building support for the “arctic” project november 18, 2002 houston, texas, usa jim...

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


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


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


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


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.


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)

8

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’.


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.


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.


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

11

12

“Arctic” Study: Route Options Studied


SIX OPTIONS STUDIED

--- Proposed ANGTS--- Proposed Dempster Lateral--- Proposed Mackenzie Valley--- ‘Over the Top’--- Northern – Onshore--- TAGS (LNG)

12

13

“Arctic” Study: Gas Price Forecast


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.

13

14

“Arctic” Study: Supply and Demand


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


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).

15

16

“Arctic” Study: Gas Reserve


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.

16

17

“Arctic” Study: Commercial Advantages


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

17

18

“Arctic” Study: NAFTA Energy Balances


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

19

“Arctic” Study: Study Regions


10 Study Regions:1 – Arctic2,3 – Canada4-9 – US (EIA’s 6 regions)10 - Mexico

19

20

“Arctic” Study: 2000 Gas Balance and Flows


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.)

20

21

“Arctic” Study: 2015 Gas Balance and Flows


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)

21

22

“Arctic” Study: Change in Balance & Flows


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.

22

23

“Arctic” Study: New Infrastructure Needed


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.

23

24

“Arctic” Study: Comparing Project Economics


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

24

25

“Arctic” Study: Positive Economic Assessment


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


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.

26

27

“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.


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.


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

28

29

“Arctic” Study: Regulatory Complexity


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:

29

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


• 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.

30

31

“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.


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

31

32

“Arctic” Study: Some Key Findings


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.

32

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.


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

33

34

Beyond the Study: New Project Matters


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.

34

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.


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.


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.


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

building support for the “arctic” project november 18, 2002 houston, texas, usa jim...

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