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Interesting Times:
Navigating the Uncertainties in the North American Gas
Market
Ed Kelly
Vice President North American Gas and Power
Wood Mackenzie
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Risks and Uncertainties – On the Supply Side
The Resource Base is Vast, but Production Levels and Cost Remain Uncertain
1) Environmental resistance – especially hydraulic fracturing regulations.
• Environmental resistance, and political attention, continue to build
• Regulatory costs and permitting delays could slow development considerably
• And increase the ultimate cost, and gas price, substantially
2) Ultimate shale/unconventional production performance
• By 2013-2014, we will know much more about how shale wells perform longer term, and will
have a much better idea of ultimate recoveries and production potential for a given well
3) Competition with oil for upstream dollars and services
• Companies moving toward oil are moving away from dry gas - gas shale plays must compete
for horizontal rigs and crews
• A booming opportunity in oil could raise target IRRs on gas plays as producers seek the best
margins
2
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Risks and Uncertainties – On the Demand Side
Demand Opportunities Require Major Capital Commitment or Policy Help, while Risks
are Few
1) Carbon and environmental policy – coal retirements are the lever
• Wide range of possibilities w. carbon depending on the targets, timing, price and investment
focus
• EPA regulation and pressure on older coal units—how many retire?
2) A weak economy – 1 year of recession takes 2-3 years of demand growth off the
table
3) New (or renewed) markets for gas
• Gas-intensive industries represent an opportunity, but depend on liquids and global dynamics
• NGVs? Difficult competition from plug-in hybrids for passenger cars and energy density issues
for long haul heavy duty vehicles
3
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So How is it Looking?
For Supply – Stronger Potential, but…
• Haynesville, Marcellus, Fayetteville, Eagle
Ford, and Canadian shales all look stronger
• How much capital is reallocated toward oil
drilling, and how much new capital enters?
• How threatened is hydro-fraccing? What will be
the results of the ongoing EPA study, and what
conditions will the Interior Department place on
drilling on federal lands?
4
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Led by Key Shales, US Supply Growth Continues: for a Few More Months
US production
Over the last six
months, Haynesville,
Fayetteville, and
Marcellus production
climbed by 1.5 bcfd
12
60.0
58.0
10
bcfd
54.0
6
bcfd
56.0
8
52.0
4
50.0
2
48.0
0
46.0
n
A -08
pr
Ju 08
l
O -08
ct
Ja -08
n
A -09
pr
Ju 09
l
O -09
ct
Ja -09
n
A -10
pr
Ju 10
l
O -10
ct
Ja -10
n
A -11
pr
Ju 11
l
O -11
ct
Ja -11
n
A -12
pr
Ju 12
l
O -12
ct
-1
2
Ann Avg production
expected to peak this
year and next at 60.5
Bcfd dry.
62.0
Ja
US Production
currently (Feb)
running an estimated
1.5 Bcfd above year
earlier levels
14
Haynesville
Marcellus
Fayetteville
Total
5
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Setting the stage—The next 18 months; breaking beyond coal competition
Short-Term Price Outlook
Flat supply, firmer global
markets, and power demand
supports price rebound from
current lows
12
Prices below $4.00/mmbtu are
likely short-lived (end mid 2011)
For 2011, prices recover into
the mid $4.00s ($4.60 nom) as
the market remains wellsupplied
10
$/mmbtu
•
14
8
6
•
Drilling levels are vulnerable
late in year
4
•
Market support develops by
winter 2011/2012 ($5.41 2012
price)
2
0
Jan-08
Jul-08
Jan-09
Jul-09
Jan-10
Jul-10
Jan-11
Jul-11
Jan-12
Jul-12
$6.00 by late 2012
CAPP spot
Henry Hub
CAPP contract
Source: Wood Mackenzie
6
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2012: Declining rig counts cut into supply and gas demand, and price
recovery is hampered by loss of coal displacement demand
Drilling and supply
59.5
Power sector summary
600
Decline in 2012
production…
59.0
25
500
58.5
20
57.5
300
bcfd
400
58.0
bcfd
…pulls down 2012 power
demand by limiting
displacement
30
15
10
5
57.0
200
0
56.5
100
56.0
55.5
2009
2010
2011
US Production
Sources: Wood Mackenzie, Smith Bits
2012
Key Shale
2013
0
2014
Other Rigs
2007
2009
2011
2013
2015
-5
Normalized gas demand
Displacement
Weather effect
Disp. $4.50-5
Disp $5-6
Disp. $4-4.50
Total gas demand
Source: Wood Mackenzie
7
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How many rigs does it take to hold production flat?
About 900, and we’re at the Tipping Point. But – it depends on where those rigs are.
With horizontal rigs at record highs and increased rig productivity, rig counts required
to maintain production have dropped significantly
Rig counts to maintain production at 2010 year-end levels depend strongly on activity
levels in key growth shales
• The rig count to sustain production could be even lower once a majority of shale drilling
switches to pad rigs, after acreage constraints ease
Rig counts required to maintain production at 2010 year-end levels
Total Rigs Haynesville Eagle Ford Fort Worth Marcellus Fayetteville & Non-shale
Woodford
horizontal
Low emerging shale
1,050
75
70-85
110
90
40
190
Base case
900
100
90-105
90
90
40
160
High emerging shale
780
125
115-135
50
90
40
120
Current
974
172
58
88
90
45
205
8
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The Resource Base is There: Supply Analysis by Region Shows the
Potential for Broad-based Growth (Bcfd, dry)
120
Supply overall
increases by 27 Bcfd in
the US 2010-2030.
This represents an
increase of 5.1 Bcfd in
2025 in the US from
Wood Mackenzie’s
previous long-term
view.
Not only do we not
need LNG – for the first
time we do not need an
AK pipe, either.
80
bcfd
The largest increases
are in the Gulf Coast
and the Northeast.
100
60
40
20
0
2000
2002
2004
Rockies
Permian
WCSB
2006
2008
2010
San Juan
Fort Worth
East Coast
2012
2014
2016
Gulf Coast
Northeast
Arctic
2018
2020
2022
Gulf of Mexico
West Coast
2024
2026
2028
2030
MidContinent
Alaska
9
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But – Will we be Allowed to Get to It? The Supply Mix Depends on Shales,
and Hydraulic Fracturing
45
Close to 50% of total
supply longer term
will be affected by
regulations on
hydraulic fracturing.
Marcellus – to 10
Bcfd
Haynesville – to 8-8.5
Bcfd
Horn River – to 5 Bcfd
Fayetteville – to 4-4.5
Bcfd
35
30
bcfd
Still, strong growth
potential - 28.5 Bcfd
in the known shale
plays by 2025!
40
25
20
15
10
5
0
2000
2003
Barnett
Haynesville
Horn River
2006
2009
2012
2015
2018
Fayetteville
Marcellus
Montney & Duverney
2021
2024
2027
2030
Woodford
Eagle Ford
10
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So How is it Looking?
For Demand – Promising Signals
• Several announcements about methanol and ammonia capacity being
restarted—new capacity announcements to come?
• Many petchem producers lightening their feedslates
• Several proposed LNG export facilities have signed MOUs, and global gas
prices have recovered more quickly than expected
• Coal mining costs look likely to support a higher cost structure—but how
fast can retirements come while preserving grid stability?
• Will high oil prices jeopardize fragile economic recovery?
11
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Short-term economic outlook has improved, but significant risks remain
Impact of high oil
prices on consumer
spending?
US GDP growth
3.5%
3.0%
2.0%
1.5%
1.0%
0.5%
Sept. 2010
25
20
24
20
23
20
22
20
21
20
20
20
19
20
18
20
17
20
16
20
15
20
14
20
13
20
12
20
20
11
0.0%
10
• “New normal”
unemployment rate
at higher levels?
2.5%
20
Long-term GDP
growth looks weaker,
with slower pace of
productivity growth
Prelim Apr. 2011
12
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And ammonia restarts and ethylene capacity conversions suggest a stronger
long-term pace of industrial demand growth
US industrial gas demand
Medium term growth
as capacity is restarted
20
15
10
5
29
20
27
20
25
20
23
20
21
20
19
20
17
15
20
13
20
20
11
20
09
20
07
20
05
20
03
20
01
99
20
19
97
0
19
bcfd
Improved environment
for US manufacturing
generally, as the dollar
depreciates and
massive trade
imbalances subside
25
East North Central
East South Central
Mid Atlantic
Mountain
Pacific
New England
South Atlantic
Non-Contiguous
West North Central
West South Central
Sept. 2010 outlook
13
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While robust gas demand in Asia, and cost inflation in Australia, look likely to
support at least a couple North American LNG export projects
LNG exports from Gulf Coast to Europe
LNG Exports from Gulf Coast to Asia
11% Brent; $100/bbl
15% Brent; $75/bbl; Panama Canal exp.
15% Brent; $75/bbl
$/mmbtu
$/mmbtu
11% Brent; $75/bbl
Regasified (Europe): HH + $4/mmbtu
Regasified (Asia): HH + $5.50/mmbtu
Regasified (Asia; Panama Canal):
HH + $4.85/mmbtu
Feedgas
price
Capital
cost
Commodity
charge
Plant
losses
Shipping
Regas
Feedgas
price
Capital
cost
Commodity
charge
Plant
losses
Shipping
Regas
14
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Gas and coal production costs are moving in opposite direction—although
carbon legislation now looks less likely to close this gap
Coal and carbon prices
7
7
6
6
5
4
30
25
20
5
4
15
3
$/ton
8
$/mmbtu
8
10
3
2
2
5
1
1
25
20
23
20
21
20
19
20
17
20
15
20
20
11
20
25
20
23
20
21
20
19
20
17
20
15
11
13
20
20
HH Sept. 2010
0
13
0
0
20
$/mmbtu
Gas prices
HH Apr. 2011 prelim
CAPP Sept. 2010
CAPP Apr. 2011 prelim
Carbon Sept. 2010
Carbon Apr. 2011 prelim
15
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…likely supporting more coal plant retirements
Coal-gas price spread
What is ultimately going
to replace CAIR?—
Differences between
Transport Rule and
Carper bill
2.00
1.50
1.00
• State-level caps
How quickly can plants be
retired?
29
20
27
20
25
20
23
20
21
20
19
20
17
20
15
20
13
20
-0.50
11
-
20
$/mmbtu
• Higher in aggregate,
but many regional
dislocations
0.50
-1.00
-1.50
-2.00
-2.50
Sept. 2010 coal-gas spread
Prelim Apr. 2011 coal-gas spread
16
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Will Gas Find Other Markets? Could the long-term price outlook—and the gap
with oil—fuel additional market opportunity?
Res/Com
Coal
retirements
Short
Circle size reflects
demand potential
Time Horizon
LNG
exports
Long
Industrial
NGVs
Carbon
bill
Plug-in
hybrids
Significant
Capital Investment Required
Minimal
Source: Wood Mackenzie
17
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(Other) Risks to the Outlook
Fiscal indebtedness
Currency swings
Spread of Civil Unrest
Political uncertainty
18
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Speaking of Which, On the Oil Side - Developing Economies (demand pull)
will exert greater influence on global oil demand
100%
Africa
Share in global oil demand
90%
FSU
80%
Developing
Economy
70%
Latin America
60%
Middle East
50%
40%
30%
Advanced
Economy
20%
10%
Non-OECD Asia
Pacific
OECD Asia
Pacific
Europe
0%
2005
2010
2015
North America
Source: History-IEA; Forecast-Wood Mackenzie
Source: History - IEA; Forecast - Wood Mackenzie
19
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As a Result: OPEC Spare Capacity Reduced Through 2015 : Our base case view
shown with the impact of lower than expected oil demand in the same period – and
this reduction is pre-crisis
7
6
Million b/d
5
4
3
2
1
0
2010
2011
2012
2013
2014
2015
Source: Wood Mackenzie
Source: Wood Mackenzie
20
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The Result: WTI Crude Oil Price Forecast to 2015 (Real and Nominal) and
Risk Factors
Oil prices return
to $100
(nominal) on
annual basis by
2013; $92 in real
terms.
Oil demand
growth
averages near
1.5 millions
Bbls/day
annually,
reaches 100
MMBbls/day by
2020.
120
Price Volatility Risk
Financial investors shift stance
100
80
US$/bbl
$95 real, $116
nominal by
2015.
Upward price risk
Political turmoil in key producing nations
Attack on Iran nuclear facilities
Lagging upstream investment
60
Downward price risk
Slower than expected GDP growth to 2015
Iraq supply wildcard
OPEC production restraint eases too much too soon
40
20
0
2000
2001
2002
2003
2004
2005
Source: History - Thomson Datastream, Forecast - Wood Mackenzie
2006
2007
2008
2009
2010
2011
WTI Real
2012
2013
2014
2015
WTI Nominal
Source: History – Thomson Datastream; Forecast - Wood Mackenzie
21
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Despite Increasing Prices, Gas Remains Cheap—Oil and Gas Remain Apart
Average price WTI:
•
2010-15: $89.46
•
2016-20: $92.21
Oil and Gas Commodity Price Forecasts
2021-30: $105.26
25.00
Plentiful exploration risk, and reservoir
performance risk in this oil outlook, in
contrast to US gas.
20.00
•
2011:
$4.60
•
2011-15:
$5.71
•
2016-20:
$5.75
•
2021-30:
$6.12
$2010/MMBtu
Preliminary Avg Henry Hub (real):
Average WTI to Henry Hub Differential
15.00
Distillate
WTI
Resid
Henry Hub
10.00
5.00
$2010/mmbtu
2010-2020
10.03
2021-2030
12.02
2030
2028
2026
2024
2022
2020
2018
2016
6.88
2014
2009
0.00
2012
2.83
2010
2000-2008
22
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The New Big Picture: Gas is Available in Any Feasible Quantity, but Not
at $4.00 ----- and That’s IF the Industry is Allowed to Get To IT
Through 2012…Sluggishness and Gas as a Coal-derived Fuel
• With sluggish economic recovery and supply strength; coal displacement continues to influence
the gas market
Late 2012 – 2016…Growth Potential
• With an increasing call on production as demand growth resumes, there is potential for growing
pains as the market transitions from retrenchment to expansion; prices rise to the $5.75 - $7
range.
2016 and Beyond – a Collision Course?
• Demand pressure appears likely, with the pace of growth shaped by coal retirements, potential
carbon legislation and a discount to oil.
• If the upstream is allowed to invest at pace, pricing remains moderate: $6.50 - $7.00
• BUT – if not, we could be needing that LNG, and that Alaska Pipeline after all!
23
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