2010 04-us gas-boston-consulting-gabaldon

A return to "normalcy" in US gas?

April 15, 2010

ENERGY &ENVIRONMENTENERGY &ENVIRONMENT

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

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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(2003-2005)

Expectations(2003-2005)

High growth of US gas demand until 2020

Limited growth of U gas production

Plenty of available new LNG

Attractive US net-back prices for LNG producers (moderate oil price)

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

+

+

+

Today / Tomorrow2008-2012

Today / Tomorrow2008-2012

Negative to moderate growth of gas demand

Still plenty of U reserves, yet production to stabilize/ decline to reflect lower investment and price signal

Oversupply of LNG due to GLOBAL low demand

Some decoupling in Europe, reducing netback

+

+

+

????

What happened(2006 -2008)

What happened(2006 -2008)

Moderate growth of gas demand

Plenty of U gas reserves, production costs decreasing

Tight supply situation in gas exporting countries

High oil prices, making European market very attractive

LNG imports at ~ 10 bcm

+

+

+


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

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

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

0

5

10

15

20

25

30

35

Gas price($/mmBtu)

Year

Unconventional gas(Bcf/day)

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

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

0

20

40

60

80

100

120

Gas price($/mmBtu)

Oil price($/bbl)

Source: Waterborne LNG; EIA;UBS; BCG analysis

YearAsia Weighted Avg. contract

Oil price

Asia Weighted Avg. spotEuropean contractNorth American spot (Nymex)

High US prices drove significant development of unconventional gas resources...

High US prices drove significant development of unconventional gas resources...

...while high oil prices kept globalLNG prices even higher

...while high oil prices kept globalLNG prices even higher

Unconventional gasproduction

Gas price

+15bcf/d in 10 years


Shale gas is the dominant type of unconventional gas

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

• The only real growth relay for gas in the US• Expected to reprensent 1/3 of US/Ca. prod. by 2030

– ~9 Tcf per year by 2025 (~2 Tcf today)• Some emerging plays in Canada too

– too early to asset full potential

• Historical plays (SG Tier 1) most likely "gone"...– Limited to no entry logic for IOCs

• ... but entering Shale Gas still possible– SG Tier 2 still offer upside potential– SG Tier 3 has embedded "speculative" logic

0

10,000

20,000

30,000

Production [kboepd]

2008 2025

Tight Gas Coalbed Methane Conventional GasShale Gas

+11%

-1%

-1%

-1%

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

0

5

10

15

20

25

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

Production [bcfd]

Divisions represent individual basins

Source: Rystad UCube; BCG analysis

Tier 1 refer to "initial" SG development wave in basin that are already significantly developed (e.g. Barnett Shales)

Tier 2 refer to new SG development on-going e.g. Marcellus

Tier 3 refer to the next likely wave of SG development, in places where only land grabbing has happended

Shale gas Tier 18

Shale gas Tier 29

Shale gas Tier 310

Additional Tier 3 potential?

Shale gas Tier 18

Shale gas Tier 29

Shale gas Tier 310

(U.S. only)

(U.S. and Canada)

(U.S. and Canada)


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

9

0

2

4

6

20 04

20 09

20 25

Production [bcfd]

Barnett Shale – Producing

46% 14%

0

1

2

3

20 04

20 09

20 25

Production [bcfd]

Fayetteville Shale – Producing

17%

9%

0

2

4

6

2004 2009 2025

Production [bcfd]

7%

22%

0

2

4

6

20 04

20 09

20 25

Production [bcfd]

13%

22%

Haynesville Shale – Developing Marcellus Shale – Developing

1. Shale gas production doesn't include NGL or any conventional gasSource: Rystad UCube; BCG analysis

Shale gas Tier 18 Shale gas Tier 18

Shale gas Tier 29 Shale gas Tier 29


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

Break even pointBreak even point IRRIRR NPVNPV

3.2

4.75.1 5.1

6.1 6.3

0

2

4

6

8

Marcell

usHayn

esville

Fayett

eville

Barnett

Core

Woodfor

d

Barnett

Non

core

Breakeven economics ($MMBtu1 )

0 20 40 60 80 100

Marcellus

Haynesville

Barnett Core

Fayettevile

Woodford

BarnettNoncore

Pretax IRRs at 8–10/MMBtu NYMEX gas

(%)

2.01.7

1.3 1.2

2.9

2.0

Marcell

us

Hyane

sville

Fayett

eville

Barnett

Core

Woo

dford

Barnett

Non

-Core

NPV/Mcfe for a sample well2

86% 47% 69% 64% 33% 31%

1. For a 10% pretax IRR 2. Pretax valuesSource: Deutche Bank


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

Source: EIA annual energy outlook (2009 and 2008)

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 20260

100

150

200

50

2008

2005

bcm/yr

2009 updated

-90 bcm

-30 bcm

EIA net LNG imports projections – Reference scenarios


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

North AmericaNorth America North-West EuropeNorth-West Europe AsiaAsia

353 337

4238

375395

1st half 2008 1st half 2009

Canada

USA

-5%

-10%

-4%

in bcm in bcm in bcm

53 48

4540

46

25

24

23

22

16

14

40

208

1st half 2009

189

1st half 2008

Other1

NL

FR

IT

GER

UK

-9%

-3%

-11% 51 47

20

17

1st half 2008 1st half 2009

64

S.Korea

Japan

-10%71

-8%

-3%

-13%

-10%

-10%

1. BE, LX, CH, ATSource: 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

-8%


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

Origin of gasOrigin of gas Essential changesEssential changes

93 85

4647

43

25

18

1712

8208

1st half 2008

4189

1st half 2009

Net storageLNG

Domestic production

(UK, NL, GER, IT)

Norway

Russia

North Africa-1

-8

-

-18

+4

in bcm Reduction of domestic production by ~8 bcm• NL -6%; UK -12%; DE -5%

Significant reduction of imports from Russia by ~17 bcm

• Reduction of expensive supply contracts• Effect of crisis in Ukraine ~2-3 bcm

Norway slightly increased production

Additional LNG imports of ~4 bcm• Via Zeebrugge and UK/Interconnector• LNG oversupply with low prices

Net withdrawal from storage facilities of ~4 bcm

• 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: 2008US LNG demand: 2008

1. Range includes discrepancies between estimates for 2008 and other effects like variations in inventory and lossesSource: Cedigaz: IEA: BCG analysis

33

10

0

10

20

30

40

Pre-financial

crisisforecast

Local gasproduction

Netpipelineimports

Demand Real

(bcma)

Real growth of 5.5–5.9 (-1% conventional and +12% non-

conventional) versus previous forecast

Real growth -13%

Real growth +0.5–0.7% versus +3% pre-financial crisis forecast

1

Financial crisisFinancial crisis

Reduced economic growth has significantly hindered the development of LNG demand

• Power and gas consumption growth highly correlated with economic growth

• LNG imports take the first impact due to their flexibility and position in supply curve

Unconventional productionUnconventional production

Unconventional production is direct competitor of LNG in US• Covering gap derived from drop in imports from Canada and

decline in conventional production

During 2008, unconventional gas supply in the US rose +12%

• Full year impact of developments launched in high gas price environment

However, there may be a near term role for LNG in the US


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

Fast growth in US unconventional production

in 2004-2008...

Fast growth in US unconventional production

in 2004-2008...

...followed by a sharp decrease in drilling

activity in 2009

...followed by a sharp decrease in drilling

activity in 2009

...could lead to a fall in unconventional supply if

investments are discontinued

...could lead to a fall in unconventional supply if

investments are discontinued

0

250

500

750

1,000

1,250

1,500

1,750

Unconventional rigs1

Total gas rigs

# gas rigs in US

292

259231226

212

0

100

200

300

400

2004 2005 2006 2007 2008

+8%

(bcma)

-55%

-40%

1. Includes rigs in Barnett, Fayetteville, Greater Green River, Haynesville, Marcellus, Piceance, Williston, and WoodfordSource: EIA; Land Rig Newsletter; Baker&Hughes

2004 2005 2006 2007 2008 2009

Marcellus Shale and Haynesville Shale rig count even growing in '09 vs. '08

"Without continuing investments, production rates will not be maintained due to the steep decline rates (60% within the first year) of shale gas wells." (Center for Strategic and International Studies, mar-2009)

"Unconventional wells have steep decline rates, and any decrease in drilling will quickly result in dramatically lower gas production from these plays." (American Association of Petroleum Geologists, sep-2009)


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

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 2009-2012Source: Cedigaz; BCG analysis

Unconventional productionUnconventional production

Constant investment in E&P required to keep current production rates

• Unconventional gas fields decline fast• New drilling activity is required to keep

production levels

Additional investments in transportation are needed to allow the flow of additional unconventional production into the market

• Rockies connection currently limited; Rockies Express facing challenges and with limited flow (18 bcma) vs. production potential

• Marcellus shale holding limited access to New England, where the highest prices are registered

New investment decisions in unconventionals will consider whether gas prices support

FULL COST of investment

LNGLNG

Investments in regas terminals already committed

• Current terminals hold > 100 bcma of capacity2 (vs. 10 bcma of LNG imports in 2008)

– These terminals concentrate ~$10bn of accumulated investment

• Terminals under construction hold c. 90 bcma of additional capacity

Connections of regas terminals to the networks already done or committed

LNG importers holding Use Or Pay contracts against these investments

New flows of LNG in the US will consider whether gas prices support MARGINAL COST

of investment1


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

Shale gas full costShale gas full cost LNG marginal costLNG marginal cost

0

2

4

6

8

0.8-1.9

4.5-6.0

0.8-1.9

6.3-7.4

0.8-1.9

3.5-5.0

4.3-6.9

Shale Gas-Barnett

5.3-7.9

Shale Gas-US average

7.1-9.3

Coal BedMethane1

Transportation

Lifting

$/MMBtu

0

2

4

6

8

0.10.3

0.5-3.3

0.3

1.0-2.7

0.30.3

0.8

1.0-2.7

0.7

1.6-3.3

2.3-6.8

TX

Liq.

E&P

$/MMBtu

•Own Liquef.•Own Vessel•Own E&P

•Tolling Liquef.•Own Vessel•Own E&P

•Tolling Liquef.•Chartered Vessel•3rd party E&P

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


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

Global LNGGlobal LNGUS Regas capacity3 US Regas capacity3 U gas production2U gas production2

0

100

200

300

400

bcm

2008 20110

100

200

300

400

bcm

2008 2011

-100%0

100

200

300

400

2011

bcm

2008

300

0

100

200

300

400

20112008

bcm

LNG import (EIA 2009)

Main uncertainties•China as possible alternative •Duration of window also dependent on strategic behaviors of U gas producers

New LNG

Jap, Korea

Production decrease

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 2009Source: EIA, Cedigas, BCG analysis

"Excess" LNG1"Excess" LNG1


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

• LTC with ToP and oil- indexation remainMarket

structure

Market liquidity

Price stability

Market shares

"Return to the good old world"

"Return to the good old world"

"Goodbye oil-indexation"

"Goodbye oil-indexation"

"Aggressive producers go downstream"

"Aggressive producers go downstream"

• Spot market volume increases, but remains relatively low

• High price stability• Prices bound to oil-price

• Small changes• Utilities only in competition

with each other

• Reduced LTC (with and without ToP) indexed to hub prices

• Increased spot market volume

• Reliable price indication

• High price volatility• Contracts may provide

more price flexibility

• Moderate changes• Wholesale share will shift• Increasing competition

among utilities

• Low share of LTCs• Diverse supply channels

for end-customers compete

• High spot market volume• Very reliable price

indication

• Medium price stability• Volatility depends on

player‘s specific price strategy

• Significant changes in downstream market

• Broad competition with increasing pressure

Source: BCG analysis


Current spot price (9 – 10 €/MWh)

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

SRMC in $/MMBtu

Netherlands

Norway

Russia

0 100 200 300 400

Italy Algeria

8

LNG

Denmark

UK

6

4

2

0

Gas supply North-west Europe 2008 in bcm

Germany0

5

10

15

20Cost in €/MWh

Oil-linked import price (BAFA 20€/MWh)

Demand2008

Merit orderMerit orderExpected profits under current price conditions of

delivery into North-west Europe Expected profits under current price conditions of

delivery into North-west Europe

1,5

5,17,6

5,9

7,4

9,8

Algeria

4,2

2,00,3

13,3

UK1

12,2

2,6

0,3

9,1

Norway

17,4

7,1

LNG

2,2

Russia Nether- lands

8,8

... however pressure to have a competitive position in short- and long-term

Profit with

oil-link

Profit at

spot- price

Poten- tial loss

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 linkSource: Wood Mackenzie; EU Sector Inquiry; BCG analysis

Profits/profit decline in € bn


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

Source: Chesapeake

Days versus DepthDays versus Depth Depth versus DollarsDepth versus Dollars

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

0 5 10 15 20 25 30 35Days from spud

Measured depth (m)

~40% less time

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

0 0.5 1.0 1.5 2.0 2.5Drilled and cased cost ($ mln)

Measured depth (m)

2006 2007 2008

~60% less cost

2006 2007 2008

"Halliburton expects plenty of demand for its shale technologies which are intended to help cash-strapped exploration and production companies increase efficiency and maximize the value " The Oil Daily, 20 Nov. 2008

"We believe that the most effective cost control will be achieved by the ongoing implementation of new oil field service technologies, particularly for the upstream segment. " Uralsib, 8 Dec. 2008


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

LNG regas.cap.

Pipelineimport1SWTight gasCBMOnshore Conv.

Shalegas

DW

600 700650550150 250 750450100 500 80030050 3502000 400 bcm/yr0

2

4

6Short-runmarginal

costin $/mBTU

LNG regasification

capacityDWSWTight gasCBM

PipelineimportOnshore Conv.

Shalegas

300250 600550 800150 700650 750100 450 50035050 2000 400 bcm/yr0

10

2

4

6

8

Long-run marginal cost/

Break-even price2

in $/mBTU

Note: Lower 48 states1. Pipeline imports primarily from Canada and likely to decline as Can. prod declines and demand from oil sands increase2. Price yielding 10% IRR including all costsSource: EIA AEO 2009; Wood MacKenzie; Rystad; BCG analysis

2012 possible supply curve

2009 supply curve Similar demand levels in 2009 and 2012

Break-even price of shale gas with main

influence on gas price in Atlantic


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

U gas LNG

Eur price

U gas LNG

Eur price

U gas

Eur price

• Recovery of US demand (carbon?)

• New LNG costs going down (liquefaction back to 200-300M$/Mtpa)

• Some disappointments on U Gas (volume and cost)

Back to normal, LNG pushed out

Sustained spot LNG

Interspersed supply

U gas LNG

Eur price • Very high growth of US

demand (dash for gas)• Shale unable to cope w/ demand

• Abundant LNG

New US gas boom

U gasLNG

Most probable

Why not?

Unlikely

???

• End of LNG surplus bringing prices back in the $6-8/MMBtu range

• U gas production growing back quickly after 2010/2011

• Global oversupply maintained after 2012- 2014

• European prices depressed (decoupling)

• LNG entering into the US below full costs


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

Solar TurbinesPratt & Whitney

Siemens Westinghouse(SGT6-6000G)

Siemens Westinghouse(SGT6-5000F)

Kawasaki

Mitsui Engineering

GEHitachiDresser-Rand

VericorMAN Group

Mitsubishi HeavyIndustries

OPRARolls-RoyceTurbomeca

194 223 265 271 278

143146

153 149 143

52

51 53 55122126

131 135 128

282286

284338 332

23

33

345

6

45454548

0

200

400

600

800

1,000

1,200

36

12

1,122

36

28

2012

15 0

4 32

15 1

4 3136

12

30

16

992

12 1

2932

40

12

29

2009

941

12 1

21

12

40

10

28

29

20112010

1,062

2013

1,109

0

3127

Source: Forecast International, Gas Turbine Forecast

High confidence Good confidence

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


But as before, environmental policy could change everything

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

Federal RES alone would reduce gas demand by 8% Federal RES alone would

reduce gas demand by 8%

Carbon legislation w/o RES would increase gas demand

up to 16%

Carbon legislation w/o RES would increase gas demand

up to 16%

Combination of RES and CO2 would increase demand

at high CO2 prices

Combination of RES and CO2 would increase demand

at high CO2 prices

2008 BAU

62

$12/T CO2,

20% RPS

67

$30/T CO2, 20% RPS

68

$50/T CO2,

20% RPS

Gas demand (Bcf/d)90

80

70

0

+4

64

2008 BAU

69

$12/T CO2

$30/T CO2

75

$50/T CO2

+10

0

70

80

90

Gas demand (Bcf/d)

74

6464

2008 BAU

59

20% RPS with 1/4 EE

-5

0

60

70

80

90

Gas demand (Bcf/d)

2020 20202020


... 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

Education

gas price104

us natural gas

high gas prices

shale gas production

gas oversupply of lng

global gas market

unconventional gas supplylng

shale gas basin