2010 04-us gas-boston-consulting-gabaldon

ENERGY &
ENVIRONMENT

A return to "normalcy" in US gas?

April 15, 2010

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eei - gas dynamics -15Apr10 - WAS-v1.ppt 1

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US natural gas – a return to normalcy?
At least for now, natural gas – rather than climate change – has turned out to be the real wild
card in the US electricity market

Gas is one of the dominant drivers of electricity prices, and thus its price is critical for
shaping future generation choices and profitability of existing units

Following the merchant gas building boom (on the heels of sustained low gas prices),
concerns grew about domestic gas shortages
• Apparent linkage of natural gas to oil prices
• Policy focused on enabling increased access to LNG...
• ... despite safety and quality concerns i, and plus exposure to a foreign gas cartel and oil-
indexed gas prices
• CCGTs replaced by nuclear and (clean) coal as preferred source of future base load

What does the recovery of extensive and economically recoverable unconventional
resources mean for LNG

Is natural gas once again the preferred choice for new generation?


In 2005, the US was about to be linked to a global gas market,
but instead it "discovered" unconventional
Expectations What happened Today / Tomorrow
(2003-2005) (2006 -2008) 2008-2012

High growth of US gas Moderate growth of gas Negative to moderate growth
demand until 2020 demand of gas demand

+ + +
Limited growth of U gas Plenty of U gas reserves, Still plenty of U reserves, yet
production production costs decreasing production to stabilize/ decline
to reflect lower investment and
price signal
+ + +
Plenty of available new LNG Tight supply situation in gas Oversupply of LNG due to
exporting countries GLOBAL low demand
+ + +
Attractive US net-back prices High oil prices, making Some decoupling in Europe,
for LNG producers (moderate European market very reducing netback
oil price) attractive

LNG imports expected to reach
LNG imports at ~ 10 bcm ????
50bcm n 2008, 160 bcm in 2020 (EIA)


High gas prices drove growth in unconventional gas supply
LNG flowed to even higher priced markets due to oil price indexed contracts

High US prices drove significant development of ...while high oil prices kept global
unconventional gas resources... LNG prices even higher

Gas price Unconventional gas Gas price Oil price
($/mmBtu) (Bcf/day) ($/mmBtu) ($/bbl)
16.0 35 16.0 120

14.0 Unconventional gas 14.0
30
production 100
12.0 12.0
25
+15bcf/d 80
10.0 10.0
20
in 10 years
8.0 8.0 60
15
6.0 6.0
40
Gas price 10
4.0 4.0

5 20
2.0 2.0

0.0 0 0.0 0
97
98
99
00
01
02
03
04
05
06
07
08
09

97
98
99
00
01
02
03
04
05
06
07
08
09
Year Year
Asia Weighted Avg. contract
Asia Weighted Avg. spot
European contract
North American spot (Nymex)
Oil price
Source: Waterborne LNG; EIA;UBS; BCG analysis

Shale gas is the dominant type of unconventional gas

Fast growing production... ...with most potential still to come

Production [kboepd]
30,000

+11%

20,000
-1%

-1%

10,000
-1%

0
2008 2025

Shale Gas Tight Gas Coalbed Methane Conventional Gas

• The only real growth relay for gas in the US • Historical plays (SG Tier 1) most likely "gone"...
• Expected to reprensent 1/3 of US/Ca. prod. by 2030 – Limited to no entry logic for IOCs
– ~9 Tcf per year by 2025 (~2 Tcf today) • ... but entering Shale Gas still possible
• Some emerging plays in Canada too – SG Tier 2 still offer upside potential
– too early to asset full potential – SG Tier 3 has embedded "speculative" logic
Source: Rystad UCube; BCG analysis

Many contributors to shale gas production...
Forecasted production available for each company, in each shale gas basin in US and Canada

Additional
Production [bcfd] 10 Shale gas Tier 3
Tier 3 potential?
25 (U.S. and Canada)

20 Divisions represent
individual basins

9 Shale gas Tier 2
15
(U.S. and Canada)

10

5
8 Shale gas Tier 1
(U.S. only)

0
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

8 Shale gas Tier 1 Tier 1 refer to "initial" SG development wave in basin that are already significantly developed (e.g. Barnett Shales)
9 Shale gas Tier 2 Tier 2 refer to new SG development on-going e.g. Marcellus
10 Shale gas Tier 3 Tier 3 refer to the next likely wave of SG development, in places where only land grabbing has happended

Source: Rystad UCube; BCG analysis

...though four basins dominate
85% share today falling to 65% in 2025

Barnett Shale – Producing Fayetteville Shale – Producing

Production [bcfd] Production [bcfd]
6 3
8 Shale gas Tier 1 8 Shale gas Tier 1

4 2

2 1 9%
46% 14%
17%

0 0
20 20 20 20 20 20
04 09 25 04 09 25

Haynesville Shale – Developing Marcellus Shale – Developing

Production [bcfd] Production [bcfd]
6 9 Shale gas Tier 2 6 9 Shale gas Tier 2

4 4

22% 22%
2 2
7%
13%
0 0
20 20 20 2004 2009 2025
04 09 25
1. Shale gas production doesn't include NGL or any conventional gas
9 Source: Rystad UCube; BCG analysis

Shale gas economics vary significantly between basins...
Marcellus with best estimated economics

Break even point IRR NPV
Breakeven economics ($MMBtu1 ) Pretax IRRs at 8–10/MMBtu NYMEX gas NPV/Mcfe for a sample well2

8 86% 47% 69% 64% 33% 31%
Marcellus

2.9
6.3
6.1 Haynesville
6
5.1 5.1
4.7 Barnett Core 2.0 2.0
1.7
4
3.2 Fayettevile
1.3
1.2

2 Woodford

Barnett
Noncore
0
0 20 40 60 80 100

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l lu

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tC

(%)

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ye
ye

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Ha

Fa
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Ba
H
Ba

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Ba

Ba
1. For a 10% pretax IRR 2. Pretax values
Source: Deutche Bank

While outlook for unconventional gas has risen, US LNG
forecasts have strongly declined

EIA net LNG imports projections – Reference scenarios

bcm/yr
200

2005

150

-90 bcm

100

2008

50 -30 bcm
2009 updated

0
1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026

Source: EIA annual energy outlook (2009 and 2008)

Gas demand has dropped in all regions worldwide, with LNG
absorbing much of the impact

North America North-West Europe Asia
in bcm in bcm in bcm

-5% -9% -10%
395 208 71
375 16
42 -8% 189 64
-10% 38 Canada 23 14 Other1
-3% 20
-10%
22 NL 17 S.Korea
25
-3% 24 FR
46
-13% 40 IT
353 -4% 337 USA
45 -11% -8%
40 51
GER 47 Japan

53 -10% 48 UK

1st half 2008 1st half 2009 1st half 2008 1st half 2009 1st half 2008 1st half 2009

1. BE, LX, CH, AT
Source: Snam Rete Gas; GRT Gaz; GTS; BAFA/BMWi/BDEW; DECC; E-Control; BP Statistical Review of World Energy; Natural Resources Canada; IEA Natural Gas Monthly Survey, BCG Analysis

In Europe, Russia and domestic production compensated for
drop in demand

Origin of gas Essential changes
in bcm Reduction of domestic production by ~8 bcm
Net storage 208 • NL -6%; UK -12%; DE -5%
LNG 8
189
18 +4
North Africa 4 Significant reduction of imports from Russia
12
-1
17 by ~17 bcm
Russia 43
-18 • Reduction of expensive supply contracts
25
• Effect of crisis in Ukraine ~2-3 bcm
Norway 46 - 47 Norway slightly increased production

Additional LNG imports of ~4 bcm
Domestic • Via Zeebrugge and UK/Interconnector
production 93 -8
(UK, NL, GER, IT)
85 • LNG oversupply with low prices

Net withdrawal from storage facilities of
~4 bcm
1st half 2008 1st half 2009
• Due to crisis in Ukraine and cold winter

Source: Snam Rete Gas; GRT Gaz; GTS; BAFA/BMWi/BDEW; DECC; E-Control; BP Statistical Review of World Energy; BCG analysis

In the US, LNG was hit hard by financial crisis and U gas
development

US LNG demand: 2008 Financial crisis

Real growth of 5.5–5.9 (-1% Reduced economic growth has significantly hindered the
conventional and +12% non- development of LNG demand
conventional) versus previous • Power and gas consumption growth highly correlated with
(bcma) forecast economic growth
40 • LNG imports take the first impact due to their flexibility and
position in supply curve
33
Real growth -13%
30

Unconventional production
20
Unconventional production is direct competitor of LNG in US
10 • Covering gap derived from drop in imports from Canada and
10 decline in conventional production
Real growth +0.5–0.7% versus
During 2008, unconventional gas supply in the
+3% pre-financial crisis forecast
US rose +12%
0 • Full year impact of developments launched in high gas price
1
Pre- Local gas Net Demand Real environment
financial production pipeline
crisis imports
forecast

However, there may be a near term role for LNG in the US
1. Range includes discrepancies between estimates for 2008 and other effects like variations in inventory and losses
Source: Cedigaz: IEA: BCG analysis

Fast decline of unconventional production fields allows a fast
adjustment of market balance

Fast growth in US ...followed by a sharp ...could lead to a fall in
unconventional production decrease in drilling unconventional supply if
in 2004-2008... activity in 2009 investments are discontinued

(bcma) # gas rigs in US "Without continuing investments,
400 1,750 production rates will not be
maintained due to the steep
1,500 decline rates (60% within the first
292 year) of shale gas wells." (Center
300 +8% -55%
259
1,250 for Strategic and International
231 Studies, mar-2009)
226
212 1,000
200
750 "Unconventional wells have steep
decline rates, and any decrease
500 in drilling will quickly result in
100
dramatically lower gas production
250
-40% from these plays." (American
Association of Petroleum
0 0
Geologists, sep-2009)
2004 2005 2006 2007 2008 2004 2005 2006 2007 2008 2009

Marcellus Shale and
Total gas rigs
Haynesville Shale rig count
Unconventional rigs1 even growing in '09 vs. '08
1. Includes rigs in Barnett, Fayetteville, Greater Green River, Haynesville, Marcellus, Piceance, Williston, and Woodford
Source: EIA; Land Rig Newsletter; Baker&Hughes

In this environment, will LNG may be competitive with
unconventionals...

Unconventional production LNG
Constant investment in E&P required to keep Investments in regas terminals already
current production rates committed
• Unconventional gas fields decline fast • Current terminals hold > 100 bcma of
• New drilling activity is required to keep capacity2 (vs. 10 bcma of LNG imports in
production levels 2008)
– These terminals concentrate ~$10bn of
Additional investments in transportation are accumulated investment
needed to allow the flow of additional • Terminals under construction hold c. 90 bcma
unconventional production into the market of additional capacity
• Rockies connection currently limited; Rockies
Express facing challenges and with limited Connections of regas terminals to the
flow (18 bcma) vs. production potential networks already done or committed
• Marcellus shale holding limited access to New
England, where the highest prices are LNG importers holding Use Or Pay contracts
registered against these investments

New investment decisions in unconventionals New flows of LNG in the US will consider
will consider whether gas prices support whether gas prices support MARGINAL COST
FULL COST of investment of investment1

1. And, of course, gas prices in other markets vs. US gas prices 2. At the end of 2008 3. Assumes new capacity expected to come online in 2009-2012
Source: Cedigaz; BCG analysis

... as LNG at marginal cost (since long) competes with full
cost of unconventional gas?

Shale gas full cost LNG marginal cost
$/MMBtu $/MMBtu
8 7.1-9.3 8
0.8-1.9 Transportation
2.3-6.8
5.3-7.9
0.8 TX
6 0.8-1.9 6
4.3-6.9
0.8-1.9
1.0-2.7 Liq.
4 4
6.3-7.4 Lifting 1.6-3.3
0.3
4.5-6.0
3.5-5.0
2 2
1.0-2.7 0.5-3.3 E&P
0.7
0.3
0.1
0 0 0.3 0.3
Shale Gas Shale Gas Coal Bed •Own Liquef. •Tolling Liquef. •Tolling Liquef.
-Barnett -US average Methane1 •Own Vessel •Own Vessel •Chartered Vessel
•Own E&P •Own E&P •3rd party E&P

1. Assumes reference values for WIlliams Fork/S.Piceance and Wasatch basins
Source: Cedigaz; BCG analysis

This may create a near term opening for LNG in the US
Significant room in the US -2011 situation

US Regas
Global LNG "Excess" LNG1 capacity3 U gas production2
bcm bcm bcm bcm
400 400 400 400

300
300 New 300 300 300
LNG

200 200 200 200

Jap, Korea

100 100 100 100

LNG import Production
(EIA 2009) decrease
-100%
0 0 0 0
2008 2011 2008 2011 2008 2011 2008 2011

Main uncertainties
•China as possible alternative
•Duration of window also dependent on strategic behaviors of U gas producers
1. U and L scenarios; 2. Low scenario assumed low rig count until 2011, high scenario until end 2010. 3. Average capacity (6600hrs) - 2011 figures accounts only for regas in operation or
under construction as of Oct 2009
Source: EIA, Cedigas, BCG analysis

Longer term evolution of LNG price driven in part by players'
conduct

"Return to "Goodbye "Aggressive producers
the good old world" oil-indexation" go downstream"

• LTC with ToP and oil- • Reduced LTC (with and • Low share of LTCs
Market indexation remain without ToP) indexed to • Diverse supply channels
structure hub prices for end-customers
compete

• Spot market volume • Increased spot market • High spot market volume
Market increases, but remains volume • Very reliable price
liquidity relatively low • Reliable price indication indication

• High price stability • High price volatility • Medium price stability
Price • Prices bound to oil-price • Contracts may provide • Volatility depends on
stability more price flexibility player‘s specific price
strategy

• Small changes • Moderate changes • Significant changes in
Market • Utilities only in competition • Wholesale share will shift downstream market
shares with each other • Increasing competition • Broad competition with
among utilities increasing pressure

Source: BCG analysis

Producer with significant interest in oil-price indexing ...
Link to OPEC-set oil prices has created tremendous value for producers

Expected profits under current price conditions of
Merit order delivery into North-west Europe
SRMC in $/MMBtu Cost in €/MWh Profits/profit decline in € bn
17,4
8 20
Oil-linked import price (BAFA 20€/MWh)

13,3
6 Demand 15 12,2 9,8
2008
Profit Poten-
9,1 7,4 with tial
4 10 7,1 oil-link loss
Current spot price LNG
(9 – 10 €/MWh)

Italy Algeria
2 5 8,8 4,2
Denmark Russia 7,6 Profit
2,2 2,6 5,1 5,9 at
Netherlands
spot-
Norway UK 2,0 price
1,5
0 0 0,3 0,3
Germany
0 100 200 300 400 Russia LNG Algeria UK1 Norway Nether-
Gas supply North-west Europe 2008 in bcm lands

... however pressure to have a competitive position in short- and long-term
1. In a balanced market continental oil linked prices influence gas to gas pricing in UK -> UK has the same interest in keeping the oil-gas link
Source: Wood Mackenzie; EU Sector Inquiry; BCG analysis

At the same time, U gas production efficiency is improving
Example: Chesapeake Fayetteville Shale operations

Days versus Depth Depth versus Dollars

Measured depth (m) Measured depth (m)
0 0
2006 2007 2008 2006 2007 2008
1,000 1,000

2,000 2,000

3,000 3,000

4,000 4,000

5,000 5,000 ~60% less cost
6,000 6,000

7,000 7,000
~40% less time
8,000 8,000

9,000 9,000

0 5 10 15 20 25 30 35 0 0.5 1.0 1.5 2.0 2.5
Days from spud Drilled and cased cost ($ mln)

"Halliburton expects plenty of demand for its shale technologies which are "We believe that the most effective cost control will be achieved by the
intended to help cash-strapped exploration and production companies ongoing implementation of new oil field service technologies, particularly
increase efficiency and maximize the value " The Oil Daily, 20 Nov. 2008 for the upstream segment. " Uralsib, 8 Dec. 2008

Source: Chesapeake

What about the longer term prospects?
When oversupply cleared, prices back to $7-9 inducing investments in unconventionals again

2009 supply curve Similar demand levels in
Short-run 6 2009 and 2012
marginal
cost
in $/mBTU 4

2 LNG
Shale Pipeline regas.
Onshore Conv. CBM Tight gas SW DW
gas import1 cap.
0
0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 bcm/yr

Long-run 10
2012 possible supply curve
marginal cost/
Break-even 8
price2
in $/mBTU 6
LNG
4 regasification
Shale capacity
2 Pipeline Tight gas SW DW gas
Onshore Conv. import CBM
0
0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 bcm/yr

Break-even price of
Note: Lower 48 states shale gas with main
1. Pipeline imports primarily from Canada and likely to decline as Can. prod declines and demand from oil sands increase influence on
2. Price yielding 10% IRR including all costs
Source: EIA AEO 2009; Wood MacKenzie; Rystad; BCG analysis gas price in Atlantic

Several scenarios for 2012+ ....
Not all with same probability – need to be prepared for all ?

Most probable Unlikely
Back to normal, LNG pushed out Interspersed supply

• Recovery of US demand
Eur • End of LNG surplus Eur (carbon?)
price bringing prices back in the price • New LNG costs going
$6-8/MMBtu range down (liquefaction back to
LNG • U gas production growing U gas LNG 200-300M$/Mtpa)
U gas U gas
back quickly after • Some disappointments on
2010/2011 U Gas (volume and cost)

Why not? ???
Sustained spot LNG New US gas boom

• Global oversupply
Eur maintained after 2012-
Eur
price 2014 • Very high growth of US
LNG price
U gas • European prices LNG demand (dash for gas)
U gas
depressed (decoupling) • Shale unable to
• LNG entering into the US cope w/ demand
below full costs • Abundant LNG


To many gas increasingly looks prudent again
Turbine supplier order books returning to pre-crisis levels

Expected production volumes in units by supplier (2009-2013)

1,200
1,122 1,109 Pratt & Whitney
1,062 29 28 Solar Turbines
992 30
1,000 Siemens Westinghouse
941 29 (SGT6-5000F)
28 338 332
284 Siemens Westinghouse
(SGT6-6000G)
286
800
282 Turbomeca
12 12 12
Rolls-Royce
12 131 135 128
10 OPRA
600 126 55
122 51 53 Mitsui Engineering
48 45 45 45
36 36 36 Mitsubishi Heavy
52 40 3
31 4 4 32 3 31 Industries
40 32 5
4 2
400 27 29 MAN Group
21 6 3 153 149 143
3 146 Vericor
143 1 15 0 16 0
15 Kawasaki
12 1
200 12 1
Dresser-Rand
265 271 278
194 223 Hitachi
GE
0
2009 2010 2011 2012 2013

High confidence Good confidence

Source: Forecast International, Gas Turbine Forecast

But as before, environmental policy could change everything

Carbon legislation w/o RES Combination of RES and
Federal RES alone would would increase gas demand CO2 would increase demand
reduce gas demand by 8% up to 16% at high CO2 prices

Gas demand (Bcf/d) Gas demand (Bcf/d) Gas demand (Bcf/d)
90 90 90
2020 2020 2020

80 +10 80
80

75 +4
74
-5
70 70
70 68
69 67
64 64
64 62
60 59

0 0 0
2008 BAU 20% RPS with 1/4 2008 $12/T $30/T $50/T 2008 $12/T $30/T $50/T
EE BAU CO2 CO2 CO2 BAU CO2, CO2, CO2,
20% RPS 20% 20% RPS
RPS

1. Based on the equilibrium case, and power sector wide optimization
Source: EIA, BCG analysis

... and key uncertainties
How will Obama's energy policy (energy efficiency, power generation mix, RPS, CO2) impact US natural gas demand?

What is the future cost structure of unconventional plays? Will unconventionals experience further technological
revolutions?

What US markets could unconventional production be serving in the future, given transportation constraints (and,
therefore, what prices will these projects be capturing)?
• Which pipeline projects will succeed and how much will they cost?
• Is there a possibility to monetize unconventional reserves through liquefaction projects (ie: Kitimat)?

What is the real potential of unconventional production in the US?

Are Canadian imports going to be available and competitive?
• Development of NG production in Canada vs. Tar Sands and domestic demand
• Competitiveness of new developments (ie: Horn River) vs. transportation costs to NA (ie: Transcanada)

How attractive is the US market price expected to be vs. other accessible markets (ie: NW Europe, Far East)?

What can US LNG operators that hold regas assets or Use or Pay contracts do to mitigate their sunk costs?
• Should companies sign long term deals that cover partially / do not cover sunk costs?
• Could new LNG plays emerge in the US, rendering additional profits for LNG operators (ie: role of storage, bi-directional
regas-liquefaction investments, etc)?


2010 04-us gas-boston-consulting-gabaldon

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