u.s.andcanada market and portfolio option overview...gas market and portfolio option overview bruce...

Exploring the Future for Exploring the Future for p gNatural Gas Supply and Demand

For Centra Gas

p gNatural Gas Supply and Demand

For Centra Gas

U.S. and CanadaU.S. and Canada

For Centra GasFor Centra Gas

U.S. and Canada Gas Market and Portfolio Option Overview

U.S. and Canada Gas Market and Portfolio Option Overview

Bruce B HenningBruce B HenningBruce B. HenningBruce B. HenningVice PresidentVice President

ICF ICF InternationalInternational703703--218218--27392739

BH i @i fiBH i @i [email protected]@icfi.com

July 8, 2011July 8, 2011

Disclaimer

This presentation presents the views of ICF International. The presentation i l d f d l ki d j i ICF h dincludes forward‐looking statements and projections. ICF has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete However a variety of factors could cause actual market resultscomplete. However, a variety of factors could cause actual market results to differ materially from the projections, anticipated results or other expectations expressed in this presentation.

The information in this presentation is proprietary and confidential, and is provided to Centra Stakeholders only for the purpose of reviewing the Centra supply planning process. It should not be distributed to third parties pp y p g p pnot involved in this proceeding and not approved by Centra. The information in this presentation may not be repackaged or resold, or redistributed beyond the Centra Stakeholder process without the express

2© 2011 ICF International. All rights reserved. 2

written permission of ICF International.

Contents

1) INTRODUCTION

2) OVERVIEW OF NORTH AMERICAN GAS MARKET TRENDS

3) OVERVIEW OF CENTRA’S CURRENT OPERATIONS AND SUPPLY PORTFOLIO

4) REVIEW OF POTENTIAL SUPPLY OPTIONS FOR CENTRA

33© 2011 ICF International. All rights reserved.

INTRODUCTIONINTRODUCTION


The current Centra gas supply portfolio is structured around two primary factorsstructured around two primary factors

1. Centra is dependent on the TransCanada Pipeline for natural gas deliveries.– WCSB production– WCSB production

– Natural gas withdrawals from storage in Michigan

– U.S. supply from the Gulf Coast, or Mid‐Continent

2. Centra has long term agreements with ANR for natural gas storage capacity in Michiganstorage capacity in Michigan. – Contracts expire on March 31, 2013


Recent market developments have changed the planning environment

Declines in gas exports from the WCSB have driven up TransCanada rates.

T C d i li it f E t th C t it t i

the planning environment

TransCanada pipeline capacity from Empress to the Centra citygate is unconstrained, hence the value of holding long term firm capacity on TransCanada is reduced.

A il bilit f hi hl di t d b kh l it f ANR tAvailability of highly discounted backhaul capacity from ANR storage on Great Lakes Gas Transmission to Emerson and economic backhaul on TCPL from Emerson to the Centra Citygate may be declining, potentially resulting in increases in the cost of using Michigan Storageresulting in increases in the cost of using Michigan Storage.

New storage options have become available since Centra contracted for ANR storage.

Ch i k t t t bl C t t h t l t thChanges in market structure enable Centra to purchase natural gas at the Centra citygate on both a seasonal and peak day basis.


The expiration of the ANR storage contract, and associated pipeline capacity on ANR and Greatassociated pipeline capacity on ANR and Great

Lakes in 2013 provides an opportunity to reevaluate the physical and contractual basis for natural gas deliveries to the Centra citygate.

NORTH AMERICAN GAS MARKET OVERVIEW

NORTH AMERICAN GASNORTH AMERICAN GAS MARKET OVERVIEW


Natural gas markets have changed dramatically over the last fifteen years


over the last fifteen years

U.S. and Canada G P d i d D li bili B f/d

Gas deliverability is a measure Gas Production and Deliverability, Bcf/dof the productive capacity of

existing wells.

The last major “Gas Glut” ended in around 2000 when

78

80Gas Production Productive Capacity

ended in around 2000, when demand (and production) caught up with productive capacity.

Between 2000 and 2008 gas70

72

74

76

age Bc

fdBetween 2000 and 2008, gas production was very near 100% of deliverability, leading to wide swings in price needed to balance supply and demand. 62

64

66

68

Avera

Over the past two years, low prices have led producers to reduce, or “shut in” production from some wells.

60

Jan‐97

Sep‐97

May‐98

Jan‐99

Sep‐99

May‐00

Jan‐01

Sep‐01

May‐02

Jan‐03

Sep‐03

May‐04

Jan‐05

Sep‐05

May‐06

Jan‐07

Sep‐07

May‐08

Jan‐09

Sep‐09

May‐10

Jan‐11


The Recession Caused Gas Demand to DeclineNORTH AMERICAN GAS MARKET OVERVIEW

U.S. Natural Gas ConsumptionAnnual Average Billion Cubic Feet per Day

I t d f i

50

60

70Difference from Projected Demand

‐0.4 Bcfd‐0.6%

‐2.7 Bcfd‐4.5%

Instead of growing modestly, gas use declined by about 5 percent consistent with

30

40

Non‐Core

Core

percent, consistent with the decline in economic activity from 2007‐09.

l ll f h d li

10

20CoreNearly all of the decline

occurred in non‐core gas use, primarily in the industrial sector

Core demand includes the residential and commercial sectors.

0

Actual Projected Actual Projected Actual

2007 2008 2009

industrial sector.

However, demand appears to be

10

Non‐core demand includes the industrial and power generation sectors. Projected values are from ICF’s November 2007 gas market projection.

© 2011 ICF International. All rights reserved.

rebounding.

But, the Recession Has Had Less Impact on Gas Supply


on Gas Supply

Drilling activity continued to rise until late 2008 in $11

$12$13$14

1,4001,600

u)

U.S. Gas Directed Drilling Activity and Gas Prices

response to relatively high gas prices.

A significant decline in activity occurred in late 2008 $2

$3$4$5$6$7$8$9$10$

200400600800

1,0001,200

s Pr

ice

($/M

MB

t

Act

ive

Rig

s

yand early 2009 in response to the collapse in prices.

Over the past year, activity has rebounded but the focus

$0$1$2

0200

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

Gas

Rigs Drilling for Gas Henry Hub Spot Pricehas rebounded, but the focus is on horizontal wells.

In the past five years, increases in unconventional gas production have more 50

607080

U.S. and Canada Natural Gas Supplies (Average Annual Bcfd)

Onshore Unconventional Gas Production

LNG Imports

gas production have more than made up for the declines in onshore conventional and offshore production 0

10203040

Onshore Conventional Gas Production

Offshore Gulf of Mexico

11

production.


0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Shale gas has been the primary contributor to growth in unconventional gas supply


growth in unconventional gas supply

U.S. and Canadian Shale Gas Production, 2000-2010

© 2011 ICF International. All rights reserved. 12

And, Storage Levels Have Been Relatively High C d t th Fi Y A


4,000

Compared to the Five‐Year Average

U.S. Natural Gas Storage Working Gas Levels (Bcf)

3,000

3,500

1,500

2,000

2,500

1,000

1,500

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

S EIA Range, 2005‐2009 Average, 2005‐09 2010 2011 YTDSource: EIA

Strong production growth and modest demand have kept working gas levels well above the five year average throughout 2010.

Re ent in reases in demand parti larl in the po er se tor ha e red ed


Recent increases in demand, particularly in the power sector, have reduced storage injections this spring, but working gas levels remain relatively high.

Natural Gas Prices Reflect the Loose Supply/Demand B l d R l ti l Hi h W ki G L l


Balance and Relatively High Working Gas Levels

■ Prices since 2009 h d

Monthly Average Spot Price at Henry Hub have averaged about $4 per MMBtu, or

$12

$14

$16(Nom$/MMBtu)

roughly half of the average for the prior 5 years

$8

$10

$12

the prior 5 years.

$2

$4

$6

$0

Jan‐04

Jul‐0

4

Jan‐05

Jul‐0

5

Jan‐06

Jul‐0

6

Jan‐07

Jul‐0

7

Jan‐08

Jul‐0

8

Jan‐09

Jul‐0

9

Jan‐10

Jul‐1

0

Jan‐11

Monthly Price Average 2004 08 Average Jan2009 Mar2011


Monthly Price Average, 2004‐08 Average, Jan2009‐Mar2011

Source: Platts

Coal‐to‐Gas Switching for Electric Power Generation in a Low Gas Price Environment


Generation in a Low Gas Price Environment

■ The market share of natural gas versus coal in power 40%

50%

Share of Natural Gas vs Coal in Power Generation Market

gas versus coal in power generation reached 33 percent on a monthly basis in August 2007 and has Natural Gas

Coal

0%

10%

20%

30%

40%

equaled that mark twice since, in August 2009 and most recently in July and August 2010

0%

Jan‐05

May‐05

Sep‐05

Jan‐06

May‐06

Sep‐06

Jan‐07

May‐07

Sep‐07

Jan‐08

May‐08

Sep‐08

Jan‐09

May‐09

Sep‐09

Jan‐10

May‐10

Sep‐10

Relative Cost of Natural Gas for Power GenerationAugust 2010.

■ The cost of natural gas relative to coal reached a 10‐year low in the 2nd half 4

6

8

/kWh gene

rated

Gas to Co

al)

Relative Cost of Natural Gas for Power Generation

10‐year low in the 2 half of 2009; cost of gas fell to below two times the cost of coal for the first time since

0

2

an‐05

ay‐05

ep‐05

an‐06

ay‐06

ep‐06

an‐07

ay‐07

ep‐07

an‐08

ay‐08

ep‐08

an‐09

ay‐09

ep‐09

an‐10

ay‐10Ra

tio of Cost /

(Natural


1999. Ja M Se Ja M Se Ja M Se Ja M S e Ja M Se Ja M

Source: EIA

Recent changes in gas supply patterns have changed Inter regional pipeline flows


changed Inter‐regional pipeline flows



Key Assumptions in ICF’sKey Assumptions in ICF s Projection


Key Assumptions Behind ICF’s Natural Gas Market Projection


Gas Market Projection

The projections in this document were developed using the Gas Market Model (GMM©), ICF’s proprietary model of the North American natural gas market based in part on the followingproprietary model of the North American natural gas market, based in part on the following assumptions:

U.S. GDP grows at a constant rate of 2.8% per year.

Electricity demand growth decelerates over time, averaging 1.4% per year through 2035.

El t i ti d d i d i b th j ti f ti it d fi dElectric generation gas demand is driven by the projections for generating capacity and gas‐fired generation from ICF’s Integrated Planning Model (IPM©).

– ICF’s electric generation and natural gas forecasts both assume a policy limiting CO2 emissions is in effect after 2018.

– All nuclear units are assumed to have a maximum operating life of 60 years As a result about 11– All nuclear units are assumed to have a maximum operating life of 60 years. As a result, about 11 GW of retirements are projected between 2029 and 2035.

– New generating capacity is built to satisfy load growth, subject to the costs of each competing technology.

Demand side management and conservation measures continue to occur, consistent with recent trends.Demand side management and conservation measures continue to occur, consistent with recent trends.

Gas supply is developed in GMM© based on the amount of resource available and the E&P finding and development costs associated with the different types of gas resources.

In the near term, pipeline and storage capacity additions are built based on announced. In the longer term, projects are added based on economic merit.


The North American Natural Gas Resource Base Could S t C t L l f G U f b t 150 Y


Support Current Levels of Gas Use for about 150 Years

Unproved

In total, the U.S. and Canada have almost 4 000 T f f th t

U.S. and Canada Natural Gas Resource Base(Tcf of Economically Recoverable Resource, Assuming Current E&P Technologies)

ProvenReserves

UnprovedPlus

DiscoveredUndeveloped

TotalRemainingResource

ShaleResource1

Alaska 7.7 153.6 161.3 0.0West Coast Onshore 2.3 24.6 27.0 0.3R ki & G t B i 66 7 388 3 454 9 37 9

4,000 Tcf of resource that can be economically recovered using current exploration and

Rockies & Great Basin 66.7 388.3 454.9 37.9West Texas 27.6 47.7 75.3 17.5Gulf Coast Onshore 70.1 684.7 754.8 476.9Mid‐continent 37.0 205.0 241.9 133.9Eastern Interior 2,3 18.6 1053.7 1072.3 986.1Gulf of Mexico 14.0 238.6 252.5 0.0

production (E&P) technologies.– At current levels of

consumption, this is U.S. Atlantic Offshore 0.0 32.8 32.8 0.0U.S. Pacific Offshore 0.8 31.7 32.5 0.0WCSB 60.4 664.0 724.4 508.8Arctic Canada 0.4 45.0 45.4 0.0Eastern Canada Onshore 0.4 15.9 16.3 10.3Eastern Canada Offshore 0 5 71 8 72 3 0 0

enough resource for about 150 years.

– As technologies improve and new discoveries are

Eastern Canada Offshore 0.5 71.8 72.3 0.0Western British Columbia 0.0 10.9 10.9 0.0US Total 244.7 2,860.6 3,105.3 1,652.5Canada Total 61.3 807.6 868.8 519.1US and Canada Total 306.0 3,668.1 3,974.1 2,171.6

made, the total gas resource is likely to grow.

Over 50% of the assumed resource is shale gas. 1. Shale Resource is a subset of Total Remaining Resourceg g

2. Eastern Interior includes Marcellus, Huron, Utica, and Antrim shale.3. Reference case assumes drilling levels are constant at today’s level over time, reflecting restricted access to the full resource development.


North American Gas Supply CurvesNORTH AMERICAN GAS MARKET OVERVIEW

The existing North America resource base includes about 1 500 Tcf 14

Total U.S. and Canadaincludes about 1,500 Tcf of gas that is economically recoverable at $5 per 10

11121314

pmen

t Co

stu)

MMBtu.– Shale gas accounts for

over half of the gas economically 5

6789

ead Develop

010$/M

MBtu

yrecoverable at $5 per MMBtu.

Total cost of developing new resource includes

12345

Total W

ellhe

(20

new resource includes exploration, development and O&M costs (both fixed and

0

0 500 1000 1500 2000 2500 3000 3500

T

Dry Gas Resource (Tcf)

CBM Ti ht C ti l Sh l T t lvariable cost).


CBM Tight Conventional Shale Total


ICF’s Gas Market Outlook


Near‐term Gas Demand Will Rebound, Assuming Positive Economic Activity


Assuming Positive Economic Activity

U.S. and Canadian Gas Demand

30

35

U S a d Ca ad a Gas e a d(Tcf per Year)

20

25

30

Power

Non‐Power

5

10

15

0

5

2007 2008 2009 2010 2011 2012 2013


Gas Prices are Likely to Remain Relatively Low over the Next Three Years


over the Next Three Years

Projected Natural Gas Prices Versus NYMEXNominal Dollars per MMBtu

■ Gas prices over the next 3 years are projected to p

12

14Historical Henry Hub Price

ICF Forecast Henry Hub Price

average around $5 per MMBtu.

■ On average our projection is similar to the trend in futures

8

10NYMEX Henry Hub gas futures contract, Apr 29

similar to the trend in futures prices, although we project more seasonal variability.

■ Shoulder‐month prices find

2

4

6a floor around $4 per MMBtu, while winter prices reach $6 per MMBtu.

ll f ’0

Jan‐06

Jul‐0

6

Jan‐07

Jul‐0

7

Jan‐08

Jul‐0

8

Jan‐09

Jul‐0

9

Jan‐10

Jul‐1

0

Jan‐11

Jul‐1

1

Jan‐12

Jul‐1

2

Jan‐13

Jul‐1

3

Jan‐14

■ All of ICF’s projections assume normal (30‐year average) weather.


Historic and futures contract prices from Platts

In the Longer Term, Growth in Gas Consumption Will Continue to be Driven by Growth in Gas Use for Electric


Continue to be Driven by Growth in Gas Use for Electric Generation

120

U.S. and Canadian Gas Consumption (Average Annual Bcfd)Total gas consumption is projected to increase at a

100

120projected to increase at a rate of 1.6% per year

– By 2035, total gas consumption in the U.S. and C d i j d Power

Generation60

80Canada is projected to approach an average of 110 Bcf per day.

About 75% of the

Residential

Commercial

Industrial

20

40incremental demand growth is in the power sector.

Power sector gas

Other*

Residential

0

20

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035

*

– Power sector gas consumption is projected to more than double by 2035.

In aggregate, very little


* Other includes lease, plant, and pipeline fuel gas use.demand growth occurs in the other sectors.

Gas‐fired Generation Grows from 23% to 37% of Total Generation by 2035


of Total Generation by 2035

The U.S. has about 460 GW of gas‐fired generating

U.S. Electricity Generation (TWh per Year)g g g

capacity, much of it new combined cycle units added in the past 15 years.

Current utilization rates for fi d l t

5,000

6,000

gas‐fired plants are relatively low, so existing plants can provide much of the incremental growth in gas‐fired generation.

Gas

3,000

4,000

Gas is an important fuel for carbon policy.– Generation from existing coal

plants is likely to decline.

R bl ti i

All Other Fuels

1 000

2,000

– Renewable generation is expected to grow at a rapid pace, but from a relatively small base.

– Nuclear generation may decline if plants are forced to retire as th h 60 f

0

1,000

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035


they reach 60 years of operation.

2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2

Demand for Natural Gas Grows Across the U.S. and Canada


and Canada

U.S. and Canada Regional Natural Gas Consumption (Average Annual Bcfd)

25

Most of the regional growth in gas demand is d t i d

25Western

25

1.2 1.3 1.4 1.50

5

10

15

20

25

Alaskadue to increased gas use for electric generation.The largest increases occur in the Gulf Coast d Mid ti t d

6.2 7.4 8.9 10.4

0

5

10

15

20WesternCanada

Central /

3.6 4.5 5.1 5.8

0

5

10

15

20 EasternCanada

15

20

25

West

0

2009 2015 2025 2035and Mid‐continent and the Southeast.

– Together, gas consumption in these regions increases by

2009 2015 2025 2035

14.0 15.517.9 19.8

510152025

Midwest 2009 2015 2025 2035

11 0 12.715.210

15

20

25

Northeast

12.3 12.5 13.6 13.7

0

5

10

2009 2015 2025 2035

25

regions increases by over 16 Bcfd through 2035.

Demand growth in Western Canada is

26 1 27 52530

Gulf Coast / Mid‐continent

0

2009 2015 2025 2035

9.111.0 12.7

0

5

2009 2015 2025 2035

6.8 8.712.6

14.9

0

5

10

15

20

2009 2015 2025 2035

Southeastprimarily driven by increased gas use for oil sands development.

– Oil sands gas use is d i b

18.922.1

26.1 27.5

05

101520


Source: ICF International

2009 2015 2025 2035expected to increase by 3 to 4 Bcfd by 2035.

2009 2015 2025 2035

Future Supply Growth Continues to Depend on Unconventional Gas Supplies


on Unconventional Gas Supplies

Onshore U.S. and Canadian Natural Gas Supplies (Average Annual Bcfd)

conventional and offshore gas production continues to decline, while

100

120LNG Imports

to decline, while unconventional production grows robustly.

60

80

Onshore Unconventional Gas Production

Unconventional production comprises two‐thirds of the total supply by 2035 20

40

Onshore Conventionaltotal supply by 2035.

0

20

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035

Offshore Conventional (primarily Gulf of Mexico)

Gas Production


Shale Gas is the Largest Source of Growth in Unconventional Gas Supplies


Unconventional Gas Supplies

Unconventional U.S. and Canadian Unconventional Gas Production (Average Annual Bcfd)

gas production increases by over 40 Bcfd between 2010 and 2035. 60

70

80

Over 90% of the increase in unconventional 40

50

gas production is due to increases in shale gas.

10

20

30

Shale Gas

0

10

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035


Shale Gas is a “Game Changer” for North American Gas Markets Providing Most of the Supply Growth


U.S. and Canadian Shale Gas Production (Average Annual Bcfd)

Gas Markets, Providing Most of the Supply Growth Over the Next 25 YearsThe shale gas plays are among the fastest growing production areas worldwide

50

60areas worldwide.

Total U.S. and Canada shale gas production is expected to increase from about 12.6 Bcfd in 2010 to 52 Bcfd by 2035.

30

40Barnett has been under development for 10 years, while development of Eagle Ford began in 2009.

Fayetteville

Haynesville /1

Marcellus

10

20The strength of the shale plays was evident during the recession, when development continued despite relatively low natural gas prices.

Woodford/ Anadarko

Barnetty

0

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

However, concerns over water use and disposal of fracturing fluids could limit the pace of future development.

*Haynesville values shown here include production from other shales in the vicinity, e.g., the Bossier Shale.


Supply Growth is Concentrated in Areas with Growing Shale Production


with Growing Shale Production

Canada Total

U.S. and Canada Regional Natural Gas Production (Average Annual Bcfd)

10

Areas with the greatest growth in production are the Gulf Coast and Mid‐

ti t d th E t

7 910.3

15East Coast

17.0 17.4 18.9 19.9

0510152025

2009 2015 2025 2035

1.1 1.2 1.4 1.5

0

5

10

2009 2015 2025 2035

Alaskacontinent and the East Coast.

– These areas have high concentrations of shale gas resource.

2025

West

2 5 3.04.7

6.2

5

10

Central / Midwest

1.44.6

7.9

0

5

10

2009 2015 2025 2035

Central/Midwest production increases due to growth of Marcellus (in West Virginia) an d Utica (in eastern Ohio).

Canadian production will 45

50

Gulf Coast / Mid‐continent

15.1 16.318.9 20.6

05

1015

2009 2015 2025 2035

2.5

0

2009 2015 2025 2035

prebound as conventional production in Alberta declines, but shale gas production in British Columbia increases. 29.4

36.0

42.745.6

20

25

30

35

40

45

l7.1 4.9 5.6 6.4

5

10

15Gulf of Mexico

Gulf of Mexico production continues a near term decline, but long run increases in Deep Water plays should offset declines in Shallow Water production.

0

5

10

15

2009 2015 2025 2035


Source: ICF International 0

2009 2015 2025 2035

p

By 2035, LNG Imports Account for only 2% of U.S. and C di N t l G S li


Canadian Natural Gas Supplies

North American LNG Imports (Average Annual Bcfd)U.S. and Canadian LNG imports are expected to

4

5grow from about 1.3 Bcfd in 2010 to 2.8 Bcfd by 2035.

– LNG imports to Mexico l i

3

Mexico

also increase.

Competition from European and Asian natural gas consumers, plus relatively low

1

2

U.S. Gulf Coast

Canadaplus relatively low domestic gas prices limit North American LNG imports.

On average North

0

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

U.S. East Coast– On average, North American LNG import terminals are expected to operate at only about 10% to 15% of their rated receipt capacity.


Source: ICF Internationalp p y

Changes in Supply and Demand Will Significantly Change Pipeline Flow Over the


Significantly Change Pipeline Flow Over the Next 10 Years

Increases in flows from th G lf C t t th tthe Gulf Coast to the east are due to increases in Mid‐continent shale gas production.

REX Pipeline enables pincreasing flow from the Rocky Mountains eastward.

Marcellus gas production th di lgrowth displaces gas

flows into the Northeast U.S. (Shifts within the Northeast are not depicted on this interregional flow map).

Declining conventional production in Alberta andproduction in Alberta and increasing gas consumption for oil sands development causes flows from Western Canada to d li



decline.

Changes in Supply and Demand Will Continue to Change Pipeline Flow In the Longer Term


to Change Pipeline Flow In the Longer Term

Substantial increases in flows continue to occurflows continue to occur out of the Mid‐continent shales and the Rocky Mountain producing basins.

Marcellus gas production growth continues to displace gas flows into the Northeast U.S. (Shifts within the Northeast are not depicted on this interregional flow map).

Flows on TCPL to eastern markets recover slightly, but remain down in thebut remain down in the longer term.



Henry Hub Gas Prices Will Average Between $5 and $7 per MMBtu


$5 and $7 per MMBtu

Average Annual Natural Gas Price at Henry Hub Henry Hub natural gas prices are projected

9

10

11(2010$/MMBtu)

p p jto average between $5 and $7 per MMBtu.

R b t th i

6

7

8

9Robust growth in gas demand applies upward pressure on gas prices over time.

2

3

4

5$5 to $7 gas prices are sufficient to support the levels of supply development in the

0

1

2

2001

2003

2005

2007

2009

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

2031

2033

2035

development in the projection, but not so high as to discourage market growth.


2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2

Sources: Platts (historic), ICF (projection)


ConclusionsConclusions


Gas Markets will Likely Grow Robustly as Unconventional Gas Supplies Continue to Grow


Total gas consumption will grow at an average of 1.6 percent per year over the next 25 years driven almost entirely by growth in gas fired power

Unconventional Gas Supplies Continue to Grow

the next 25 years, driven almost entirely by growth in gas‐fired power generation.

– Increased efficiency, conservation, and GHG regulations are uncertainties that will have an impact on future growth in gas use.

Production of shale gas reserves, where a significant portion of remaining gas resources are located, should contribute to a robust increase in North American supplies.

– Concerns over water use and disposal of fracturing fluids could adversely impact the pace of shale gas development.

– Exploration and production in the Deep Water Gulf of Mexico also may be limited due to environmental concernsenvironmental concerns.

Regional shifts in gas supply and demand will drive future gas infrastructure needs.

– Construction of new pipeline capacity is likely to continue at a rapid pace over the next

37

Construction of new pipeline capacity is likely to continue at a rapid pace over the next 5 to 10 years.


Natural Gas Prices are Likely to Average Between $5 and $7 per MMBtu


Projected Henry Hub gas prices are likely to average between $ $

Between $5 and $7 per MMBtu

$5 and $7 per MMBtu through 2035.

– Prices will be high enough to support the robust supply development projected over time, but not so high as to adversely impact market growth.p j g y p g

Significant short‐term gas price volatility is likely to continue.

– Abnormal weather events and rapid shifts in economic activity can significantly change gas prices over relatively short periods of time.

– But, market forces will tend to push gas prices back into the $5 to $7 per MMBtu price range.


Forecast Uncertainty

Economic GrowthE i t l P li 14 000

Alternative Marcellus Shale Production ScenariosEnvironmental PolicyNatural gas resources and production technologies

M ll Sh l 10,000

12,000

14,000

– Marcellus Shale– Uinta and other

eastern shales– Western Canadian

shales 6,000

8,000

0,000M

cfd)

shalesArctic Gas SupplyLNG Imports and ExportsAlberta demand 2,000

4,000

(MM

Alberta demand– Tar sands and

potential GTLStorage developmentTransCanada tolls

-2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035

"Low" Marcellus Production "High" Marcellus Production ICF Base CaseTransCanada tolls

Alternative Market Scenarios Considered

Tight Gas Market Scenario:– Slower growth in North American

Pessimistic Mainline Market Drivers Scenario:

Shale Gas Production

– Faster economic recovery and natural gas demand growth than

t d i th ICF B C

Drivers Scenario: – High growth in Marcellus Shale

Production

– High Alberta Demand Growthrepresented in the ICF Base Case.

Optimistic Mainline Market Drivers Scenario:

l h ll h l

High Alberta Demand Growth

– Continuing decline in WCSB Production and Exports

– BC Shale Gas exported as LNG– Slow growth in Marcellus Shale

Production

– Low Alberta Demand Growth

High growth in WCSB Production

p

TransCanada Tolls Scenarios– Eastern Zone toll bracketed at

$1.00, $1.50, $2.00, $3.00– High growth in WCSB Production and Exports

– No incremental LNG Exports from North America (E.g., no

$1.00, $1.50, $2.00, $3.00

– For each market scenario

from North America (E.g., no Kitimat)


TransCanada Mainline FT Contract Demand and Receipts at Empressand Receipts at Empress

7

5

6

Day

3

4

Cub

ic F

eet p

er

1

2Bill

ion

C

0

Jan-

05

Jun-

05

Nov

-05

Apr

-06

Sep

-06

Feb-

07

Jul-0

7

Dec

-07

May

-08

Oct

-08

Mar

-09

Aug

-09

Jan-

10

Jun-

10

Nov

-10

Receipts at Empress Contract Demand From Empress


???

J J N A S F D M O M A J J N

TransCanada Mainline FT Tolls (100% Load Factor Excluding Fuel)Factor, Excluding Fuel)


???

Impact of TCPL Rate Structure on Basis

Range in AECO to Chicago Basis 2015

Range in AECO to Dawn Basis 2015

Range in AECO to Henry Hub Basis 2015

0 400.60 0.80 1.00 1.20 1.40 1.60

asis ($/MMBtu)

0 50

1.00

1.50

2.00

2.50

asis ($/MMBtu)

0 400.60 0.80 1.00 1.20 1.40 1.60

asis ($/MMBtu)

‐0.20 0.40

$1.00 TCPL Tariff

$1.50 TCPL Tariff

$2.00 TCPL Tariff

$3.00 TCPL Tariff

Ba

‐

0.50

$1.00 TCPL Tariff

$1.50 TCPL Tariff

$2.00 TCPL Tariff

$3.00 TCPL Tariff

Ba

‐0.20 0.40

$1.00 TCPL Tariff

$1.50 TCPL Tariff

$2.00 TCPL Tariff

$3.00 TCPL Tariff

Ba

1.20 1.40 1.60

Btu)

Range in AECO to Chicago Basis 2020

2 00

2.50

3.00

MBtu)

Range in AECO to Dawn Basis 2020

1.20 1.40 1.60

Btu)

Range in AECO to Henry Hub Basis 2020

‐0.20 0.40 0.60 0.80 1.00

$1.00 $1.50 $2.00 $3.00

Basis ($/M

M

‐

0.50

1.00

1.50

2.00

$1.00 $1.50 $2.00 $3.00

Basis ($/M

M

‐0.20 0.40 0.60 0.80 1.00

$1.00 $1.50 $2.00 $3.00

Basis ($/M

M


TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

TCPL Tariff

OVERVIEW OF CENTRA’SOVERVIEW OF CENTRA S CURRENT OPERATIONS


Centra Natural Gas CustomersOVERVIEW OF CENTRA’S CURRENT OPERATIONS

300,000 Commercial/IndustrialResidential

200 000

250,000

150,000

200,000

100,000

‐

50,000


V:\sloan\Centra Manitoba\2010 Nov Files\CM_OperStats_Fig20&21.xls

2002 2003 2004 2005 2006 2007 2008 2009 2010

Centra Natural Gas Deliveries 2002‐2010OVERVIEW OF CENTRA’S CURRENT OPERATIONS

90

100

70

80

90

Transportation Service Customer

50

60

per Year)

Service Customer Deliveries

C i l/

20

30

40 (PJ's Commercial/

Industrial Sales

‐

10

20

Residential Sales


V:\sloan\Centra Manitoba\2010 Nov Files\CM_OperStats_Fig20&21.xls

2002 2003 2004 2005 2006 2007 2008 2009 2010

ICF Forecast of Manitoba Natural Gas Demand to 2020

OVERVIEW OF CENTRA’S CURRENT OPERATIONS

to 2020


V:\sloan\Centra Manitoba\2010 Nov Files\???

ICF Forecast of Alberta & Saskatchewan Natural Gas Demand to 2020


Natural Gas Demand to 2020

1 800

2,000

1,400

1,600

1,800

Pipeline Fuel

1,000

1,200

PJ's per Year)

FORECAST

400

600

800 (P

Industrial/Power Generation

FORECAST

‐

200 Commercial

Residential


V:\sloan\Centra Manitoba\2010 Nov Files\DemandCharts-GMM1010_Fig5&25.xlsx

Monthly Normal Traditional Heating Degree Days


Days

1,800

2,000

ManitobaS k h

1,400

1,600

1,800

Fahren

heit)

SaskatchewanQuebecAlbertaWest North CentralEast North Central

1,000

1,200

e 65

Degrees F New Enlgand

OntarioMid‐AtlanticBritish Columbia

400

600

800

HDD (B

ase

0

200

400


V:\sloan\Centra Manitoba\2010 Nov Files\ DegreeDayCharts_Fig23 & Table1.xls

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2010/11 Centra DemandOVERVIEW OF CENTRA’S CURRENT OPERATIONS

Centra Daily Sales Requirement by Month

400

500

Maximum

300

(TJ/Day)

Average

Minimum

100

200

0

100

Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct


V:\sloan\Centra Manitoba\2010 Nov Files\ Centra Daily Min Avg Max by month Figure_24.xlsx

p y g p

Annual and Daily Weather VolatilityOVERVIEW OF CENTRA’S CURRENT OPERATIONS

V:\sloan\Centra Manitoba\2010 Nov Files\ DegreeDayCharts_Fig23 & Table1.xls

Comparison of Manitoba Weather to Other RegionsServed by WCSB Gas Production

(Annual Heating Degree Days)Normal Weather

Warmest Year

Coldest Year

Absolute Range

Relative Range

%Manitoba 10,378 9,332 12,301 2,969 29%Alberta 9,423 8,568 11,146 2,578 27%Saskatchewan 10,003 9,633 12,370 2,737 27%British Columbia 5,339 4,846 5,724 878 16%Ontario 6,582 6,087 7,742 1,655 25%Q b 8 338 6 824 8 803 1 979 24%Quebec 8,338 6,824 8,803 1,979 24%

New England 6,611 5,742 6,967 1,225 19%Mid-Atlantic 5,911 4,923 6,276 1,353 23%East North Central 6,497 5,317 7,004 1,687 26%W t N th C t l 6 750 5 725 7 431 1 706 25%

Standard Deviation of Daily Changes in Temperature (Degrees Celsius) Summer

(April - Oct) Winter (Nov

- Mar) Average Manitoba (Winnipeg) 3.12 4.96 4.13

West North Central 6,750 5,725 7,431 1,706 25%

( p g)Alberta (Calgary) 3.03 4.81 4.01 Saskatchewan (Saskatoon) 3.04 4.67 3.93 Ontario (Toronto) 2.00 3.49 2.83 Quebec (Montreal) 2.70 4.50 3.69 U.S. North East Central (Chicago) 2.93 4.08 3.54


V:\sloan\Centra Manitoba\2010 Nov Files\Daily Temperature Data Table2.xlsx

( g )Rocky Mountains (Denver) 3.58 4.43 4.02 New England (Boston) 2.90 3.81 3.38

Design Firm Peak Day Requirements(As of November 1 2010)


(As of November 1, 2010)

GJ/day %

System Supply 116,406 24.2%Direct Purchase (WTS) 20,794 4.3%Total Under FS Transportation 137,200 28.5%

Oklahoma Supply 7,860 1.6%Storage Withdrawal 208,591 43.3%Delivered Service 63,269 13.1%Peaking Delivered Service 64,380 13.4%

481 300 100 00481,300 100.00


Existing Centra Pipeline and Storage Arrangements


ArrangementsServices Type of

Service Annual Summer Winter Expiration

TCPL (GJ/d)Empress to Saskatchewan FS 2 200 10-31-2011Empress to Saskatchewan FS 2,200 10-31-2011Empress to Manitoba FS 135,000 10-31-2011

Manitoba to Emerson STS 54,0003-31-2012Emerson to Manitoba STS 215,614*

Delivered Service FS 20 000 63 269Delivered Service FS 20,000 63,269

Great Lakes (GJ/d)Emerson to Crystal Falls FT 53,351

3-31-2013Deward to Emerson FT 237,388*

ANR (GJ/d)Crystal Falls to ANR Storage FTS 52,448

3-31-2013ANR Storage to Deward FTS 208,591Oklahoma to ANR Storage/Crystal Falls FTS 7,860Louisiana to ANR Storage FTS 22,380

ANR StorageStorage annual capacity (GJ) FSS 15,509,323

3-31-2013Withdrawal (GJ/d) FSS 208,591I j ti (GJ/d) FSS 88 625Injection (GJ/d) FSS 88,625


* Backhaul

Location of Centra Pipeline and Storage AssetsOVERVIEW OF CENTRA’S CURRENT OPERATIONS

TransCanadaTransCanadaTransCanadaTransCanada

Centra Manitoba Service TerritoryCentra Manitoba Service TerritoryCentra Manitoba Service Territory

ANR Storage

Great Lakes Gas Transmission

ANR Storage


ANR StorageANR Storage


gggg

ANR SouthwestANR S th t





???

ANR SoutheastANR SoutheastANR SoutheastANR Southeast

Centra Pipeline and Storage Assets – Summer Operations (Apr 1 2011 Oct 31 2011)


Operations (Apr. 1, 2011 – Oct. 31, 2011)


???

Centra Pipeline and Storage Assets – Winter Operations (Nov 1 2010 Mar 31 2011)


Operations (Nov. 1, 2010 – Mar. 31, 2011)


???

REVIEW OF POTENTIALREVIEW OF POTENTIALSUPPLY OPTIONS FOR CENTRA


Key Supply Portfolio Planning Issues

Where should Centra purchase natural gas?

How much storage capacity should be used?– And where?

How much pipeline capacity should be retained?How much pipeline capacity should be retained?– On which pipelines?

– For which services?

How does Centra minimize risk associated with TransCanada rates and rate structure?

58

Alternative Sources of Natural Gas CommodityPOTENTIAL SUPPLY OPTIONS FOR CENTRA

• WCSB supply transported on the TransCanada system from AECO or Empress c rrentl constit tes the primar so rce of gas commoditEmpress currently constitutes the primary source of gas commodity for Centra.

• Alternative sources of Canadian supply include:• WCSB production in Saskatchewan from existing and potential new

sources

• Associated natural gas production in Manitoba

• Shale gas production in Manitoba

• Potential sources of U.S. supply include:U S Rocky Mountains• U.S. Rocky Mountains

• Mid‐Continent and Gulf Coast gas

• Purchases at MichCon, Chicago, Dawn and other smaller market


centers

Pipeline Transportation Options for WCSB GasPOTENTIAL SUPPLY OPTIONS FOR CENTRA

• The TCPL Mainline is currently the only pipeline from the WCSB production region to serve ManitobaWCSB production region to serve Manitoba.

• Alternatives to TCPL Mainline would require new construction. • Alliance Pipeline:

• A TCPL interconnect near Regina

• new—build extension to serve Brandon and/or Winnipeg areasnew build extension to serve Brandon and/or Winnipeg areas

• A TCPL interconnect in Manitoba into existing Centra meter stations

• Direct delivery of Saskatchewan WCSB gas on TransGas• Direct delivery of Saskatchewan WCSB gas on TransGas.


Shale Plays in Western CanadaPOTENTIAL SUPPLY OPTIONS FOR CENTRA


POTENTIAL SUPPLY OPTIONS FOR CENTRA

Alternative Sources of Natural Gas Commodity

• U.S. Rocky Mountain Gas• Currently delivered to the U.S. West Coast and the U.S. Midwest.

• Continuing growth in supply expected from Rocky Mountain shale plays.

• U.S. Gulf Coast and Mid‐Continent• Reliable so rce of nat ral gas ith contin ing gro th coming from• Reliable source of natural gas, with continuing growth coming from

the Barnett, Eagle Ford, and other shale basins.

• Centra currently sources some Gulf Coast and Mid‐Continent gas to fill its ANR storagefill its ANR storage.


Alternative Sources of Natural Gas CommodityPOTENTIAL SUPPLY OPTIONS FOR CENTRA

• Direct purchases at MichCon, ANR, Dawn storage or other i d kstorage sites and market centers.

• Chicago, Dawn, and MichCon all offer sufficient liquidity to ensure reliable supply.

• Purchases delivered to the right point can reduce or eliminateneed to pay for pipeline capacity for storage injection, and reduce the cost of using storagereduce the cost of using storage.• Likely available at Dawn, MichCon, and ANR storage locations.


Natural Gas Storage

Centra holds 15.5 BCF of storage capacity with

Seasonal Arbitrage Value of Natural Gas StorageANR Storage that is scheduled to expire on March 31, 2013. 1.50

2.50

Seasonal Arbitrage Value of Natural Gas Storage

Renegotiation or replacement of the ANR storage contracts and

i d i (1 50)

(0.50)

0.50

ential (C

$/GJ))

AECOassociated transportation contracts represents a key decision point in Centra’s future supply

(3.50)

(2.50)

(1.50)

Winter P

rice Differe

Henry HubChicagoNYMEX Strip

Centra s future supply strategy.

Timing of renegotiation appears fortuitous

(5.50)

(4.50)

(Sum

mer ‐

FORECAST

appears fortuitous.


Natural gas storage fills a number of critical roles for Centra


roles for Centra

1) Minimizes costs on the TCPL for additional winter capacity

5) Provides daily gas supply flexibility to balance nominated supply toadditional winter capacity.

2) Improves Centra’s purchase and transportation load factors for WCSB supply

to balance nominated supply to weather‐driven demand fluctuations.

6) Allows Centra to minimize openWCSB supply.

3) Allows Centra to utilize normal seasonal differences in commodity prices to minimize

6) Allows Centra to minimize open market purchases and reliance on swing services.

7) Provides increased security ofcommodity prices to minimize and hedge annual gas purchase costs.

4) Mitigates rate volatility by

7) Provides increased security of supply during periods of limited supply liquidity or during times when markets are closed.4) Mitigates rate volatility by

allowing storage withdrawals at single unit cost.

when markets are closed.

8) Facilitates supply diversity (depending on location) by providing access to gas suppliesproviding access to gas supplies from remote markets.


Centra has a number of potential storage options in dditi t l f ANR Mi hi St


addition to renewal of ANR Michigan Storage

1) Saskatchewan storage 5) Other storage options• Existing• New

2) Manitoba storage

• Alberta Storage• Williston Basin

Interstate Pipeline) gdevelopment

3) Michigan storage

Interstate Pipeline storage

• Northern Natural Gas Pipeline storage• ANR

• Bluewater• MichCon/DTE

Pipeline storage• Virtual storage• No storage

MichCon/DTE

4) Ontario storage


Natural Gas Peaking OptionsPOTENTIAL SUPPLY OPTIONS FOR CENTRA

• Delivered Service• Changes in market structure have allowed marketers to provide

reliable, cost effective delivered services.

• Reduces the need for FT pipeline capacityReduces the need for FT pipeline capacity.

• Liquefied Natural Gas Peaking Plant• Costs appear much higher than alternative sources of supply

• TCPL Pipeline Capacity Conversion to High Deliverability Storage


SUPPLY PORTFOLIOSUPPLY PORTFOLIO OPTIMIZATION ANALYSIS


Analytical ToolsAPPROACH TO SUPPLY PORTFOLIO OPTIMIZATION ANALYSIS

• ICF’s Gas Market Model (GMM®)• Full supply/demand equilibrium model of the North

American gas market

S l f thl t l i t 120 k t• Solves for monthly natural gas prices at over 120 market centers throughout North America

• ICF’s Gas Storage Valuation Model (GSVM)ICF s Gas Storage Valuation Model (GSVM)• Uses monthly gas prices projected by the GMM and

statistical characterization of daily prices, in addition to variable cost assumptions for storage to create an optimal pattern of utilization for storage capacity


Factors Considered in AnalysisAPPROACH TO SUPPLY PORTFOLIO OPTIMIZATION ANALYSIS

• Quantitative Factors• Weather Volatility

• Sendout Volatility

• Natural Gas Price Volatility

• Other CriteriaDi i d Li idi f diff f li i• Diversity and Liquidity of different portfolio options


u.s.andcanada market and portfolio option overview...gas market and portfolio option overview bruce...

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