus TransAlaskan pipeline route.
Its about:
ENVIRONMENT – understanding the Arctic competition
ARCTIC STUDY – understanding the Arctic Project
BEYOND THE STUDY – positioning to optimize the Arctic result.
3
Environment: Gas Supply Options
Houston Energy Group
Global Energy DataCategory Gas Oil
Reserves
Bn BOE (Tcf)
1,100 (6,600)
1,050 (6,300)
Production ‘01
Bn BOE (Tcf)
15
(89)
27.5
(165)
RLI - Years 74 38
A complete turnaround from the last Arctic discussion: • For every 1 Tcf consumed
since 1990 3.4 Tcf have been proven.
• Reported proven global natural gas reserves surpassed oil in 2001; double on a reserve life index (RLI) basis.
• Monetization of stranded gas via LNG, GTL, etc. is increasing in country/company priority.
• Competing projects (e.g., LNG) continue to come down in cost - improving their competitiveness.
Growing Proven Gas Supply
Volume 1980 1990 2000 2002
Tcf 2,650 4,200 5,300 6,600
3
4
Environment: LNG Options
Houston Energy Group
There are 15 operating LNG plants in 12 countries (shown as darker circles) with many more planned, and some under construction: Norway, Egypt, Malaysia III and with new contracts: Indonesia – Tangguh.
10 of the 12 countries with LNG plants are expanding liquefaction capacity (but not Alaska, Libya).
Dark countries import LNG, and shaded countries are considering it. The large numbers represent where the proposed new plants are.
Nigeria II
Egypt: Idku
Yemen: Bal Haf
Egypt: Damietta4
Papua New Guinea
Australia: Gorgon
Australia: Bayu Undan
Australia: Sunrise8
Russia: Sakhalin II
Irian Jaya: Tangguh
Angola: Luanda
Bolivia: Margarita12
Brazil: Amazon
Peru: Camisea
Iran: South Pars
Norway: Snohvit16
Indonesia: Natuna
Canada: Hibernia
Russia: Yamal
Alaska: North Slope20
Equatorial Guinea: Alba
Venezuela I: Shell
Venezuela II: BG
Nigeria – West Delta24
3 7 11 15 19 23
2 6 10 14 18 22
1 5 9 13 17 21
1
2
3
9
5
6
8
15
1413
11
10
47
12
20%
20%
60%
1
2
3
4
5
6
78
9
10
11
12
13
14
15
16 19
18
17
20
21
2223
6
8
5
122
24
4
5
Environment: LNG Capacity - liquefaction
Houston Energy Group 5
Includes some expansion at existing terminals and some new terminals.
Currently Oman, Malaysia, Australia, Qatar and Trinidad &Tobago, etc. are building LNG spec. capacity. The existence of excess gas supply and an open access US receiving terminals are feeding this.
0
50
100
150
200
250
1964 1969 1974 1979 1984 1989 1994 1999 2004 2009
YEAR
MMtpa
Slope = 12.9 MMtpy,more than double the 90’s
Approximate: 1 MMt = 50 Bcf 1 Tcf = 20 MMt
At existing terminalsdoes not include these expansions:Trinidad #5,6 = 8Nigeria #6 = 4Qatargas #5,6 = 9.5Rasgas #5,6 = 7TOTAL = 28.5 MMt
Does not included:Angola-LuandaBrazil-AmazonEquatorial Guinea-AlbaPeru-CamiseaVenezuela-PVLNGAU: GorgonAU/E Timor: SunriseAU: Scotts ReefIndo: NatunaIran: South ParsNigeria: W. DeltaCanada: HiberniaAlaska: North SlopePapua New GuineaRussia: YamalEtc.
The following 7 countries have announced they want to be the largest LNGsupplier (about 40 MMt each): Trinidad & Tobago, Nigeria,Algeria, Qatar, Malaysia,Indonesia, and Australia.
6
Environment: LNG Capacity - Shipping
Houston Energy Group
0
50
100
150
200
250
2002 2003 2004 2005 2006 2007
# of Ships Needed for Plants
Recently there has been a shortage of LNG ships (for example, this reduced the LNG available to US in the 2000 year because of high US gas prices then). There are 132 ships now, up from 118 a year ago.
Current ships being built (industry capacity = 28/year with 3 years to build) will greatly exceed the LNG growth as this supply chain unbundles and the entrance of more companies wanting to own their ships.
Currently 6 to 8 ships being built per year that are not dedicated to a LNG project.
6
LNG Ship Surplus
7
Environment: LNG Capacity – US Receiving
Houston Energy Group
Location Peak Capacity
(Bcf/d)
Peak Expansion
plan (Bcf/d)
Connecting pipelines
Everett, Mass 0.435 0.565 Tennessee, Algonquin
Elba Island, Geo.
0.4400.360
(CP02-379)
Southern,SCANA
(proposed)
Lake Charles, La.
0.630 0.570
(CP02-60)
TrunklineHeader
Cove Point, Md. 1.200 0.250Columbia,
PECO
Hackberry, La. 0 1.5
Sabine, Florida Gas,
Transco, Tx. Eastern
Total 2.705 3.245
Combined Total 5.95 Bcf/d
When Cove Point goes into operation in 2003 capacity will be 2.7 Bcf/d, with plans to expand to 4.45 Bcf/d.
Hackberry, La. application (CP02-374) for 1.5 Bcf/d and many others (more than 20) are being planned in Canada, US, Bahamas and Mexico. LNG has averaged about 0.65 Bcf/d the last three years, so there is substantial upside without significant additional facilities.
7
8
Environment: LNG Value Chain
During this decade the LNG market will be in a position ofexcess supply and capacity.
In addition, its cost to delivercontinues to decrease with further decreases expected going forward … table is illustrative only – to US some LNG sites are lower and someare higher.
Arctic failed in the 1970s because of domestic production gains. Will it beInternational gas this time?
Ships give LNG projects theopportunity to switch gas markets - an advantage.
Houston Energy Group
Excess Supply
Excess Capacity
Excess Capacity
Excess Capacity
Value Chain after: 1995 2002 2010 Comment
To Market $4.25 $3.50 $3.10 To destination market
Gasification $3.95 $3.25 $2.85 Into market as natural gas
Shipping $3.55 $2.95 $2.55 To terminal as LNG
Liquefaction Plant $2.65 $2.40 $2.10 As LNG at the plant
Pipeline, Shrink $1.40 $1.50 $1.40 Net-gas at the LNG plant
Netback (and local taxes)
$0.50 $0.75 $0.75 Netback (excludes condensate)
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9
Environment: North American Gas Supply
The competitive alternatives to Arctic gas today are greater than they were in the 1970s.
In addition, by pipeline: Canadian Hibernia, Colombia and Venezuela gas reserves are ‘closer’.
Houston Energy Group
At gas prices between $2.75 and $3.75 (Chicago Hub) there are a growing number of potential supply sources.
CS = Coal seam methane
9
West Supply EastLNG: North Slope Sable Is.• Alaska (?) Mackenzie Delta Hibernia• Existing LNG CS – WCSB LNG:• Bolivia Deep Gulf of Mexico • Trinidad• Peru CS – US Rockies • Venezuela• Timor Sea Colombia • Algeria• Irian Jaya Venezuela • Nigeria• Indonesia-Natuna Others • Angola• Papua New Guinea • Egypt• Sakhalin Is. • Norway• Gorgon • Middle East• Canada (?) • Eq. Guinea• Others (?) • Others(?)Into supply connects to markets
10
Environment: North American Gas Demand
Gas demand in NA (US, Canada, Mexico) was approximately 27 Tcf in 2001 (same as 2000), and is forecast to approach 38 Tcf by 2020.
Our projection is more conservative than some as it reduces industrial demand for ammonia, methanol and other gas intensive industries. At $3.00+ gas prices – these businesses will go elsewhere (next to a LNG plant).
This demand will not be realizedat prices above $4.00.
Houston Energy Group
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
Year
Bcf
10
US L48 States
Mexico
Canada, Alaska
11
“Arctic” Study: History, Scope, Conclusions
We performed a thorough study of Arctic gas options into North America a year ago,and it has been updated sincethen.
That study concluded that theproject was commercial,competitive, and was possible under existing technologies, environmental and regulatory requirements.
Some results were publishedin the Oil & Gas Journal thenand I will update then for younow.
Houston Energy Group
All deal killers
were within the
control of the
Arctic
participants
All deal killers
were within the
control of the
Arctic
participants
HISTORYStudy 1st done in 2001 for INGAA Foundation.
The Foundation is represented by US and Canadian pipelines and their suppliers.
HEG and URS Corporation prepared the Study
Study updated by HEG North American supply
options, demand levels, and price
North American infrastructure requirements
SCOPE, CONCLUSIONS Environmentally
Feasible … YES Technically
Feasible … YES Regulatorially
Feasible … YES Commercially
Feasible … YES Competitive … YES
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12
“Arctic” Study: Route Options Studied
Houston Energy Group
SIX OPTIONS STUDIED
--- Proposed ANGTS--- Proposed Dempster Lateral--- Proposed Mackenzie Valley--- ‘Over the Top’--- Northern – Onshore--- TAGS (LNG)
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13
“Arctic” Study: Gas Price Forecast
Houston Energy Group
0
1
2
3
4
5
6
US
$ p
er M
MB
tu
Henry Hub Chicago
Empress Calif Border
Current Year Prices
0
1
2
3
4
5
6
Henry Hub 1.47 1.76 2.11 1.91 1.71 2.67 2.48 2.08 2.27 4.3 3.96
West TexasIntermediate/6
3.59 3.43 3.08 2.86 3.06 3.68 3.43 2.4 3.21 5.06 4.33
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001
Gasx6 / Crude Oil (%)
41 51 69 67 56 73 72 87 71 85 91
Oil / 6
Gas
We support a sustainable $2.75-$3.75 price range.
In the 1990s Henry Hub spot gas price averaged 64% of WTI: $2.05/MMBtu v $19.16/Bbl.
Due to technology (CCGT generation) and environment drivers we forecast gas prices to rise to 75% of oil price in NA on an energy basis. $19.16/Bbl $2.40/MMBtu $24/Bbl $3.00/MMBtu
US gas prices have averaged above 70% of oil since 1995.
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14
“Arctic” Study: Supply and Demand
Houston Energy Group 14
North American Supply and Demand
Demand, 15%
Demand, 50%
35% Demand in Supply
Infrastructure as key as supply.
• In 2001 > 90% (i.e. 69 out of 75 BCF/d) of gas from ‘Supply’ zone.
• 50% of gas demand came from provinces and states east of this ‘Supply’.
• Lines indicate additional supply sources.
• Key finding: need for additional pipeline capacity from ‘Supply’ to east and west coast markets. Pipeline routes and access through Ontario and Ohio are key to retaining an integrated gas market.
15
“Arctic” Study: Gas Supply Options
Houston Energy Group
Canada32%
LNG5%
GOM Off27%
GOM On10%
Rockies10%
Other16%
Source of Annual Incremental Gas (Tcf)
Source Potential 2010 2015
Arctic 1.4 - 2.2 1.4 1.4
LNG 1.1 - 2.2 1.4 2.1
WCSB-Canada 0.5 - 2.6 0.8 1.0
US Rockies 0.4 - 2.0 0.6 0.9
GOM (Net) 1.5 - 3.5 2.0 2.8
Other Basins (Net) (1.0) - 1.5 0.3 0.7
TOTAL 6.0 - 13.5 6.5 8.9
Source of Incremental Gas to US
Source: 2001 GTI Baseline for 2020
The table on top summarizes the sources modeled to meet the projected increase in demand. This study was done on a basin-by-basin, LNG plant-by-LNG plant basis, and assumed pipeline infrastructure would be built (big assumption).
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16
“Arctic” Study: Gas Reserve
Houston Energy Group
Arctic Gas Supply Reserves
Source Reserves (Tcf) Comment
Alaska North Slope 31 Proven
Mackenzie Delta 13.5 Proven (50 fields)
Eagle Plain (Yukon) 0.1 Proven (4 fields)
Mackenzie Corridor 0.4 Proven (3 fields)
TOTAL ARCTIC 45 Proven
NA (L48,LCanada, Mexico
157+144+30 = 331 Proven (excl. Arctic)
TOTAL NA 376 Proven (Incl. Arctic)
Compared to 2000 NA consumption of 27 TCF, or Reserve Life Index (RLI) = 14with Arctic reserves connected, up from 11.
Arctic gas reserves are proportionately greater than Arctic oil reserves were back when the oil pipeline was built from the North Slope in the 1970s.
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“Arctic” Study: Commercial Advantages
Houston Energy Group
Domestic source Liquid content lower oil
imports Gas demand for enhanced
oil from tar sands production
Lowers NAFTA dependence on oil imports
Common ownership between gas reserves and tar sands reserves
Arctic gas delivered into supply grid:
More market choices Improves reliability of
integrated network
Location of AlbertaTar Sands
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18
“Arctic” Study: NAFTA Energy Balances
Houston Energy Group
NAFTA imports more than 1/3 of its liquid petroleum requirements.
A tripling of Alberta tar sands oil production to 2 million barrels per day would lower NAFTA’s net liquid imports 20% everything else being equal (and potentially consume 1.5 Bcf/d … ideally from the Arctic).
18
Natural Gas (in Bcf per year) 1999 2000 2001
Gas Production 23,908 27,257 27,351
Gas Exports 64 66 66
Available 23,845 27,191 27,285
Gas Imports 161 223 238
Domestic Gas Consumption 24,005 27,414 27,523 Import Dependence 0.7% 0.8% 0.9%
Liquids (Thousand Barrels Per Day) 1999 2000 2001
Liquids Production 11,408 11,596 11,566
Liquid Exports 9 10 10
Available 11,399 11,586 11,556
Liquid Imports 5,993 6,196 6,437
Domestic Oil Consumption 17,392 17,782 17,993 Import Dependence 34.5% 34.8% 35.8%
Note: Liquids = Oil, NGL, other petroleum products.Does not include LNG.
NAFTA GAS BALANCE
NAFTA LIQUID ENERGY BALANCE
United States, Canada and Mexico
United States, Canada and Mexico
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“Arctic” Study: Study Regions
Houston Energy Group
10 Study Regions:1 – Arctic2,3 – Canada4-9 – US (EIA’s 6 regions)10 - Mexico
19
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“Arctic” Study: 2000 Gas Balance and Flows
Houston Energy Group
Note: Gas balances do not sum to zero due to rounding and change in storage inventory.
Gas Balance by Region and Interregional Flows: 2000 (BCF/d)
0
14.6(3.6)
(9.9)
(4.9)
(12.2)3.4
21.8(7.6)
(0.1) 2000 DemandIn TCF:
Canada 2.9L48US 22.8Mexico 1.3Total 27.0
This chart shows the difference between annual supply and demand in each of the 10 study regions, and the average day flows between regions, in year 2000 (BCF/d.)
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21
“Arctic” Study: 2015 Gas Balance and Flows
Houston Energy Group
Note: Gas balances do not sum to zero due to change in storage inventory.
Gas Balance by Region and Interregional Flows: 2015 (BCF/d)
3.8
17.2(4.3)
(14.9)
(4.6)
(15.1)4.1
22.3(10.8)
2.3
5.7
5.2 10.1
0.1
0.8
2.4
3.3
14.8
5.0
5.0
3.5
6.4
2.1
3.8
2.4
3.8
2015 DemandIn TCF:
Canada 4.1L48US 29.5Mexico 2.3Total 35.9
This chart shows the same difference between annual supply and demand in each region, and the average day flows between regions - in 2015 (using the study assumptions)
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22
“Arctic” Study: Change in Balance & Flows
Houston Energy Group
Note: Gas balances do not sum to zero due to change in storage inventory.
Change in Gas Balance by Region and Change in Interregional Flows: 2015 (BCF/d)
3.8
2.6(0.7)
(5.0)
0.3
(2.9)0.7
0.5
(3.2)
2.4
0.7
0.5
2.1
Increase inDemand (TCF):Canada 1.2L48US 6.6Mexico 1.0Total 8.9
This chart shows the difference between 2000 and 2015, or the change in demand and supply by region, and the average day interregional flows needed to meet demand.
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“Arctic” Study: New Infrastructure Needed
Houston Energy Group
Note: The figures will not balance because it reflects peak day requirements, not average flows
Capacity Additions within Regions and Between Regions: 2000 - 2015 (BCF/d)
0.5
5.01.5
6.9
1.5
5.51.4
5.0
4.5
2.7
1.8
4.2
We need the
Equivalent of
4 new Alliance
Pipelines to the
Northeast
within 15 years
We need the
Equivalent of
4 new Alliance
Pipelines to the
Northeast
within 15 years
Average day data needs to be converted to peak day to measure the amount of new pipelines needed.
We did this using assumptions of peak day demand.
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“Arctic” Study: Comparing Project Economics
Houston Energy Group
Annual Unit Rate Capacity Capital Operating @ 95%
LFProject BCF/d $Bn $Bn $/MCF
ANGTS 4/6 $10/$13 $1.5/$1.95 $1.08/$0.94Dempster Lateral 2 $3.5 $0.5 $0.72Mackenzie Valley 2/4 $4/$5.5 $0.6/$0.8 $0.87/$0.58Over-the-Top 6 $13 $1.95 $0.94Onshore Prudhoe- Mackenzie 6 $12 $1.80 $0.87
Project economics to Boundary Lake, Alberta
Desktop study using industry best practice adjusted upward for environmental, technical, other factors identified in Study.
Annual Operating Cost includes return on and of investment at 70/30 D/E.
Only Pipeline Options Shown
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“Arctic” Study: Positive Economic Assessment
Houston Energy Group
Arctic Commerciality ($ Per MMBtu)
Pricing Point Price Explanation
Chicago Hub $3.50 Assumed long-term contract price Alberta/British
Columbia Border$2.60 Alliance Pipeline tariff
used as an example
Arctic Wellhead $1.60 Wellhead Netback Price
Table showing producer netback in Arctic using study pipeline cost assumption at $1.00 per Mcf.
Arctic project requires $3.00-$4.00 per MMBtu gas price.
Below $3.00 and producer netback unlikely to be attractive.
Above $4.00 and gas demand is unlikely to be adequate.
New pipeline capacity is needed to the markets (east and west coasts) … which the study quantified.
Note – this wellhead price is higher than assumed with ‘illustrative’ LNG project.
25
26
“Arctic” Study: Positive Economic Assessment
Houston Energy Group
Arctic Pipeline Liquids
Category Amount Explanation
Assumed Gas Production
6.0 BCF per Day
Available Liquid Heat Content
0.1 100 BTUs per MCF assumed extracted as liquids in Alberta
Liquids Extracted
0.6 BCF equivalent per Day
Liquids 100,000 Barrels per Day assuming 6 MCF per Barrel
Note – Does not include ‘Alliance’ technology in pipeline design.
Arctic gas production would also increase domestic liquids production ... Here is an illustrative calculation.
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“Arctic” Study: Environmental Considerations
Our study identified the keyenvironmental issues that needed to be addressed in a Arctic type project.
We also identified the specialconsiderations that such a pipeline would need to consider.
These were based on currentrequirements, and not thosein existence when ANGTS wasapproved.
Our study included knownMitigation measures and optionsfor these issues and considerations.
Houston Energy Group
Key environmental issues:1) Environmental discharge,2) Oil spills and cleanup,3) Cumulative effects of development,4) Effects on subsistence lifestyles of native
communities, and5) Inclusion of traditional knowledge
Special considerations include:1) Endangered species,2) Subsistence hunting,3) Seasonal construction/repair,4) Permafrost,5) Ice gouging,6) Leak detection, and7) Strudel scour
27
28
“Arctic” Study: Technology/Process Gains
Our study identified new technologies for both designand construction as well as ongoing operations and maintenance. Our focus herewas on technologies during thepast decade rather than goingback too far that could be applicable to Arctic projects.
Houston Energy Group
Design and Construction:
1) High strength steels
2) Design changes
3) Construction in frozen land improvements
4) Automated ultrasonic testing
5) Directional drilling under rivers and
streams
6) Composite reinforced line pipe
Operation & Maintenance:
1) GIS
2) Inline inspection tools
3) Electronic flow measurement and automated operations
4) SCADA data analysis
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“Arctic” Study: Regulatory Complexity
Houston Energy Group
Regulators Relevant to the MackenzieValley Pipeline
RegulatoryCoordination
CEAA
DIAND
NEBDFONWT
AUB
NWTWater Board
Sahtu LandUse PlanningBoard
IMF
MVLWB
Grwich’in LandUse PlanningBoard Deh Cho
MV EnvironmentalImpact ReviewBoard
Illustration of regulatory complexityThe regulatory complexity for anArctic project is higher than mostpipelines to-date. This chart forthe Mackenzie Valley Pipelineroute … possibly the leastcomplex because it only involvestwo Canadian provinces.
Regulatory collaboration, coordination and compromise are critical success factors:
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Mackenzie Valley PipelineJune 2002 Cooperation Plan• MOU – Invialuit participation in environmental review (10/1)• Draft EIR – Environmental Impact Review public (10/7)
30
“Arctic” Study: Regulatory Challenges
Houston Energy Group
• Access roads, bridges• Erosion control, ponds, parks • Cultural, endangered species data• Direct property owner payments• Property taxes• Equipment rental, consumables• Local employment, training
Potential Landowner Benefits
Key hurdle Native land access & land claims.
A very important element in any Arctic pipeline is successfully dealing with Native issues, which are substantial, but so are the potential benefits … a case of finding the win-win solution “early” before sides are taken.
Feasible, but certainly the most challenging the industry has faced.
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“Arctic” Study: Some Key Findings
Again, we found Arctic wasfeasible from a regulatory,technical and environmentperspective.
Our analysis of the projectProvided higher netback atthe wellhead compared tothe competition.
Houston Energy Group
Environment Feasible Unique to Arctic Mitigation and monitoring
Technology Feasible Since ANGTS: significant advances,
including experience with TAPS Liquids rich gas a la Alliance
Competitive Feasible Netback comparable Enhance oil from tar
Regulatory Feasible Multi-jurisdictional: Collaboration,
Coordination and Compromise required Key Hurdle: Native land access & land
claims
Economic Feasible $3-$4 at Chicago Market ‘beyond’ Chicago
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32
“Arctic” Study: Some Key Findings
Houston Energy Group
Challenges to Arctic Gas
Challenge Controllable
Ensure land access and land claims for First Nations are resolved
Yes
Pipeline Infrastructure Delays Yes
Respect for land, environment, wildlife and traditional lifestyles
Yes
Suggested Actions to meet these challenges:
1 Regional development with Arctic communities,
2 Educate and train Arctic workers,
3 Coordinated infrastructure development policy across North America
The study did not focus onlegislative solutions toaddress commercial riskto the commodity. That did not appear needed.
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33
“Arctic” Study: Some Conclusions
We agree that pipeline capacity is needed beyondAlberta, but that is notspecifically an Arcticrequirement.
LNG plants do not talk about additional pipeline investment past thereceiving terminal … theydon’t have to … its anintegrated gas market.
Houston Energy Group
North America needs new supply sources Arctic is significant, new domestic supply Feasible – Technical, Environmental,
Regulatory Key – Invest in Arctic region and its people Key – Coordination, collaboration,
compromise
North America needs new pipeline capacity
This capacity is needed to east and west coasts
Key – Access to new right-of-way to market
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Beyond the Study: New Project Matters
Houston Energy Group
New Project matters: Alternative Arctic routes are competing
against each other rather than developing a comprehensive, acceptable approach = all will lose at the current pace (except a downsized Mackenzie).
45 Tcf proven (and much more likely) makes regulated pipeline returns acceptable for that industry.
Alternatives (e.g., LNG) are bringing their costs down rapidly and could displace Arctic (as occurred before). There is more than enough gas.
$20 Billion cost (or more or less) may be required to get the gas to the Chicago Hub, but that is not the challenge of the Arctic gas … NA has an integrated gas market.
Our study didn’t cover matters that need to be addressed.
Legislative solutions ignores that other projects are proceeding without such benefit, and that there is more than enough gas around … the issue is infrastructure.
It may be best for NA to keep the Alaskan/Arctic gas up there as a deterrent to future security of supply risks … why
consume all of ours like we are with oil.
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If WCSB starts
to decline post
2012, then the
pipe to Chicago
may not be as
big.
If WCSB starts
to decline post
2012, then the
pipe to Chicago
may not be as
big.
35
Beyond the Study: To Chicago?
Clearly, a pipeline to Chicagowill miss the benefits of other gas markets when thebasis differential out of Alberta favors other locations.
Through convergence Arctic gas can become (examples):• Injected gas for tar sands• gas or power in Alberta• gas or power in West• gas or power in East• power export to US• feedstock in petrochemical
Its not just about gas price any more.
Houston Energy Group
To Chicago?: While capacity is needed to achieve the forecast growing market, that is not efficiently done within the Arctic project:
Once an Arctic project is under construction, pipeline companies will have the incentive to add takeaway capacity from AECO to markets east and west
The future decline rate of WCSB could influence additional AECO requirements, which is not known at this time
35
$/
MW
h
Time
Electricity Pool Price
Gas Price equivalent*
* including thermal efficiency
Top of Both Curves
36
Beyond the Study: Arctic versus Competition
This is a comparison between Arctic gas and any/all LNG imports.
Houston Energy Group 36
Benefits of Arctic: Security of Supply: Reduce dependence on
imported energy – increase domestic gas production
Environment: Decrease domestic emissions of carbon dioxide (through fuel substitution)
Security of Supply: Increase proportion of long-life domestic gas production
Price: Long-term price stability since investment in place
Price: Reduce commodity price volatility Macro Economic: Benefit US and Canadian
economies, including from construction, a new development corridor, and from price impacts on the economy
Oil Imports: Increases domestic liquids production
direct via NGLs indirect via Alberta Tar Sands
Hydrates: Access to methane from ice hydrates in NWT
37
Beyond the Study: Building Project Support
One Arctic approach, oneArctic project.
Houston Energy Group
New Project approach:
• Two Arctic pipelines is better than 1 (and 0).
• Deal with real Arctic issues – local requirements, etc. as identified in our study – collectively.
• Develop markets close to the supply (e.g., Tar Sands to lower oil imports) to improve overall returns and gas market impact.
• Emphasize real Arctic value – domestic production for a long time = Security of Supply that alternative don’t provide (and ships can go anywhere).
37