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Energy and commodity price benchmarking and market insights

North American shale boom drives new challenges for transport sector

David GivensMay 2012

Who is Argus?

• Report prices globally foro Gaso Powero NGL & LPGo Emissionso Coal and cokeo Refined productso Crudeo Fertilizers

• Over 400 staff globally with numerous offices• Rapid growth in spot and term contract

indexation, swap market indexation

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Argus Natural Gas Americas

• Abundant pipeline capacity from shale plays• Firm transportation devalued in benign

regulatory environment • Crude, NGL production drives gas output• Basis narrows*, except in US Northeast

* Except in abnormal weather

Takeaways

Gas, crude and NGL fundamentals

US crude, gas production rising

Dec-08145

155

165

175

185

195

1,400

1,550

1,700

1,850

2,000

2,150Crude production vs gas

Crude Gas

'000 b

l/month

Tcf

/month

Three years of divergence

Dec-08 Oct-09 Aug-10 Jul-11 May-120.0

5.0

10.0

15.0

20.0

25.0

US crude, gas Btu comparison

Henry Hub ASCI

$/m

mB

tu

NGL prices rise relative to gas

Dec-08 Oct-09 Aug-10 Jul-11 May-1250

100

150

200

250

1.5

3.0

4.5

6.0

7.5Propane and butane vs gas

Mt Belvieu propane Mt Belvieu butane Henry Hub gas

¢/U

SG

$/m

mB

tu

8 May, 2012$/mmBtu

• Value of natural gas vs. splitting CH4 into NGLs

• Each NGL is assumed a representative % of barrel

• Each NGL distinct heating value

• Fuel used to frac (shrink)

• Btu value of some NGLs weaker recently

Fractionation spread

Seen in Eagle Ford, Bakken

Midstream paradise

4-Jan 3-Feb 4-Mar 3-Apr 3-May0.5

1.5

2.5

3.5

4.5

5.5

Mont Belvieu fractionation spreads

Non-LDH (Non-TET) Ethane PropaneNormal Butane Iso-ButanePentanes Plus

$/m

mB

tu

Possible ethane rejection

4-Jan 3-Feb 4-Mar 3-Apr 3-May0.5

1.5

2.5

3.5

4.5

Conway fractionation spreads

Ethane-Propane Mix Propane Normal ButaneIso-Butane Pentanes Plus

$/m

mB

tu

NGL fracs roll up to high margins

Continuing growth

Dec-0818,000

21,000

24,000

27,000

30,000

33,000

Ethane-ethylene production

Source: EIA

'000 b

l

Price/mmBtu for 15pc ROR

• SW Marcellus, wet: $1.85• SW Marcellus, dry: $3.19• NE Marcellus, dry: $3.60

Source: LyondellBasell

• “Super Rich Marcellus” ROR: 55pcSource: Credit Suisse

Low breakevens, high RORs narrow basis

• Shale plays drive midstream oil pipelining:o Bakkeno Eagle Fordo Permian Basin

• Light sweet imports into US should continue to drop and eventually even disappear altogether

Crude pipeline projects boom

What does it mean for US natural gas?

• No requirement to update gas pipeline tariff • No “major” FERC rulemakings in 20 years*• New pipeline tariffs are negotiated• New construction weighted toward incremental

pricing

* Order 712

US natural gas regulatory fundamentals

• Pipeline tariffs disconnected from markets• Producers subsidized bullet pipes from shales• Gas, storage everywhere devalues firm

transport• All regions have adequate gas• Basis spreads do not support transport costs • Generic FERC policy considered to restructure

tariffs on legacy pipes due to shale

Recent dynamics

• FERC Order 712 (2008)o Removed price caps on short-term

capacity releaseo Ever-increasing capacity release

volumeso Facilitated Asset Management

Agreements (AMAs)

One reason marketers stay profitable today

“Shale gas in the middle of long haul pipelines presents opportunities to segment more capacity and release more capacity.”

Steve Hinton, Engineering Director, Skipping Stone (Capacity Center)

What the future holds

“Our industry has evolved toward a market-driven model.”

Donald F. Santa, president, Interstate Natural Gas Association of America (and FERC commissioner 1993-1997)

The bottom line

• Traditionally served by gas patch• More shale plays exist• Pipeline capacity turnback• Some constrained burnertip markets• Shale gas + capacity release = underutilization• Backhaul prospects everywhere

o Tetcoo Transcoo Columbiao Tennessee

Impact on East markets

• Load factor dropping south of Marcellus interconnects

• Volumes climbing east of compressor station 219

• 300 line was flowing east to west at one point last year

• “Non-straight fixed variable” rates in market zones 4 through 6

Tennessee Gas Pipeline 2011 rate settlement

Tennessee Gas Pipeline in northeast states

TGP zone boundaries Pipeline location

Traditional Boston-Gulf Coast spreads

2009 2010 20110.00

0.75

1.50

2.25

3.00

0.45 0.43 0.5

1.10

2.55

1.03

Tennessee Z6 minus 800 leg

April-Oct Nov-Mar

$/m

mB

tu

Effect on Columbia system

2009 2010 20110.05

0.10

0.15

0.20

0.25

0.160.15

0.12

0.21

0.18

0.08

Columbia App minus Onshore

April-Oct Nov-Mar

$/m

mB

tu

The last great gas market

Jan-09 Aug-09 Apr-10 Nov-10 Jun-11 Feb-120

3

6

9

12

15Iroquois Zone 2 basis to Henry

$/m

mB

tu

Hot Gulf Coast summer 2011

2009 2010 20110.00

0.07

0.14

0.21

0.28

0.01

0.06

0.14

0.17

0.240.23

Chicago minus ANR SE

April-Oct Nov-Mar

$/m

mB

tu

Traditional Midcontinent winter basis

2009 2010 20110.05

0.10

0.15

0.20

0.25

0.30

0.08

0.11

0.17

0.27 0.29

0.23

Chicago minus NGPL South Texas

April-Oct Nov-Mar

$/m

mB

tu

• Fewer shales, less storage

• Weather, capacity issues major drivers

• Summer gas basis expected tight with SONGS outage

• Effects of Ruby, Rockies Express

• GTN tariff amendment to flow gas north

• GTN Transmission firm transport 33c/mmBtu

• Northwest Pipeline firm transport 44c/mmBtu

Western market impact

Western basis volatility

2009 2010 20110.00

0.09

0.18

0.27

0.36

0.11

0.05

0.190.19

0.0800000000000001

0.320000000000003

SoCal border minus El Paso Permian

April-Oct Nov-Mar

$/m

mB

tu

Canadian deliveries down last year

27-Jul 9-Aug 22-Aug 4-Sep 17-Sep 30-Sep0

500

1,000

1,500

2,000Ruby, GTN flows at Malin

Ruby GTN GTN 2010

mn c

f/d

Source: Ruby, GTN pipelines

Malin premium to Opal has fallen

Jan-10 May-10 Sep-10 Jan-11 May-11 Sep-11-1.0

-0.5

0.0

0.5

1.0Malin-Opal basis

$/m

mB

tu

Marcellus pushes REX supply west

2009 2010 20110.09

0.18

0.27

0.36

0.450.42

0.27

0.14

0.35

0.15 0.14

Malin minus Opal

April-Oct Nov-Mar

$/m

mB

tu

REX versus Marcellus

April-Oct Nov-Mar0.1

0.2

0.3

0.4

0.5

0.6

0.7 0.650000000000005

0.320000000000003

0.330000000000003

0.15

Clarington minus Cheyenne

2010 2011

$/m

mB

tu

Winter gas demand in Northwest

Jan Feb Mar Apr May Jun Jul Jul Aug Sep Oct Nov Dec-2

0

2

4

6Sumas daily cash basis

2009 2010 2011

$/m

mB

tu

Lower pressures vs. Ruby start up

Jan Feb Mar Apr May Jun Jul Jul Aug Sep Oct Nov Dec-1.50

-0.75

0.00

0.75

1.50PG&E gates daily cash basis

2009 2010 2011

$/m

mB

tu

Breakout years ahead?

1949

1952

1955

1958

1961

1964

1967

1970

1973

1976

1979

1982

1985

1988

1991

1994

1997

2000

2003

2006

2009

2012

2015

0

6

12

18

24

30US Gas Consumption

Source: EIA

Tcf

/yr

• Plentiful US gas and transport capacity; basis does not support tariffs

• Capacity release volumes keep growing• Btu values of crude, NGLs keep production high• East: backhauls, displacement• Western markets reveal more constraints

Takeaways

Any questions?

David GivensHead of Gas & Power, Americasdavid.givens@argusmedia.com+1 202 349 2891www.argusmedia.com