2013 Customer Meeting Presentation

8/12/2019 2013 Customer Meeting Presentation

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Vector ipelineTM

Customer MeetingOctober 16, 2013


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OverviewVector ipeline

TM

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Welcome John Donaldson

Vector Update Amy Bruhn & Matt Malinowski

Enbridge Update Ron Brintnell

DTE Update Pete Cianci

Natural Gas Market Dynamics Sesha Narayan

Discussion


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Amy BruhnManager, Transportation Services


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Vector ipelineTM Commercial Products

Firm Services FT-1 Firm Transportation FT-H Hourly Firm Transportation FT-L Limited Firm Transportation

Interruptible Services IT-1 Interruptible Transportation

PALS-1 Park and Loan Service TTS Title Transfer Service MBA Management of Balancing Agreement

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Competitive Rates to Dawn Commodity Basis to Henry Hub

AECO Chicago Dawn

-$0.42 +$0.02 US $/Dth

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Vector ipelineTM

Based on Vectors analysis of TCPL 2013-2017 Approved Tolls effective July 1, 2013

Based on Henry Hub Prices from 09/27/2013, one year starting November 2013 with a 1.0 US/CDN conversion Includes fuel based on one year average

VECTOR HH + $0.37

TCPL

TCPL / GREAT LAKES HH + $0.95

HH + $1.36 -$0.99

-$0.58

Emerson


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Vector ipelineTM

Vector ipelineTM Abandonment Cost Recovery

The National Energy Board (NEB) issued its Reasons for Decision (RH-2-2008) for the Land Matters Consultation Initiative (LMCI) Stream 3 in May2009, whereby it required regulated Group 1 and Group 2 pipelines to filefor future abandonment cost recovery mechanisms.

Vectors physical abandonment plan was filed with the NEB, reflectingestimated future abandonment costs of $4.8 million ($CAN).

Vectors proposed abandonment cost collection and set asidemechanisms was filed with the NEB on May 31, 2013.

Future abandonment costs are to be collected from shippers commencingno later than January 1, 2015 over a period of 40 years and placed into a

trust for safekeeping.

The abandonment surcharge is proposed to be CAN $0.0004 per GJ, butis still illustrative. It is proposed to be charged similar to the ACAsurcharge.

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Vector ipelineTM


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Vector ipelineTM

Vector ipelineTM Current Home Page


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Vector ipelineTM New Home Page


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Vector ipelineTM Familiar Navigation


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Vector ipelineTM

Vector ipelineTM Web Site Redesign

Easy access to key information on thehome page

Retaining menu bar so its easy to findwhat you usually look for

Design is still in progress, so wewelcome your input


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Vector ipelineTM

Matt MalinowskiManager, Market Development


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Vector Update(continued)

Operations

2013 ILI ProgramNew Facilities

Open Season Available CapacityExpansion Capabilities

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Operations

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Vector ipelineTM

Vector ipelineTMContinued Engine Replacements

Spring 2013 Washington StationTwo Engines


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Vector ipelineTM 2014 Engine Changeouts

Springville Unit #2 Spring 2014

This was originally planned for 2013 butpostponed due to extended run life

Athens Spring 2014

Springville Unit #1 Fall 2014


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Vector ipelineTM

Vector ipelineTM 2014 Maintenance

Highland Compressor replace withnew assembly - TBD

Springville Unit #1 replace entirecontrol system - Fall 2014 (2-3 weeks)

Older equipment no longer OEM supported Eventually impacts all Springville and

Highland engines


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Vector ipelineTM

Vector ipelineTM 2014 Maintenance

Additional electronic upgradesthroughout the system due to older

equipment being obsolete Exhaust stack repair at Washington

Station

Pipeline Integrity Inspection Digs


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2014 Outagesector ipeline TMVector ipeline TM

Goal is for no impact to Firm Servicedue to planned maintenance


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2013 ILI Program

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ILI Program

Required every seven years Requires several tool runs

Three discrete segments Three different tool types

Gauge plate tool failed along the Joliet toHighland segment and required removal

All ILI tool runs completed by July 20 No immediate concerns detected

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Gauge Plate Toolector ipeline TMVector ipeline TM

Tool weight3300 lbs(1500 kg)


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New Facilities

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Sheridan

New receipt point for up to 4.5 MMcf/dof Michigan production gas from a localproducer (West Bay Exploration)

DTE Gas Gathering handles smalllateral and metering This was flare gas from an oil play

In-Service May 16, 2013

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Sheridanector ipeline TMVector ipeline TM


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Gas-Fired Generation

Proposed Powerplants

Ontario 300 MW near Lambton Midwest 600 to 1200 MW along

Vector in Indiana

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Available Capacity

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Capacityector ipeline TMVector ipeline TM

Currently holding Open Season forlong-haul capacity

116,885 Dth/d available Nov. 1, 2013 Seeking five-year term Rate of $0.20 per Dth Open Season closes Monday Oct. 21


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Capacity Valueector ipeline TMVector ipeline TM

Cash is King!


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Future Expansion

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Vector ipelineTM


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MICHIGAN

Chicago

Detroit

Lake Michigan

Lake Erie

Lake Huron

ILLINOIS INDIANA

ONTARIOWISCONSIN

Dawn (Union)

VectorExpans ion Capabil i t ies

ector ipelineTM

Vector ipelineTM

Joliet

Long Haul 105 MDth/d Incremental Capacity

2 New Compressor Units Lease Line Loop

Washington

Highland

Athens

Springville

Short Haul 300-850 MDth/d Incremental Capacity

Lease Line Loop Potential Compression


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MICHIGAN

Chicago

Detroit

Lake Michigan

Lake Erie

Lake Huron

ONTARIO

WISCONSIN

Dawn (Union)

VectorMichig an Supp ly Hub

ector ipelineTM

Vector ipelineTM

Joliet

Washington

Highland

Athens

Springville


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Questions


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Providing A Competitive Link tothe WCSB and the Bakken

Vector Pipeline Shipper MeetingOctober 17, 2013


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A Unique Energy Transporter

System Capability

Approximately 1.6 Bcf/d of capacity 250 mmcf/d receipt capacity from Bakken Over 99% reliability


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Rich Gas Capability / Advantages

Designed and optimized to ship

liquids-rich natural gas streams Carries over 100,000 bpd of

entrained natural gas liquids

Average heat content:

Alliance pipeline~1110 Btu/cf Other WCSB &

Midwest pipelines~1025 Btu/cf

Alliance volumetric toll yieldsdecreasing energy toll asheat content rises

Alliance heat content is rising

980

1,000

1,020

1,040

1,060

1,080

1,100

1,120

APL Other Regional Pipelines

B t u / c f

Alliance vs. Other WCSB & Midwest Pipelines

Source: WCSB & Midwest Pipeline websites, Alliance website

ll d


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Vector

0

2

4

6

8

10

12

2010 2015 2020 2025

B c

f / d

Bakken

Montney

Duvernay

NGL Rich Shale Gas Production

02468

10121416

2000 2005 2010 2015 2020 2025 2030

B c

f / d Other

TransportPower IndustrialCommercialResidential

Source: Wood Mackenzie Spring 2013 Long-Term View

Source: Enbridge 2013 Fundamentals View

Midwest Region Demand Growth

Well Positioned

RegionHeat Content

(btu/cf)

BC North Montney > 1200

BC Groundbirch > 1100

AB Montney > 1100

AB Duvernay > 1200

AB Cardium > 1100

North Dakota Bakken > 1200

NGL Rich Shale Gas Heat Content

ACE H b Alli Chi E h


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ACE Hub Alliance Chicago Exchange

ACE Hub Services and Connections: Enhanced Title Transfers Interruptible Wheeling (IW) Park and Loan (PAL)

k


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New 2015+ Services Framework

ChicagoHub

Tioga Lateral

TransferPool

New Services Framework includes :

New zones

New Canadian Trading Pool

Toll Certainty

Increased ability to carry natural gas liquids

Rich gas toll crediting

Market price sharing option

Reduced credit requirements

2015+ services are being subscribed

New options for receipt and delivery shippers

ACEHub

h


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Unique / Competitive Service Choices

3-10 Years2 Price Tiers

Fixed Rates1-10 YearsFixed RatesFDS

FT-1

FRS

1-10 YearsNegotiatedFixed RatesCanada

U.S.3-10 YearsNegotiatedIndex Based Rates

FDS

CanadaU.S.

FT-1

FT-1

3-10 Years2 Price TiersNegotiated

Fixed Rates

Segmented

IndexBased

FullPath

TitleTransfer

3-10 YearsNegotiated IndexBased Rates

ACEHub

Alliance volumetric tolls converted to energy equivalents@ fixed 41MJ/m 3 (1,100 Btu/cf).

ACEHub

3-10 Years2 Price TiersFixed Rates

FPS

CanadaU.S.

ACEHub

ATP

41

$0.00 $0.50 $1.00 $1.50 $2.00

Proposed

Current

5-yr Fixed

$/MMBtu

Alliance / Vector

Alberta Field to Dawn Tolls (Dry Gas Basis)

NGTL / TCPL

L f d l h l i i


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Long term fundamentals support the value proposition

AECO-Chicago differential is forecast to widen over the longer term(more supply build for BC LNG, more WCSB rich gas, less attraction to TCPL Mainline)

.00

.40

.80

1.20

1.60

2.00

2013 2014 2015 2016 2017 2018 2019 2020

$ / m m

b t u

Alliance ATP to CHI Fixed Toll, incl. fuel

Enbridge fundamentals analysis indicates AECO-CHI differentialwill reach $0.80 by 2017 and continue to widen to 2020

AECO-CHI Differential($0.80 YTD Average for 2013 )

F Additi l D t il


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For Additional Details

For additional details including onhow to participate in the AlliancePrecedent Agreement process visit:www.alliancepipeline.com andclick on the tab

> Post-2015 Capacity

Alliance Toll for ATP to Chicago:$0.64 / mmbtu , excluding fuel

Aux Sable: Rich Gas Value Enhancement


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Aux Sable: Rich Gas Value Enhancement

Rich GasAllianceTrading

PoolAux Sable

ChicagoGas

AllianceReceipt

Zone

Contractedby Producer

AllianceTransmission

Zone

Contracted byLong-haul

Shipper

Aux Sable providescompetitive gas netback

with Alberta market

Aux Sableshares NGL

value

NGLs remain critical to

Natural Gas drilling decisions

Aux Sable is utilizing Rich GasPremium contracts to increaseNGL content

Producers avoid costly field plantinvestment

Provides competitive gas and NGLnetbacks / price transparency

Access to larger / liquid markets

44

Source: Alberta Energy; Aux Sable


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Questions ?


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NEXUS Gas Transmission Overview

New pipeline to connect Appalachian Basinsupply to U.S. Midwest and Dawn markets

Strong development partners - DTE Energy,Enbridge and Spectra

250 mile, large diameter pipeline delivering atleast 1 Bcf/d

In service by November 2017; potential tophase into service

Uses existing infrastructure and utility corridors

Firm path to Dawn Hub with interconnects tomajor markets along the way

Ohio Michigan (DTE Gas, Consumers, Vector) Ontario (Union Dawn, Enbridge

Tecumseh)

47

DTEGas


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48

NEXUS Open Season Review

Open season ran from October 15 November 30, 2012 Received interest and support from producers, LDCs, power generators and industrial customers

Volumes requested exceeded the 1 Bcf/d planned capacity of the pipeline Anchor shipper criteria:

150 Mdth/d volume commitment 15 year contract term

Anchor Shippers Several parties submitted requests that met or exceeded the Anchor shipper criteria Anchor shipper requests alone exceed the 1 Bcf/d planned capacity Split between market and producers

Currently negotiating PAs with the market


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NEXUS Route Update

Main route from M3 Kensington plant, TGPinterconnect, Dominion lateral and TETCOOPEN lateral in Columbiana County OH to DTEGas, Vector and Dawn

Potential laterals to other locations in NE OHand NW PA

Pipeline corridor has been selected 75% of corridor will be co-located to

minimize impacts Community outreach begun along corridor Government Relations campaign in OH & MI

Route to Dawn will use transportation on DTEGas and Vector

Transportation By Others (TBO) minimizesfacilities, environmental impacts and costs

DTE Gas and Vector can both be easilyexpanded with compression or looping

Uses existing international river crossing

49


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NEXUS Costs & Schedule

Still on track for $0.60/Dth rate to Michigan and $0.80/Dth rate to Dawn

Planned in service date of November 2017 for the greenfield projectPhased-in project start with bridge capacity from Michigan to Dawn

Currently negotiating PAs with the market Producers need additional time to finalize their development plans in the Northern Utica acreage

Key items over the next 6 months include: Complete PAs with market Secure interest from producers Stakeholder / Landowner Outreach Environmental Assessment Engineering and ROW Refinements Benefit studies for Ohio and Michigan completed Begin preparation for FERC pre-filing

NEXUS is continuing to make progress


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The widening transportation spread is also beingreflected in the forward market

52

January 2, 2013 basis spread

July 24, 2013 basis spread


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Questions?

53


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Natural Gas Market Dynamics

Sesha NarayanOctober 17, 2013 Vector Customer meeting

The U.S. energy landscape continues to be


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The U.S. energy landscape continues to beprofoundly impacted by the growth of shaleproduction

55Source: EIA

U.S. Shale Gas ProductionTrillion Cubic Feet

8.1

3.5

1.00.50.3

2000

+42%CAGR

2012200920062003

U.S. Shale / Tight Oil ProductionMM Barrels per Day

2.0

0.6

0.20.10.2

+47%CAGR

20122009200620032000

2% 3% 5% 17% 34% % ofTotal 3% 3% 4% 12% 32%

Beginning in 2005 and particularly since the shale


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Beginning in 2005 and particularly since the shalerevolution, we have seen a massive decouplingbetween prices for oil and natural gas

56Source: NYMEX

0

5

10

15

20

2002 2004 2006 2010 201220081996 1998 2000

Crude oil (WTI)

Natural gas (Henry Hub)

$ / M M B t u Historically, oil and gas prices

have been tightly linked

Shale revolution

De-Coupling of Crude Oil and Henry Hub Natural Gas Prices

In response to the large spread between liquid and


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In response to the large spread between liquid andgas prices, producers have focused on basins withhigher concentration of condensate and NGLs

571: NGL composite comprised of 42.5% ethane, 27.5% propane, 12.5% natural gasoline, 10% isobutane, and 7.5% butane2: Rig counts from February 2011 September 2013Source: NYMEX, Baker Hughes

0

5

10

15

20

25

201320122011

$/MMBtu

NGL Composite 1

Natural Gas

Crude Oil

Natural Gasoline

Butane

Propane

Ethane

2011 Sep 2013 Petroleum Product Prices2011 2013

2

Change in Rig CountFor key shale basinsHighest Concentration

of Liquids

Lowest Concentrationof Liquids

(49)

(42)

(42)

(9)

7

24

(22)

(122)

(37)

Fayetteville

Haynesville

Barnett (51)

Marcellus

Woodford (31) 11

Utica 2720

Eagle Ford 100149

Bakken

OilGas

V i i h f h d


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Composition ofGas Stream

Variances in the presence of these compoundscan have a profound impact on overall economics

581. For Pioneer, includes lean and rich condensate windows; for Chesapeake, based upon 19 producing wells in wet window; for Range, wet window composition2. After-tax IRR at NYMEX forward curve as of September 25, 2013; average NGL % of crude oil pricing 2013 YTD; crude price of $90/bbl; ethane priced as natural gasSource: DTE analysis

Effective Dry Gas Breakeven Prices

For select shale plays; Assuming 10% after-tax IRR $2.45

$0.40

($3.60)

($5.60)

Eagle Ford(Pioneer) 1

NE Marcellus(Susquehanna County)

Utica(Chesapeake) 1

SW Marcellus(Range Resources) 1

IRR at CurrentForward Curve 2 ~90% ~70% ~60% ~30%

35%

25%

40%

Gas

NGL

Condensate

17%56%

27%

53% 46%

1%

100%

DriestWettest

Th h i hi h l li id h l d t


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The emphasis on higher-value liquids has led toan increase in associated gas production

59Note: 2013 rig count as of 10/4/2013Source: EIA; Baker Hughes; DTE analysis

U.S. Associated Gas Production and Average Annual Oil Rig Count

12

11

9

77

66

0.0

2.5

5.0

7.5

10.0

12.5

15.0

0

250

500

750

1,000

1,250

1,500

A s s o c

i a t e d G a s

P r o

d u c t

i o n

( B c

f / d )

2013YTD

13

2012201120102009200820072006

Oi l Ri g

C o un

t

Overall, total natural gas production has managed


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, g p gto increase / remain steady, despite steep declinesin the gas-focused rig count

60Note: 2013 rig count as of 10/4/2013Source: DTE analysis, Baker Hughes

U.S. Natural Gas Production and Gas Rig Count

0

250

500

750

1,000

1,250

1,500

1,750

30

0

70

60

50

10

40

20

G a s -F o c u s e d Ri g

C o un

t

N

a t u r a

l G a s

P r o

d u c

t i o n

( B c f

/ d )

2013F

62

2012

66

2011

64

2010

59

2009

57

2008

56

2007

51

2006

54

Shale growth has dramatically altered traditional


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g yflow patterns; U.S. Northeast imports havedeclined as Marcellus production has increased

61Note: Northeast defined as New England (Maine, Rhode Island, Connecticut, Massachusetts, New Hampshire, and Vermont) and Mid-Atlantic (New York, New Jersey, andPennsylvania)Source: DTE GPCM model

11

0

9

1

3

5

7

8

6

4

2

10

LNGRockies

Canada

Gulf Coast

Other

U.S. Northeast Imports versus Marcellus ProductionBcf/d

8

9

0 Apr-2013Jan-2013Oct-2012Jul-2012 Apr-2012Jan-2012Oct-2011Jul-2011 Apr-2011Oct-2010 Jan-2011

10

11

7

6

5

4

3

2

1

MarcellusProduction

In recent years, North American demand has


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y ,grown modestly, growth in the U.S. has been ledby the electric power sector

62Source: EIA; DTE analysis

U.S. Natural Gas DemandBcf/d

70

60

50

40

30

20

10

0

+1.4%CAGR

2006

Other

Industrial

60

20122008 2010

66

Electric Power

Commercial

Residential

Canada Natural Gas DemandBcf/d

10

0

8

4

2

6

+0.7%CAGR

2006

9.3

20102008

9.8

2012

10%

14%

8%

14%

2%

16%

9%

16%

5%

(24%)

Changesince 06

Change

since 06

Gas demand in the electric power sector has


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pdeclined between 2012 and 2013 as gas priceshave risen

63Source: Bentek

U.S. Natural Gas Power Burn

Bcf/d per month (based upon average daily data)2005-2011 Min / Max Range 20132012

0

5

1015

20

25

30

35

40

P o

w e r

B u r n

( B c f /

d p e r

M o n

t h )

3.33.53.32.82.82.9

2.42.41.9

2.22.52.7

3.63.4

3.63.84.04.23.8

3.33.3

1

2

3

4

5

Aug SepJun Apr May DecMarJan Feb Jul Nov

N a

t u r a

l G a s P r i c e s

( $ / M M B t u )

Oct

Storage inventory has returned to traditional


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levels, retreating from the historical highsexperienced in the spring of 2012

64Source: Bentek

3.0

3.5

2.5

AugMar OctJunFeb

1.0

1.5

0.5

2.0

May Jul Sep0.0

Nov

4.0

AprJan Dec

L - 4

8 G a s

i n S t o r a g e

( T c

f )

2013 Balance2012 Balance

U.S Gas Storage LevelsTcf

2007 - 2011 Min / Max Range

The abundance of shale gas supplies has had a


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The abundance of shale gas supplies has had amaterially adverse effect on storage spreads

65Note: Spreads calculated as December-February (deep winter) average less May October averageSource: NYMEX

Prompt Year Storage Spreads$/MMBtu; Average spreads from August of listed year

$0.35$0.44

$0.55

$0.73

$1.16

$0.99

$1.30

$0.91

2009 2010 2011 2012 2013200820072006

$2.40

2005

2005 2010 Averag e: $1.25

Natural gas prices have increased over the past


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twelve months, generally in line with the forwardcurve from September 2012

66Source: NYMEX

Henry Hub Spot Prices versus NYMEX Futures (from Sep 2012)$/MMBtu

2.5

3.0

3.5

4.0

4.5

Nov 2012 Jan 2013 Mar 2013 May 2013Sep 2012 Jul 2013 Sep 2013

NYMEX Futures- Sep 2012

Henry HubSpot Pr ice

The equilibrium price of gas is set by the marginal


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cost of supply of annual new production neededto replace the ~8 9 Bcf/d of natural decline

67Source: DTE Analysis, Wood Mackenzie

An incremental ~8-9 Bcf/dsupply from new wells isneeded each year to makeup for natural productiondecline from existing wells

2011 2012 2013 2014 2015

80

70

60

50

40

30

0

Bcf/d

Demand with growthFlat demand

Supply with nonew drilling

Exact amount of annual

replacement neededdepends on existing wellsdecline curves

New supply needed to meetdemand growth isincremental to this (~1 Bcf/d)

Illustrative

Cost of supply is falling as a result of significant


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Cost of supply is falling as a result of significantimprovements in drilling and well productivity

681: Breakeven at 10% after-tax IRRSource: Cabot investor presentations, DTE analysis

Days to Drill Lateral Length (000 Feet)

4.13.83.4

2.7

+52%

2012201120102009

1620

26

32-50%

2012201120102009

$1.85

$3.10

2012

-40%

2009

14.113.211.2

7.8

2012

+81%

201120102009

EUR Estimated Dry Gas Breakeven Price 1

Marcellus Drilling Productivity: Cabot Oil & Gas Example

In the near term, we expect the equilibrium price of


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natural gas to remain in the $3.50 - $4.50 range,driven by the cost of new supply

691. Breakeven calculated at 10% after-tax IRRSource: DTE analysis

$0

$1

$2

$3

$4

$5

$6

- 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 Bcf/d

Outlook in Early 2012

Breakeven cost of supply1

($/MMBtu)

Natural Gas Equilibrium Pricing

Revised OutlookBased uponContinued

Productivity

Improvement

~$3.50 4.50 / MMBtuequilibrium price

Includes those playswhose breakeven is

below $2

Dry PlaysWet Plays

~8 - 10 Bcf/dnew supply

needed


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U.S. growth will be driven by Utica / Marcellus and


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liquid-rich regions, while conventional supply isforecasted to decline

71Note: Conventional supply also includes coal bed methane and SNGSource: DTE analysis

Woodford

Bakken

Marcellus

Fayetteville

Haynesville /Bossier

Eagle Ford

Utica

Barnett

U.S. Production by BasinBcf/d

50

20

10

60

40

100

90

80

30

70

02030202820262024202220202018201620142012

66

93

Conventional

Other Shale

Fayetteville

Bakken

Woodford

Barnett

Utica

Eagle Ford

Haynesville

Marcellus

12 30 Change (Bcf/d)

+12.7

+2.5

+6.5

+5.1

(0.6)

+2.4

+3.0

+0.4

+0.2

(6.3)

Canadian output will expand as increases in shale


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Canadian output will expand, as increases in shaleoutweigh declines in conventional gas production

72Note: Conventional supply also includes coal bed methaneSource: DTE analysis

Canada Production by BasinBcf/d

12 30 Change (Bcf/d)

+4.9

+2.9

+1.6

(4.0)

6

0

2

10

8

12

22

14

16

18

20

4

2018 20202014 20162012 2026 20282024 2030

15

2022

20

Conventional

Duvernay

Montney

Horn River

Horn River

Montney

Duvernay

Long-term demand growth will be modest, driven


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Long term demand growth will be modest, drivenby electric power and industrial segments

73Source: DTE analysis

U.S. Natural Gas DemandBcf/d

90

80

70

60

50

40

30

20

10

0

Industrial

2030

84

20252012

Commercial

70

Other

Electric Power

2015 2020

Residential

+1.1%CAGR

Canada Natural Gas DemandBcf/d

15

10

5

02012

9.9

2030

14.1

202520202015

+2.0%CAGR

13%

16%

11%

16%

97%

72% 17% 12%

57%

37%

Change

from 12

Change

from 12

In addition, electric power demand could increasef h h ld h U S i l b i i


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further should the U.S. implement carbon pricingand / or carbon reduction targets


2030 Implications ofCO 2 Reduction Case

Natural gas (1.2 TWh ofgeneration in 2012) would ascendto top electrical power source,responsible for ~40% ofgeneration

Coal (1.5 TWh in 2012) would beimpacted by material coal-to-gasswitching, and would see its shareof generation falling by half to~20%

Renewables (~0.2 TWh in 2012)would experience strong growth,led by wind (~12% of generation)

U.S. Power Sector Natural Gas DemandBcf/d

40

34

30

25

CO2 CaseReference Case:2012

+34%

CO2 Reduction Case:

(20% from 2012 Levels)

2030

No Price onCarbon

Implementationof Carbon Price

Carbon Price +Higher Renewables &Coal-to-Gas Switching

LNG exports are expected to expand, as a host ofj l i li i d


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projects move closer to commercialization andregulatory approval

75Note: Approved indicates non -FTA (Free Trade Agreement) export license approval (U.S.) or NEB application approval (Canada)Source: CERA

Key Proposed / Approved LNG FacilitiesSize of bubble corresponds to size of project; Not exhaustive

Summary of LNG ProjectsBcf/d

Jordan Cove

Lake Charles Exports

Cameron LNG

Sabine Pass

Freeport LNG Main Pass Energy

Prince Rupert (Prince Rupert L NG, Pacif ic Northw est LNG)

Kit imat (Doug las Channel , Kit imat LNG, LNG Canada)

Cove Point

7

5

12

U.S.

49

Proposed

Canada

11

TOTAL

Approved*

16

38

27

34

Equates to 2.0 Bcf/d

Factoring in demand for LNG exports, the WestS h C l d S h A l i i ill


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South Central and South Atlantic regions willexperience the largest demand growth


U.S. Lower 48 Natural Gas Demand by RegionBcf/d

2.4

7.8

9.2

4.5

17.4

10.0

4.2

4.9

8.1

New England

Middle Atlantic

South Atlantic

East South Central

West South Central

East North Central

West North Central

Mountain

Pacific

19.6

13.3

3.1

9.7

5.8

12.5

6.4

5.1

7.2

4.0

14.21.0

23.6

Change(+ / - Bcf/d)

(0.8)

0.3

2.2

2.5

6.3

1.25.1

1.9

0.7

2012 2030

LNG Exports

To accommodate the new supply / demandliti t diti l fl t d t


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realities, traditional gas flows are expected toundergo significant changes


Overview of Natural Gas Flows: Key Changes from 2012 to 2030

Increasing

Consistent

Decreasing

Mid-Continent

Rockies

Bakken

Utica &Marcellus

GulfCoast

WesternCanada

Overall, prices are expected to increasei t ll ti b t h ld i ll


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incrementally over time, but should remain wellbelow pre-shale levels

78Source: NYMEX (10/11/13); DTE analysis

$2

$3

$4

$5

$6

$7

$8

$9

2008 2010 2012 2014 2016 2018 2020 2022 2024

DTE

NYMEX

Actual

2008 2025 Annual Henry Hub Price (Nominal)$/MMBtu

In addition, key producing hubs are expected torem in disco nted rel ti e to Henr H b o er the


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remain discounted relative to Henry Hub over thelong term

79Note: October 11 close date used for spot price and 2015 futuresSource: NYMEX, OTC Global Holdings, CERA

Forward-Looking Basis Differential:Select Gas Hubs

Relative to Henry Hub; $/MMBtu

Hub CurrentSpot Price2015

Futures2020

CERA

AECO (W. Canada) ($0.65) ($0.65) ($0.58)

Chicago $0.00 ($0.10) $0.06

MichCon $0.03 ($0.06) $0.15

Dawn $0.29 $0.09 $0.30

Lebanon $0.01 ($0.26) -

Columbia Appalachia ($0.06) ($0.23) ($0.25)

Dominion South Point ($0.30) ($0.44) -

1

4

5

6

3

2

56

3

Chicago

Dawn

DominionSouth Point

Lebanon

MichCon

ColumbiaAppalachia

1

2

4


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Questions


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Vector ipelineTM

Vector ipelineTM

Discussion


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Vector ipelineTM

Thank You

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2013 Customer Meeting Presentation

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