Natural Gas Watch - energianews.com · Consequently, we lower our 2011 NYMEX natural gas price...

December 1, 2010

Natural Gas Watch Commodities Research

Gas production moving higher in 2011, pushing prices lower

Another leg up in supply in 2011…

Debottlenecking in well completion services and strong oil economics will

likely provide further support to US natural gas production growth. Higher

oil prices are likely to continue to incentivize liquids-rich gas plays as well

as provide cash flow to finance gas drilling elsewhere and spur associated

gas production. In addition, an expected debottlenecking in services will

likely help reduce completion times, bringing to the market a high number

of backlogged wells that were drilled but not completed in 2010.

…calling for lower natural gas prices

We expect continued growth in production will require prices to move

lower in order to motivate increased coal-to-gas substitution by power

generators. Consequently, we lower our 2011 NYMEX natural gas price

forecast to $4/mmBtu from $5.25/mmBtu and we expect prices to decline to

$3.75 in 3Q2011. In addition, we introduce our 2012 natural gas price

forecast at $4.25/mmBtu. We believe that these price levels will motivate

coal-to-gas substitution in the order of 2.0 Bcf/d in 2011 and 1.7 Bcf/d in

2012. We expect this level of coal-to-gas substitution will allow the market

to absorb our forecast US natural gas production growth of 1.4 Bcf/d and

0.9 Bcf/d, respectively, in 2011 and 2012, without breaching storage

capacity.

Global natural gas markets likely to recover sooner, remaining disconnected from the US in the near to medium term

While LNG demand growth in 2010 was partly driven by weather events

across the globe, we believe that increased demand from non-OECD LNG

buyers will contribute to an elimination of the supply glut in global LNG

markets in the next couple of years. This will likely keep international

markets disconnected from the oversupplied US market, driving

international gas prices up closer to oil-indexed natural gas prices by the

end of 2012.

Samantha Dart

+44(20)7552-9350 [email protected] Goldman Sachs International

David Greely

(212) 902-2850 [email protected] Goldman Sachs & Co.

Jeffrey Currie


Johan Spetz


The Goldman Sachs Group, Inc. does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. For important disclosures, see the text preceding the disclosures or go to www.gs.com/research/hedge.html.

The Goldman Sachs Group, Inc. Goldman Sachs Global Economics, Commodities and Strategy Research

December 1, 2010

Goldman Sachs Global Economics, Commodities and Strategy Research 2

Hedging and trading recommendations

Hedging recommendations

Consumers: We see limited value in the current forward curve for US consumers, as we

expect oversupply to continue to be a key feature of the natural gas market next year and

for prices to remain subdued around $4.00/mmBtu through 2012. Ultimately, the market

remains vulnerable to further upside surprises to production, as most offsetting shifts on

the demand side have played out. In the UK, we expect spot prices to retreat in 2011, but to

recover again in 2012 as the global LNG market becomes more balanced.

Producers: We believe there are still opportunities for US producers to hedge 2011 and

2012 gas, as we expect prices to decline further before bottoming in 3Q2011. We also see

good hedging opportunities for producers exposed to the European spot markets given the

recent price strength, which we think will subside going into 2011, but return in 2012.

Trading recommendations

We do not have natural gas trading recommendations at this time.

Current trading recommendations

Source: Goldman Sachs Global ECS Research.

Long Soybeans

Buy November 2011 COBT Soybean November 18, 2010 - Agriculture Update $11.60/bu $11.62/bu $0.02/bu

Long European Gasoil

Buy January 2011 European ICE Gasoil November 10, 2010 - Energy Weekly $747.25/mt $734.50/mt ($12.75/mt)

Short Aluminum

Sell February 2011 Aluminum November 5, 2010 - Metals Weekly $2,462/mt $2,273/mt $189/mt

Long Gold

Buy December 2011 COMEX Gold October 11, 2010 - Precious Metals $1,364.2/toz $1,398.1/toz $33.9/toz

Long Corn

Buy March 2011 CBOT Corn October 8, 2010 - Agriculture Update $5.38/bu ² $5.44/bu $0.07/bu

Long Copper

Buy December 2011 Copper October 4, 2010 - Metals Watch $8,024/mt $8,220/mt $197/mt

Long Platinum

Buy January 2011 NYMEX Platinum July 15, 2009 - Commodity Watch $1,611.1/toz $1,666.4/toz $492.3/toz

¹As of close on November 30, 2010. Inclusive of all previous rolling profits/losses.

²With market limit up on trade entry, initial value proxied with closing level on October 8, 2010.

Current profit/(loss)1

Rolled on September 16, 2010 from a Buy October 2010

NYMEX Platinum for a $437.0/toz gain

Current trades First recommended Initial value Current Value

December 1, 2010


Price actions, volatilities and forecasts

units 30 Nov Change Implied2 Change Realized2 Change 2Q 09 3Q 09 4Q 09 1Q 10 2Q 10 3Q 10 3m 6m 12m

Energy

2.68

2.77

0.16

0.07

0.14

7.53

Industrial Metals4

-69

160

60

-311

Precious Metals

27

3.2

Agriculture

-67

17

-52

-8

-3

-25

-1.6

4.3

2.8

1 Monthly change is difference of close on last business day and close a month ago.2 Monthly volatility change is difference of average volatility over the past month and that of the prior month (3-mo ATM implied volatility, 1-mo realized volatility).3 Price forecasts refer to prompt contract price forecasts in 3-, 6-, and 12-months time.4 Based on LME three month prices.

2.63 2.602.11 2.171.86 1.94 2.00 2.27-0.73 26.6 -2.9 1.71 RBOB Gasoline $/gal 2.27 32.1

103.50 Brent Crude Oil $/bbl 85.92 30.7 -0.68 24.4 -3.0 59.90 68.87 87.50 98.50

76.13 78.88

75.54 77.37 79.41 76.96

Historical Prices

59.79 68.24-0.6 105.0078.05 76.21 89.00 100.00

Volatilities (%) and monthly changes2Prices and monthly changes1

WTI Crude Oil $/bbl

Price Forecasts3

84.11 31.2 -0.54 27.6

-0.02 28.0 0.8 1.51

4.00 4.004.23 4.25

1.73 1.94 2.01 2.07 2.65 2.75

NYMEX Nat. Gas $/mmBtu 4.18 41.8

2.01 2.41 USGC Heating Oil $/gal 2.27 30.5

4.99 4.353.06 44.4 -28.2 3.81

-3.89 36.3 20.7 27.57

3.44 4.93

2200 22002110 2125

23.48 31.83 33.35 37.48 36.30 40.50

LME Aluminum $/mt 2275 28.1

42.68 41.90 UK NBP Nat. Gas p/th 55.14 38.5

2199 21220.10 31.3 8.0 1530

-0.51 32.7 11.5 4708

1836 2037

19500 1950021271 19500

5856 6677 7274 7042 8800 11000

LME Nickel $/mt 23050 37.4

7278 8800 LME Copper $/mt 8360 31.2

20163 22431-2.07 44.0 17.8 13147

0.28 52.2 20.8 1509

17576 17593

1565 16901228 1480

1780 2241 2307 2052 2400 3100

London Gold $/troy oz 1385 20.6

2043 2300 LME Zinc $/mt 2112 38.1

1110 11971.03 21.0 3.6 923

6.02 43.9 7.9 13.8

962 1099

700 700653 700

14.7 17.6 16.9 18.3 26.1 28.2

CBOT Wheat cent/bu 650 36.6

19.0 24.7 London Silver $/troy oz 27.1 38.7

496 4671.41 36.8 -3.4 564

0.84 38.6 7.2 1128

485 522

585 585422 585

1049 1002 955 957 1400 1400

CBOT Corn cent/bu 530 37.0

1035 1400 CBOT Soybean cent/bu 1243 26.8

370 3551.46 38.4 -7.8 406

n/a 56.1 9.5 54

327 386

140 140174 180

60 71 76 81 125 125

NYBOT Coffee cent/lb 201 n/a

87 125 NYBOT Cotton cent/lb 117 n/a

134 140n/a 41.7 3.8 124

n/a 29.5 5.4 2499

125 139

16.0 16.020.2 20.0

2867 3259 3070 2987 2400 2400

NYBOT Sugar cent/lb 27.6 43.2

2863 2700 NYBOT Cocoa $/mt 2772 n/a

24.4 15.54.60 73.7 20.8 14.7

n/a 11.0 -3.3 83.0

20.6 23.6

85.0 90.079.7 75.0

85.4 83.6 90.5 93.7 110.0 110.0

CME Lean Hog cent/lb 69.0 n/a

95.0 105.0 CME Live Cattle cent/lb 103.1 n/a

53.7 57.8 69.7 81.9n/a 18.2 -7.1 63.2


December 1, 2010


Gas production moving higher in 2011, pushing prices lower

The US natural gas market remains in the early stages of its recovery. The market remains

in a deep surplus, created by continuing increases in US shale gas production and a weak

US economic recovery. Typically following a recession, we would expect rising natural gas

demand to draw down the surplus as the economic recovery strengthens. In fact, our US

economics team has raised their 2011 economic outlook to 2.7% growth and introduced an

above trend growth forecast of 3.6% for the United States in 2012. This would normally

suggest a tightening of the natural gas market balance. However, we believe that the US

natural gas market will continue to face significant supply-side headwinds in 2011, which

will likely see the natural gas surplus increase in 2011, rather than decline.

Despite an apparent leveling off in production efficiency gains when looking at aggregate

US shale gas production, we believe that debottlenecking in well completion services and

the impact of high oil prices in driving gas production economics will spur significant

growth in US natural gas production in 2011. Oil economics are influencing natural gas

production in several ways:

High NGL prices make gas drilling economical in liquid-rich gas plays, even in the

face of low natural gas prices are low

Revenues from oil provide cash flow that may be used to finance gas drilling

Higher oil drilling as a result of higher oil prices will likely increase the production

of associated gas, with US oil rigs counts at their highest level since 1987

Given our forecast that WTI crude oil prices will average $100/bbl in 2011 and $110/bbl in

2012, we expect the impact of high oil prices on natural gas production will increase, not

decline in coming years.

In the face of this continued strength in supply and without a comparable offsetting rise in

US natural gas demand, we believe that US natural gas prices will have to move lower in

2011 and 2012 in order to curb natural gas production growth, and more importantly, to

incentivize further fuel substitution in the power generation sector to rebalance the market.

Specifically, we expect that gas prices will need to move low enough to generate sufficient

coal-to-gas substitution by generators to allow the gas market to avoid breaching storage

capacity in 2011 and 2012.

Consequently, we are lowering our 2011 NYMEX natural gas price forecast to $4/mmBtu

from $5.25/mmBtu, with prices expected to decline to $3.75 in 3Q2011. In addition, we are

introducing our 2012 natural gas price forecast at $4.25/mmBtu (Exhibit 1). We believe that

these price levels will motivate coal-to-gas substitution on the order of 2.0 Bcf/d and 1.7

Bcf/d in 2011 and 2012. We expect this level of coal-to-gas substitution will allow the

market to absorb our forecasted US natural gas production growth of 1.4 Bcf/d and 0.9

Bcf/d, respectively, in 2011 and 2012, without breaching storage capacity.

Still, even taking into account such supply and demand responses to prices, we expect US

natural gas inventories to reach high levels by the end of summer in both 2011 and 2012,

highlighting the fragility of the market and how price risks remains, in our view, skewed to

the downside in the face of potentially weaker-than-normal weather-related demand and

further positive production surprises. This will likely remain the case until there is a similar

structural shift in US natural gas demand. One potential source of such a structural shift

would be the expected retirement of many coal-fired plants beginning in 2014, which could

add 6 Bcf/d of new demand to the market through 2018.

December 1, 2010


In contrast to the over-supplied US natural gas market, the glut observed in global LNG

markets for the past two years off the wave of new liquefaction capacity and the loss of

demand from the global recession is likely to clear more quickly. In fact, we expect 2012 to

be a transition year in which we believe competition for LNG cargoes will become more

pronounced as rising global demand off the increased participation of non-OECD buyers in

the LNG market, begins to eliminate excess supply from the market. By the end of 2012, we

expect the competition for LNG cargoes to pull UK NBP prices up closer to oil-indexed

natural gas price levels. As a result, we are raising our 2011 UK NBP price forecast to

$7/mmBtu from $5.75/mmBtu and we introduce our 2012 NBP price forecast at

$8.50/mmBtu (Exhibit 1).

Exhibit 1: We are lowering our US and raising our UK natural gas price forecasts (although

still bearish relative to the NBP forward curve) $/mmBtu unless otherwise noted

Source: NYMEX, ICE and Goldman Sachs Global ECS Research.

18 months after the end of the US recession, the natural gas market

remains in a deep surplus

In mid-2008, the US gas market was starting to go through a period of remarkable

production growth. This supply-driven surplus in the US gas market was exacerbated by a

sharp decline in natural gas demand, and in particular in industrial use of gas, during 2008

and most of 2009, as US industrial production collapsed during the recession. And even

now, 18 months after the end of the US recession, the rebound in demand has done little to

rebalance the market. Specifically, while there has been significant sequential growth in

industrial production and a 2.1 Bcf/d growth in industrial demand (Exhibit 2), US natural

gas production has grown by 2.8 Bcf/d in the same period, keeping the market

oversupplied. Net, even after taking into account the 1 Bcf/d estimated positive impact of

weather on generation demand this year, US working gas inventories reached an all-time

high of 3843 Bcf in November.

US ($/mmBtu)

UK ($/mmBtu) UK (p/th)

Previous New Previous New Previous New

2011 5.25 4.00 5.75 7.00 35.20 39.80 4.40 8.40 53.00

2012 --- 4.25 --- 8.50 --- 45.90 5.00 8.80 55.60

1Q2011 5.00 4.25 5.50 7.00 34.10 42.60 4.20 8.80 55.00

2Q2011 5.00 4.00 5.50 6.50 33.70 37.20 4.20 8.10 50.70

3Q2011 5.25 3.75 5.75 7.00 35.10 38.70 4.30 8.00 50.70

4Q2011 5.75 4.00 6.25 7.50 38.10 40.80 4.70 8.80 55.50

1Q2012 --- 4.50 --- 8.00 --- 43.20 5.10 9.40 59.70

2Q2012 --- 4.25 --- 8.00 --- 43.20 4.80 8.30 52.60

3Q2012 --- 4.00 --- 8.50 --- 45.90 4.90 8.20 52.20

4Q2012 --- 4.25 --- 9.50 --- 51.40 5.20 9.10 57.80

*As of close on November 29, 2010.

Forward curve*

US ($/mmBtu) UK ($/mmBtu) UK (p/th)

GS

December 1, 2010


Exhibit 2: US industrial demand for natural gas is slowly recovering, in line with the

broader economic recovery US industrial production (index, left axis); US industrial demand for natural gas in Bcf/d (right

axis); US total gas consumption in Bcf/d (left axis)

Source: EIA, Haver Analytics and Goldman Sachs Global ECS Research.

In the next few years we continue to expect further increases in US industrial demand for

natural gas, albeit likely at a lower pace than in 2H2009 and 2010 (Exhibit 2). We believe

such growth will be mainly supported by the following three drivers:

US natural gas remains substantially cheaper than crude oil, which contributes to

US manufacturing competitiveness against oil-based industries in Asia;

US natural gas is also significantly cheaper than natural gas elsewhere in the

world, contributing to US competitiveness against gas-based industries in Europe ;

and

US economic growth is likely to strengthen, particularly in 2012, when our

economists expect it to accelerate, with industrial production expected up by 3.7%

year on year.

Looking further out, we see an opportunity for a substantial boost to US natural gas

demand from the expected coal plant retirements, which could add 6 Bcf/d of natural gas

demand through 2018. We expect these retirements to occur among small- to mid-sized

coal plants, which will be rendered uneconomical given stronger regulatory controls on

pollution. While we expect most of these retirements to occur between 2014 and 2018, they

will likely add an impressive boost in demand to a market that is currently oversupplied,

likely representing the structural shift that has been lacking on the demand side for the past

two years (Exhibit 3).

16.5

17.0

17.5

18.0

18.5

19.0

19.5

20.0

20.5

21.0

50

60

70

80

90

100

110

Jan-06 Aug-06 Mar-07 Oct-07 May-08 Dec-08 Jul-09 Feb-10 Sep-10 Apr-11 Nov-11 Jun-12

US IP (left axis) Total gas consumption (left axis) Industrial demand (right axis)

Realized ForecastDec 2007

December 1, 2010


Exhibit 3: US coal plant retirements Expected coal power plant capacity retirements, MW

Source: Goldman Sachs Equity Research.

Surplus will likely deepen in 2011 as oil economics continue to drive

natural gas production

While structural demand growth is limited in the near to medium term, we expect natural

gas supplies to continue to rise, in particular as oil prices remain well supported going

forward. The disconnect between oil and gas prices has spurred E&Ps to increase their

exposure to the oil complex, either via liquids-rich gas or outright oil production. The path

of least resistance for gas producers opting to pursue this strategy is to continue to target

gas, but to shift activity from dry gas plays to wet ones. This process is well underway, as

rigs already started to decline in drier gas plays like Haynesville and Barnett and to

increase in more liquids-rich gas plays like Eagle Ford and the South-West Pennsylvania

section of the Marcellus since mid-2010. The shift in rig activity has already started to result

in impressive production growth from relatively liquids-rich areas such as Eagle Ford and

Granite Wash (Exhibits 4 & 5). In these plays, the NGL component of the hydrocarbon

stream essentially subsidizes the methane component, rendering gas production

economically viable.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2010 2011 2012 2013 2014 2015 2016 2017 2018

December 1, 2010


Exhibit 4: Rigs are migrating away from dry shale gas

plays in search of liquids exposure… Rig counts

Exhibit 5: … resulting in increasing gas production in wet

shale plays like Eagle Ford and Granite Wash Wellhead gas production from horizontal gas wells, mmcf/d

Source: Land Rig Newsletter.

Source: IHS. Includes data supplied by IHS Inc.; Copyright 2010 IHS.

However, the widening oil-to-gas spread can also motivate gas producers to target oil

instead, but using the knowledge acquired when developing shale gas resources.

Horizontal drilling for oil has increased markedly this year and has already had an

important impact on the US oil supply (Exhibit 6). In the gas market, this will lead to more

associated gas coming from these new unconventional oil wells. Two prominent examples

of oil fields where unconventional technologies are being used with impressive results are

the Permian Basin and the Bakken Shale (Exhibit 7). Increasing oil revenues can also to

some extent finance the “un-economic” drilling seen this year, such as drilling to hold

leases.

Ironically, as US gas production becomes increasingly driven by oil economics, overall gas

supply becomes more independent of gas prices, which makes these dynamics key to

understanding the continued production growth through the downturn, in our view.

Exhibit 6: US oil drilling is booming, largely driven by

horizontal rigs Rig counts

Exhibit 7: “Hot” oil plays are delivering increasing

volumes of associated gas Wellhead natural gas production from oil wells, mmcf/d

Source: Baker Hughes.

Source: IHS. Includes data supplied by IHS Inc.; Copyright 2010 IHS.

20

30

40

50

60

70

80

90

100

110

120

2Q 2009 3Q 2009 4Q 2009 1Q 2010 2Q 2010 3Q 2010 4Q 2010 (QTD)

Barnett Eagle Ford Haynesville Marcellus

0

50

100

150

200

250

300

350

400

Jan-08 Jul-08 Jan-09 Jul-09 Jan-10

Eagle Ford horizontal gas wells Granite Wash horizontal gas wells

0

100

200

300

400

500

600

700

800

900

1,000

Jan-00 Jan-02 Jan-04 Jan-06 Jan-08 Jan-10

Oil rigs Horizontal rigs (oil and gas)

0

20

40

60

80

100

120

140

160

180

200

950

1,000

1,050

1,100

1,150

1,200

1,250

Jan-06 Jan-07 Jan-08 Jan-09 Jan-10

Permian Basin associated gas (lhs) Bakken Shale associated gas (rhs)

December 1, 2010


Frac stimulation debottlenecking could release an inventory of

uncompleted wells into the market in 2011

In addition to the support we expect from higher oil prices in 2011 and 2012 to US natural

gas production, we believe that a debottlenecking in services may also contribute to

production growth in 2011. Specifically, fracture stimulation markets has remained tight,

with frac fleets working 24/7 in the Bakken, Eagle Ford and Marcellus, and frac-related

delays are increasingly being cited by the major shale gas producers as the cause of delays

in well results or reductions in production guidance. However, we expect new capacity that

is coming on line over the next 6-12 months to begin to debottleneck well completions and

reduce the excess backlog of uncompleted wells. This backlog is substantial. In the

Marcellus, we believe Anadarko has the largest backlog at 100 wells (initial production of

500 MMcf/d). Consequently, the debottlenecking of completion activity with the arrival of

more frac stimulation capacity in 2011 will likely release a significant amount of new

natural gas production into the market.

The backlog on uncompleted wells may also explain in part the leveling off of production

efficiencies following the sharp rise in 2009. This is particularly the case in the Haynesville

and Marcellus gas plays. Consequently, we may see a renewed rise in efficiency in 2011 as

a result of a lower, more efficient rig count, reductions in completion delays and further

reduction in drilling days by E&Ps.

Shale gas technology continues to spread, raising production

efficiency of the US natural gas market

The way in which fewer completion delays may impact gas production by increasing the

number of producing wells rather than the initial production levels of each well is actually

in line with what we believe was the largest contributor to US natural production growth

for the most part of the past five years. Our analysis of unconventional gas production in

the United States suggests that although technological improvement matters, the key

driver behind the impressive production growth in recent years has primarily been the

increased application of the new technology in the new areas of the country in the form of

additional wells.

Geographical expansion in the form of new wells is a particularly dominant driver of

overall production growth in the early years of each shale play, and has thus been the main

driver of overall production growth so far. After the initial phase of a shale play, as the

number of wells finds a stable level, further production growth becomes increasingly

dependent on endogenous efficiency gains in drilling and extraction, as measured by

drilling times and initial production rates (IP) of incremental wells (Exhibits 8-10).

December 1, 2010


Exhibit 8: The production growth in the initial years of

the shale gas revolution was driven by new wells… Left axis: US dry natural gas production, Bcf/d; right axis:

number of horizontal gas wells producing in Barnett

Exhibit 9: .. while increasing productivity did not really

impact production until 2009 Left axis: US dry natural gas production, Bcf/d; right axis: rig-

weighted IP in mcf/d for major US shale gas plays

Source: DOE, IHS. Includes data supplied by IHS Inc.; Copyright 2010 IHS.


Exhibit 10: Since the growth in horizontal wells became more moderated and the

unconventional technology was exported to new and more productive shale plays,

production has largely been a function of aggregate initial production rates (IP) Stylized development of US shale gas production using aggregates for the Barnett, Fayetteville,

Haynesville and Woodford shale plays. Left axis: wellhead production in mmcf/d and number of

horizontal wells; right axis: rig-weighted IP in mcf/d.

Source: Goldman Sachs Global ECS Research, Land Rig Newsletter, IHS. Includes data supplied by IHS Inc.; Copyright 2010 IHS.

-2,000

0

2,000

4,000

6,000

8,000

10,000

48.0

50.0

52.0

54.0

56.0

58.0

60.0

1997 1999 2001 2003 2005 2007 2009

US dry natural gas production (lhs) Horizontal gas wells in Barnett (rhs)

700

1,200

1,700

2,200

2,700

3,200

48.0

50.0

52.0

54.0

56.0

58.0

60.0

Jan-97 Jan-99 Jan-01 Jan-03 Jan-05 Jan-07 Jan-09

Total US production (lhs) Rig-weighted IP, horizontal rigs, 6m avg (rhs)

700

1,200

1,700

2,200

2,700

3,200

3,700

4,200

2,000

4,000

6,000

8,000

10,000

12,000

Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Jan-10

Wells Production Rig-weighted IP, 3m avg (rhs)

December 1, 2010


The Barnett is a great example of the contribution to growth from adding new wells, rather

than increases in productivity. In fact, average initial production rates of horizontal wells in

the Barnett did not improve much in 2006-08, when production growth was the most

impressive (Exhibit 11). In other words, new unconventional wells replacing old

conventional ones in the overall well mix was the key source to production growth in the

Barnett, rather than continued improvement in productivity of the unconventional wells

themselves. Again, it should be noted that all shale plays are different, and that in many of

the newer shale plays a much more gradual growth in IP can be observed.

As the growth in wells becomes more moderated, drilling can be done more selectively,

which generally has a positive effect on initial production rates of the new wells, a process

also known as high-grading. These developments are most advanced in Barnett and

Woodford, which are the two plays with the highest ratio of production to technically

recoverable resources, suggesting this is a natural process once the best areas of a play

have been developed (Exhibit 12). However, collapsing natural gas prices in the wake of the

financial crisis of 2008 was likely also key to the timing and speed of the slowdown in

activity in these plays, suggesting there is an important cyclical component here as well.

Exhibit 11: Initial production rates did not improve much

in Barnett in 2006-08, suggesting growth was driven by

new wells Left axis: wellhead production in mmcf/d and number of

horizontal wells; right axis: average 1m IP, mcf/d

Exhibit 12: The financial crisis capped growth in Barnett

and Woodford, which are most developed relative to

reserves Production to technically recoverable gas resources

Source: Goldman Sachs Global ECS Research. IHS. Includes data supplied by IHS Inc.; Copyright 2010 IHS.


At the current stage in the shale gas revolution, we think the growth contribution from

reduced drilling times has likely peaked and will diminish on an individual play basis, while

IP rates are likely to continue to grow but at a slower and slower pace, barring major

changes in rig counts. However, since plays have different IP levels and drilling times

relative to each other, it is important to distinguish between efficiency gains at the play

level and at the US aggregate level. While the efficiency measures for each play tends to

follow relatively stable and predictable trajectories, there is still potential for significant

shifts in these variables on a US aggregate level owing to shifts in activity between

different plays. The clearest example being rigs moving from say Haynesville to Eagle Ford.

Based on the characteristics of each of those plays, this will affect the aggregate measures

of IP per horizontal rig negatively, since Haynesville display higher IP rates than Eagle Ford,

but aggregate drilling times will likely drop as well, so there will be offsetting effects on

total efficiency of the rigs (Exhibit 13).

600

700

800

900

1,000

1,100

1,200

1,300

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10

Production Wells IP (rhs)

0

20

40

60

80

100

120

140


Barnett Haynesville Fayetteville Woodford Marcellus

December 1, 2010


Exhibit 13: Average IP jumped in 2009 on Barnett high-grading and Haynesville ramp-up,

but has come off in 2010 Initial production horizontal rigs, mcf/d

Source: Bentek Energy

At the aggregate level, we expect both drilling times and IP to improve moderately over

2011-12, but at a slower and slower pace, and nothing comparable to 2009. Specifically, IP

improvements are likely to face physical limitations to further improvements in lateral

length and optimized targeting. The caveat on the IP side is that major reductions in rig

counts will likely put upward pressure on IPs, as happened in Barnett.

The aggregate drilling time will likely benefit from a relative shift in focus away from

Haynesville, while the loss in aggregate IP from this will be offset by growth in Marcellus

and Granite Wash and further overall improvements to IP on a play-by-play basis as

discussed above. On net, although we think these efficiency measures may increase some

more over the next few years, their impact on production growth is largely behind us at

this point. Completion rates are instead the area where we see the most potential for

improvement going into 2011, as discussed earlier.

Market remains vulnerable to supply-side surprises as most

offsetting adjustments have already been made

Even as efficiency gains in production seem to be moderating, however, we continue to

see production growth risks skewed to the upside. As we have argued in the past, were

these risks to be realized, prices would likely respond by moving lower thereby reducing

the incentives for supply growth and triggering further natural gas demand.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000


Average IP of wells drilled with horizontal rigs

December 1, 2010


Such a scenario has largely played out this year, with NYMEX natural gas prices averaging

$4.39/mmBtu, driving US LNG imports to a minimum and incentivizing coal-to-gas

substitution in the power generation sector, as gas became once again cheaper than coal

generation costs.

However, exceptionally warmer than average temperatures in the united States this

summer increased the utilization rate of gas-fired plants, and in particular of the most

efficient CCGTs, leaving little room for fuel substitution. In other words, since the most

efficient gas-fired plants were already in use, the coal-to-gas price spread had to widen to

make fuel substitution economical for less efficient gas-fired plants. This has, in our view,

put additional downside pressure on natural gas prices this summer and kept (weather

adjusted) incremental gas demand for generation closer to 1 Bcf/d than the 1.7 Bcf/d

estimated for 2009.

The already low levels of US LNG imports suggest that any incremental tightening of the

US gas market via lower imports is limited, as are any chances of rebalancing the market

solely based on industrial demand growth, as we discussed previously. Hence, we believe

that balancing the market for the next couple of years will depend on responses from US

production, on the supply side, and coal-to-gas fuel substitution, on the demand side, to

still significantly low natural gas prices. Consequently, we are lowering our 2011 NYMEX

natural gas price forecast to $4/mmBtu from $5.25/mmBtu and we are introducing our 2012

natural gas price forecast marginally higher, at $4.25/mmBtu.

As a result of such a price path, which includes sub-$4/mmBtu prices expected in 3Q2011,

we believe US natural gas production growth will be limited to approximately 1.4 Bcf/d in

2011 and 0.9 Bcf/d in 2012. Specifically, despite the support to production from higher oil

prices and the de-bottlenecking in the services sector allowing well completions to

accelerate in 2011, which we have discussed previously in this report, the low natural gas

prices will likely limit the number of new producer hedges following the expiration of

current hedges. Further, as some of the acreage leases in new shale drilling areas expire,

producers will have less of an incentive to drill regardless of natural gas prices and will

likely behave more consistently with the investment economics presented by the market.

Going into 2012, we expect a lower impact from services de-bottlenecking relative to 2011

and, hence, a modestly lower production increase.

In addition, on the demand side, we believe that the potential for coal-to-gas substitution is

in the 2 Bcf/d range in 2011. This is significantly higher than estimated coal-to-gas

substitution in 2010, as we still expect the coal-to-gas generation cost spread to remain

wide (near $1/mmBtu at $65/t Appalachia coal for at least part of 2011) while assuming a

normalization in weather. Specifically, milder weather in summer 2011 relative to 2010 will

leave more spare capacity in gas-fired plants, allowing the coal-to-gas fuel substitution to

take place. While August utilization capacity is still expected at 100%, we expect significant

room for incremental gas burn in other months based on the typical variations in utilization

of gas-fired plants relative to August (Exhibit 14).

December 1, 2010


Exhibit 14: Low natural gas prices relative to coal will likely incentivize significant fuel

switching in the generation sector Estimated incremental natural gas demand owing to coal-to-gas substitution in Bcf/d


We note, however, that the coal-to-gas substitution process will likely displace a significant

amount of coal (estimated at 50 mn tonnes for next year), contributing to a rapid fill of coal

inventories in the United States, such as what happened in 2009, as the export market is

unlikely to absorb all the displaced coal. As a result of this oversupply of coal in the United

States, Appalachia prices will likely move lower in 2011, although we expect them to be

supported at their estimated cash cost in the $60/t range. It is this price impact that will

likely limit the amount of coal-to-gas substitution to 2 Bcf/d, as opposed to what it could

have been if coal prices remained well supported keeping the coal-to-gas price spread

wider.

In 2012 the lower expected production growth than in 2011 indicates that less coal-to-gas

substitution is required to balance the gas market, allowing natural gas prices to move

marginally higher. At $4.25/mmBtu gas prices and coal near cash costs we estimate coal-

to-gas substitution will likely remain in the 1.7 Bcf/d range.

Net, even after taking into account the expected supply and demand responses to our

forecast natural gas price path for 2011 and 2012, which is currently below the forward

curve, we believe gas inventories will still reach relatively high levels by the end of summer

in both years (Exhibit 15).

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

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

2011 2012

December 1, 2010


Exhibit 15: Even after taking into account a response from supply and demand to lower

gas prices, we expect inventories to be close to full next summer US working storage level, bcf

Source: Goldman Sachs Global ECS Research, DOE.

This is a reminder that, although shale gas productivity gains may be arguably

approaching a steady state in the near to medium term, the US natural gas market is still

imbalanced. Barring extreme weather or regulatory changes affecting hydraulic fracturing,

it is only when we see a consistent leg up on the demand side, which, as we discussed

previously, may be brought about by significant coal plant retirements from 2014 on, that

we believe US natural gas prices may move consistently higher, supported by

fundamentals. Until then, we are likely to continue to see a market disconnected from gas

prices elsewhere in the world and from the oil market.

Global gas and LNG: Transitioning away from the US and back

towards oil indexation

While US natural gas markets have remained over supplied and with prices persistently

low, the main feature of global gas markets in 2010 was a disconnect from such a pattern.

Specifically, UK NBP and spot LNG natural gas prices have moved significantly above US

levels, particularly in 2H2010, largely driven by a sudden tightness in the LNG market

(Exhibit 16).

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500


5-year average 2012E 2011E 2010E

3979 Bcf

1870 Bcf

December 1, 2010


Exhibit 16: UK NBP and spot LNG natural gas prices have moved significantly above US

levels, particularly in 2H2010 Global fuel prices, $/mmBtu

Source: NYMEX, Platts, ICE, Goldman Sachs

This tightness was the result of low utilization rates in liquefaction terminals in 1H2010 at

the same time that natural gas demand spiked in all continents supported by (transient)

weather events, listed below:

Cold winter in Europe. January, February and May were particularly cold months,

driving 2010 natural gas consumption up by 1 Bcf/d;

Warmer than average summer in Asia. We estimate that this has prompted Asian

demand up by approximately 600 mmcf/d this year; and

Cold and drought in South America. A cold winter spurred Argentinian heating

related demand, while the worst drought in 47 years in Brazil spiked LNG imports

for power generation to compensate for low hydro power. We estimate that

weather driven incremental demand in the region was in the order of 300-

400 mmcf/d.

At the same time, on the supply side, liquefaction utilization rates were significantly low,

albeit on average not as low as in 2009, but with an important difference: this time around

Qatar, the largest LNG exporter cut back approximately 2 Bcf/d of supplies from the market

by sequentially shutting down several of its liquefaction trains for alleged maintenance.

Qatari supplies remained depressed until mid-year, when global prices rose to

$6.50/mmBtu and above in response to this 4 Bcf/d transient tightness.

We believe that this cut back in Qatari supplies, along with the lower Russian sendouts to

Europe via pipeline since last year, suggests that some of the largest gas producers outside

of the United States are willing to defend a floor for international gas prices. Based on

historical responses in utilization rates to prices, we believe that this floor will be in the

$7/mmBtu range, even as global markets are expected to remain over supplied in 2011 as

the weather-driven demand observed in 2010 fades. If prices move consistently below that

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

22.00

Jan-08 May-08 Sep-08 Jan-09 May-09 Sep-09 Jan-10 May-10 Sep-10

Platts Japan Korea LNG Marker NYMEX Natural Gas

UK NBP Natural Gas Continental oil-indexed proxy

December 1, 2010


range, we believe that producers will cut back supplies to tighten global balances and,

hence, restore support to international prices. As a result, we are raising our 2012 UK NBP

price forecast to $7/mmBtu (39.80 p/th) from $5.75/mmBtu (35.20 p/th).

Going into 2012, we expect renewed growth of global demand in both OECD and non-

OECD countries to tighten the market relative to 2011, requiring global liquefaction

utilization rates to rise to 87% (above historical average of 85%) from 81% in 2011 to satisfy

demand (Exhibit 17). We believe that such a high utilization rate will require higher price

levels as an incentive as we have seen this year and in the past and we are therefore

introducing our 2012 UK NBP price forecast at $8.50/mmBtu (45.90 p/th), where the

expected price path embeds NBP prices as high as $9.50 by 4Q2012.

Exhibit 17: We expect global liquefaction utilization rates to rise to 87% in 2012 to satisfy

demand Global liquefaction utilization rates

Source: Goldman Sachs Global ECS Research, Waterborne Energy.

Interestingly, we believe that the seasonality historically embedded in liquefaction

utilization rates’ curves (higher in the winter, lower in the summer) will gradually be

eliminated as exemplified by our expected 2012 levels (Exhibit 17). This is because non-

OECD buyers of LNG typically have an opposite seasonal pattern from OECD buyers, with a

lot of their demand dedicated to summer generation demand (or winter heating demand,

in the case of South America, in the June-August period). These seasonal patterns are

likely to increase competition for summer LNG cargoes as non-OECD buyers become a

larger share of the market – which we estimate at 20% by the end of 2012, up from only 9%

four years ago – flattening the liquefaction utilization rate curve (Exhibits 18 & 19).

65%

70%

75%

80%

85%

90%

95%

100%


2012E 2011E 2010E 2010 2009 2008 2007

December 1, 2010


Exhibit 18: Non-OECD buyers are changing the

seasonality of global LNG sales… Expected LNG purchases in 2012 in Bcf/d

Exhibit 19: … as their share of global LNG consumption is

expected to continue to rise, likely reaching 20% by 2012Realized and expected LNG consumption in Bcf/d



Beyond 2012, continued growth in global gas demand will likely further tighten LNG

markets, as liquefaction capacity additions become fewer and further in between after 2011.

As a result, we see 2012 as a transition year towards a return to spot natural gas (outside of

the US) pricing in the same range as oil-indexed natural gas contracts.

Overview of global LNG markets in 2011 and 2012 by region

OECD Asia

2011 gas consumption and LNG imports expected flat year on year as the weather

adjustment in 2011 compensates for increased economic-driven demand. We expect the

region to return to strong growth, in the 600 mmcf/d range, in 2012.

Northwest Europe

Natural gas consumption expected flat year on year in 2011 also due to a weather

correction. However, LNG imports are expected to rise approximately 800 mmcf/d driven

by declining production, increased pipeline exports to Mediterranean Europe via Transitgas

pipeline and storage demand for gas. In 2012, both gas consumption and LNG imports are

expected to rise (800 mmcf/d and 1.3 Bcf/d, respectively).

Mediterranean Europe

We expect increased gas consumption in 2011 and 2012 to be satisfied by increased

pipeline imports, after the start up and ramp up of the Medgaz pipeline from Algeria. Hence,

we expect LNG imports flat to down in both years.

North America

Modest LNG import growth in 2011 and 2012 likely driven by Mexican demand.

South America

We expect small increments in demand in 2011 and 2012 led by Argentina and Chile, while

Brazilian LNG imports decline as weather normalizes and gas production from the

Mexilhao field starts by the end of this year.

0

5

10

15

20

25

30

35

Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12

OECD Non-OECD

0

5

10

15

20

25

30

35

40

Dec-06 Jul-07 Feb-08 Sep-08 Apr-09 Nov-09 Jun-10 Jan-11 Aug-11 Mar-12 Oct-12

OECD

Non-OECD

Realized Expected

December 1, 2010


Non-OECD Asia and Middle East

We expect significant growth in LNG imports, near 1 Bcf/d in both 2011 and 2012, led by

Chinese imports after the planned start up of two additional import terminals in 2011 and

one in 2012.

2011/2012 US supply and demand outlook details

Exhibit 20: Expected 2011 natural gas balance

Year on year changes by category in Bcf

Exhibit 21: Expected 2012 natural gas balance

Year on year changes by category in Bcf

Source: DOE and Goldman Sachs Global ECS Research.


Supply

Production

US unconventional natural gas production continued to grow at an impressive rate this

year, and displayed remarkable resilience to the low gas prices. Overall, US production will

likely increase by more than 2 bcf/d to around 59.5 bcf/d in 2010. Unprecedented gains in

rig and well productivity likely drove the growth in 2009, but in 2010 other factors have also

played a significant role. Specifically, oil economics have become an increasingly

important driver of gas production. With the current price differential between oil and gas,

gas producers are moving to more liquids-rich areas to increase their oil price exposure. In

addition, oil drilling in the US is booming, resulting in increasing associated gas production

in many oil fields. We generally expect the efficiency gains in production to level off, but

there will likely be continued strong growth through 2011 as new capacity is added on the

services side, in particular more fracing capacity. We therefore forecast higher growth in

2011 (+1.4 bcf/d) than in 2012 (+0.9 bcf/d) (Exhibit 22).

LNG imports

One striking implication of the production growth in the United States is that the North

America has largely disconnected from the global markets by its inability to absorb LNG in

face of such an oversupply in the market. The LNG import terminals built in recent years

are severely underutilized, and will likely remain so through 2012, in our view. We expect

LNG imports to remain around this year’s depressed levels, and forecast 1.2 Bcf/d for the

coming two years (Exhibit 23).

-300

-200

-100

0

100

200

300

400

500

600

Production Net Pipeline Imports

Net LNG Imports

Residential Demand

Commercial Demand

Industrial Demand

Power Generation

Demand

Other Net

1.36 Bcf/d

-0.71 Bcf /d

0.02 Bcf /d

0.12 Bcf/d 0.11 Bcf/d

0.33 Bcf /d

0.69 Bcf /d

-0.25 Bcf/d

-0.35 Bcf /d

-300

-200

-100

0

100

200

300

400

Production Net Pipeline Imports

Net LNG Imports

Residential Demand

Commercial Demand

Industrial Demand

Power Generation

Demand

Other Net

0.91 Bcf /d

-0.62 Bcf/d

0.0 Bcf/d 0.00 Bcf/d

-0.02 Bcf/d

0.40 Bcf /d

0.25 Bcf/d

0.08 Bcf/d

-0.43 Bcf /d

December 1, 2010


Exhibit 22: US dry natural gas production

Bcf/d

Exhibit 23: US LNG imports

Bcf/d



Pipeline imports

Canadian production is in structural decline, and growth from Montney and Horn River

Basin will not be able to reverse this, in our view. In addition, increasing oil sands

production will likely put slight upward pressure on Canadian consumption, further limiting

the volumes available for exports to the United States. In addition, increasing US

production has been displacing Canadian gas this year, and we expect this to continue.

Specifically, the new Ruby and Bison pipelines will increase the capacity to deliver Rockies

gas to the California and Midwest markets, which this year have been destination markets

for Canadian gas already displaced from the eastern United States. Net, we expect US

pipeline imports to decline 0.7 Bcf/d in 2011 and 0.5 Bcf/d in 2012 (Exhibit 24).

Pipeline exports

We see US pipeline exports remaining strong and edging higher over 2011-12 as Mexican

power generation demand for natural gas to continues to grow. We also expect support to

pipeline exports from increased competitiveness of Marcellus Shale against Alberta gas in

Eastern Canada (Exhibit 25).

48

50

52

54

56

58

60

62

64


2012E 2011E 2010E 2010 2009 2008 2007

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0


2012E 2011E 2010E 2010 2009 2008 2007

December 1, 2010


Exhibit 24: US natural gas pipeline imports

Bcf/d

Exhibit 25: US natural gas pipeline exports

Bcf/d



Demand

Residential and commercial demand

The first half on 2010 saw unusually large deviation from normal seasonal demand from

residential and commercial consumers, with January and February being very cold and

March, April and May being mild. Net, the effects have canceled each other out to a large

extent. We expect both residential and commercial demand for natural gas to increase only

slightly in 2011 and to be flat year-over-year in 2012 (Exhibits 26 & 27).

Exhibit 26: US residential demand for natural gas Bcf/d

Exhibit 27: US commercial demand for natural gas Bcf/d



6.0

7.0

8.0

9.0

10.0

11.0

12.0


2012E 2011E 2010E 2010 2009 2008 2007

1.0

1.5

2.0

2.5

3.0

3.5

4.0


2012E 2011E 2010E 2010 2009 2008 2007

2.0

7.0

12.0

17.0

22.0

27.0

32.0

37.0


2012E 2011E 2010E 2010 2009 2008 2007

3.0

5.0

7.0

9.0

11.0

13.0

15.0

17.0

19.0


2012E 2011E 2010E 2010 2009 2008 2007

December 1, 2010


Industrial demand

Industrial demand has recovered nicely so far this year, and is up more than 1 Bcf/d

compared to 2009. Even though pipeline scrubs in recent months have suggested the

recovery is running out of steam, we believe this will prove temporary. We assume a

positive stance on industrial demand on the back of upward revisions to the economic

outlook made by our US economists as well as of increased competitiveness of US

manufacturing relative to the rest of the world owing to US dollar weakness and to lower

natural gas prices. Specifically, we forecast industrial demand to grow 0.3 Bcf/d in 2011 and

0.4 Bcf/d in 2012 (Exhibit 28).

Generation demand

Although extreme weather has provided strong support for generation demand this year,

we believe that increased coal-to-gas substitution as well as structural growth in demand

supported by the economic recovery expected in 2011 will compensate for the weather

adjustment and help drive generation demand approximately 700 mmcf/d higher next year.

In 2012 we expect coal-to-gas substitution to moderate on the back of reduced gas

production growth, but total generation demand is still likely to rise moderately, by

approximately 250 mmcf/d, on the back of structural increases in demand (Exhibit 29).

Exhibit 28: US industrial demand for natural gas

Bcf/d

Exhibit 29: US generation demand for natural gas

Bcf/d



14

15

16

17

18

19

20

21

22


2012E 2011E 2010E 2010 2009 2008 2007

10

15

20

25

30

35


2012E 2011E 2010E 2010 2009 2008 2007

Decem

ber 1, 2010

Goldm

an Sachs Global Econom

ics, Com

modities and Strategy R

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23

Exhibit 30: US natural gas balance table

Bcf/d unless otherwise indicated


Jan-11E Feb-11E Mar-11E Apr-11E May-11E Jun-11E Jul-11E Aug-11E Sep-11E Oct-11E Nov-11E Dec-11E Jan-12E Feb-12E Mar-12E Apr-12E May-12E Jun-12E Jul-12E Aug-12E Sep-12E Oct-12E Nov-12E Dec-12E 2011E 11 YOY 2012E 12 YOY

Supply

Production 60.26 60.37 60.48 60.69 60.69 60.87 60.86 60.93 61.02 61.12 61.31 61.41 61.36 61.47 61.68 61.69 61.79 61.77 61.76 61.83 61.82 61.92 61.91 61.91 60.83 1.36 61.74 0.91

Pipeline imports 10.60 10.00 9.00 8.26 7.40 7.30 7.70 7.90 7.60 7.24 7.70 9.30 10.08 9.48 8.28 7.54 6.78 6.68 7.38 7.58 7.28 6.92 7.38 8.98 8.33 -0.66 7.86 -0.47

LNG imports 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 0.02 1.20 0.00

Balancing term -2.27 1.70 1.51 1.99 0.33 0.15 0.05 -0.16 -0.61 -3.18 -4.31 -5.18 -2.27 1.70 1.51 1.99 0.33 0.15 0.05 -0.16 -0.61 -3.18 -4.31 -5.18 -0.83 0.16 -0.83 0.00

Demand

Pipeline exports 3.35 3.30 3.15 2.80 2.70 2.55 2.55 2.45 2.53 2.71 3.09 3.47 3.50 3.45 3.30 2.95 2.85 2.70 2.70 2.60 2.68 2.86 3.24 3.62 2.89 0.06 3.04 0.15

LNG exports 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.00 0.10 0.00

Residential demand 29.21 26.94 20.82 13.25 7.00 4.76 3.85 3.57 4.21 7.31 14.44 24.17 29.21 26.94 20.82 13.25 7.00 4.76 3.85 3.57 4.21 7.31 14.44 24.17 13.29 0.12 13.29 0.00

Commercial demand 15.58 15.01 12.02 8.75 5.65 4.49 4.25 4.24 4.62 6.00 9.00 13.15 15.58 15.01 12.02 8.75 5.65 4.49 4.25 4.24 4.62 5.80 9.00 13.15 8.56 0.11 8.55 -0.02

Industrial demand 20.22 20.30 19.22 17.90 17.36 17.19 17.04 17.12 17.07 17.46 18.11 19.29 20.41 20.70 19.52 18.25 17.71 17.44 17.24 17.33 17.47 17.92 18.97 20.15 18.19 0.33 18.59 0.40

Generation demand 18.87 18.37 18.65 18.82 20.13 22.40 27.55 26.59 23.60 20.60 18.90 18.65 19.15 18.68 18.93 18.99 20.31 23.17 27.61 27.03 23.56 20.82 19.04 18.85 21.09 0.69 21.35 0.25

Vehicle fuel cons. 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.10 0.01 0.11 0.01

Lease and plant cons. 3.53 3.53 3.54 3.55 3.55 3.56 3.56 3.57 3.57 3.58 3.59 3.59 3.59 3.60 3.61 3.61 3.62 3.62 3.61 3.62 3.62 3.62 3.62 3.62 3.56 0.00 3.61 0.05

Pipeline and dist. use 2.33 2.24 1.97 1.63 1.40 1.36 1.47 1.44 1.38 1.43 1.68 2.10 2.35 2.26 1.98 1.65 1.41 1.39 1.48 1.45 1.39 1.44 1.71 2.12 1.70 -0.08 1.72 0.02

Stock change (Bcf) -728 -465 -229 157 361 390 289 331 361 220 -93 -555 -733 -493 -239 143 352 360 292 322 358 213 -122 -589Inventory level (Bcf) 2563 2098 1870 2027 2388 2778 3067 3398 3759 3979 3886 3331 2599 2106 1867 2010 2361 2722 3014 3336 3694 3906 3785 3196

*Actual through September 2010.

Decem

ber 1, 2010

Goldm

an Sachs Global Econom

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modities and Strategy R

esearch

24

Exhibit 31: Global LNG balance table Bcf/d unless otherwise indicated


Jan-11E Feb-11E Mar-11E Apr-11E May-11E Jun-11E Jul-11E Aug-11E Sep-11E Oct-11E Nov-11E Dec-11E Jan-12E Feb-12E Mar-12E Apr-12E May-12E Jun-12E Jul-12E Aug-12E Sep-12E Oct-12E Nov-12E Dec-12E 2010E 10YOY 2011E 11YOY 2012E 12YOY

OECD AsiaProduction 0.45 0.46 0.44 0.39 0.37 0.38 0.39 0.39 0.38 0.38 0.43 0.49 0.45 0.46 0.44 0.39 0.37 0.38 0.39 0.39 0.38 0.38 0.43 0.49 0.40 0.03 0.41 0.01 0.41 0.00Pipeline imports 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00LNG imports 14.72 14.68 14.62 13.06 11.64 12.17 12.24 12.82 13.32 13.27 13.75 14.57 15.26 15.22 15.16 13.62 12.19 12.72 12.82 13.41 14.00 13.76 14.35 15.17 13.48 1.64 13.41 -0.08 13.97 0.57Exports 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Consumption 15.37 15.86 14.56 13.88 12.50 12.55 12.73 13.02 13.20 13.25 14.18 14.97 15.91 16.40 15.10 14.43 13.06 13.10 13.31 13.60 13.78 13.84 14.78 15.56 13.81 1.53 13.84 0.03 14.41 0.57Stock change -0.20 -0.73 0.50 -0.43 -0.50 0.00 -0.10 0.19 0.50 0.40 0.00 0.10 -0.20 -0.73 0.50 -0.43 -0.50 0.00 -0.10 0.20 0.60 0.30 0.00 0.10 0.08 0.13 -0.02 -0.10 -0.02 0.00Inventory level (Bcf) 283 262 278 265 250 250 246 252 267 280 280 283 277 256 271 259 243 243 240 246 264 273 274 277

Other Asia LNG demandChina 1.05 1.10 1.30 1.36 1.77 1.70 1.90 2.08 2.04 1.80 1.80 1.80 1.75 1.60 1.70 1.76 2.17 2.10 2.20 2.38 2.34 2.10 2.10 2.10 1.18 0.43 1.64 0.46 2.02 0.38India 1.40 1.40 1.40 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.27 0.01 1.50 0.23 1.78 0.28Indonesia 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.10 0.10 0.10 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.00 0.00 0.03 0.03 0.20 0.18Taiwan 1.05 1.12 1.40 1.60 1.50 1.80 1.70 1.70 1.70 1.70 1.60 1.30 1.05 1.12 1.40 1.60 1.50 1.80 1.70 1.70 1.70 1.70 1.60 1.30 1.53 0.33 1.51 -0.01 1.51 0.00Thailand 0.00 0.00 0.00 0.00 0.00 0.00 0.10 0.10 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.00 0.00 0.06 0.06 0.14 0.08

MED EUROPE**Production 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.03 0.01 1.00 -0.03 1.00 0.00Pipeline imports 10.75 10.63 11.14 11.10 10.06 10.15 10.13 8.85 10.20 10.45 11.86 12.71 12.94 12.58 11.92 11.40 10.36 10.45 10.43 9.15 10.50 10.75 12.16 13.01 9.82 -0.50 10.67 0.85 11.31 0.63LNG imports 5.61 6.12 4.97 4.24 3.82 3.85 4.23 3.68 4.03 4.70 5.36 5.23 4.03 4.77 4.79 4.55 4.12 4.15 4.53 3.98 4.33 5.00 5.66 5.53 4.98 1.38 4.65 -0.33 4.62 -0.03Exports 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.02 0.01 0.00 -0.02 0.00 0.00Consumption 20.91 20.49 17.89 15.22 13.02 12.96 13.31 11.96 14.13 15.65 18.82 20.93 21.51 21.09 18.49 15.82 13.62 13.56 13.91 12.57 14.73 16.25 19.42 21.53 15.88 0.93 16.27 0.39 16.88 0.60Stock change -3.55 -2.74 -0.78 1.13 1.85 2.04 2.06 1.56 1.10 0.50 -0.60 -1.99 -3.55 -2.74 -0.78 1.13 1.85 2.04 2.06 1.56 1.10 0.50 -0.60 -1.99 -0.08 -0.05 0.05 0.13 0.05 0.00Inventory level (Bcf) 735 658 634 668 725 786 850 898 931 947 929 867 757 678 653 687 745 806 870 918 951 967 949 887

NW EUROPE***Production 21.12 20.13 18.41 15.28 12.12 11.30 10.30 10.00 11.00 14.43 19.07 21.57 20.72 19.73 18.01 14.78 11.62 10.90 9.90 9.60 10.60 14.03 18.67 21.17 15.60 0.26 15.39 -0.20 14.98 -0.42Pipeline imports 15.72 14.94 13.73 13.42 12.52 12.20 11.74 11.84 12.15 13.53 14.79 15.21 15.82 15.04 13.83 13.52 12.62 12.30 11.84 11.94 12.25 13.63 14.89 15.31 13.60 0.20 13.48 -0.12 13.58 0.10LNG imports 3.23 3.53 4.86 6.83 5.98 4.65 5.16 3.54 4.63 5.47 5.69 5.52 5.47 5.73 6.22 7.50 7.14 5.72 6.22 4.70 5.80 6.63 6.86 6.68 4.11 0.86 4.92 0.81 6.22 1.30Exports 0.20 0.20 0.69 0.78 0.86 0.94 0.95 0.76 0.99 1.03 1.14 1.29 1.28 1.34 0.99 0.88 0.86 0.94 0.95 0.76 0.99 1.03 1.14 1.29 0.66 -0.26 0.82 0.16 1.04 0.22Consumption 47.52 45.70 39.80 32.01 25.17 22.14 20.71 19.54 23.40 31.62 40.92 45.65 48.39 46.47 40.57 32.57 25.94 22.91 21.47 20.41 24.26 32.49 41.79 46.51 32.87 1.88 32.85 -0.02 33.65 0.80Stock change -7.66 -7.30 -3.50 2.74 4.60 5.08 5.54 5.07 3.39 0.77 -2.52 -4.63 -7.66 -7.30 -3.50 2.34 4.60 5.08 5.54 5.07 3.39 0.77 -2.52 -4.63 -0.22 -0.31 0.13 0.35 0.10 -0.03Inventory level (Bcf) 1002 798 689 771 914 1066 1238 1395 1497 1521 1446 1302 1064 853 744 814 957 1109 1281 1438 1540 1564 1488 1345

NORTH AMERICA****Production 83.02 82.33 81.35 81.33 81.19 80.63 81.11 80.43 80.70 80.95 81.92 83.17 83.72 83.03 82.15 81.93 81.89 81.13 81.61 80.93 81.10 81.35 82.12 83.27 80.72 1.71 81.51 0.79 82.02 0.51Pipeline imports 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00LNG imports 2.48 2.40 2.38 2.29 2.38 2.19 2.48 2.19 2.38 2.29 2.48 2.48 2.68 2.60 2.58 2.49 2.58 2.39 2.68 2.39 2.58 2.49 2.68 2.68 2.11 0.26 2.37 0.26 2.57 0.20Exports 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.09 0.01 0.10 0.01 0.10 0.00Consumption 111.96 103.75 92.61 78.03 69.63 67.24 70.95 69.66 69.52 75.39 87.36 105.26 112.82 104.84 93.57 78.93 70.54 68.65 71.57 70.77 70.24 76.24 88.73 106.68 82.46 2.60 83.45 0.99 84.47 1.02Stock change -26.56 -19.11 -8.98 5.50 13.84 15.49 12.54 12.86 13.46 7.75 -3.06 -19.71 -26.52 -19.31 -8.94 5.40 13.82 14.78 12.62 12.45 13.34 7.50 -4.02 -20.83 0.28 -0.64 0.33 0.05 0.02 -0.31Inventory level (Bcf) 2994 2459 2181 2346 2775 3239 3628 4027 4430 4671 4579 3968 3146 2586 2308 2470 2899 3342 3733 4119 4519 4752 4631 3986

Other LNG demandArgentina 0.00 0.00 0.10 0.10 0.20 0.30 0.40 0.50 0.50 0.20 0.00 0.00 0.00 0.00 0.20 0.30 0.30 0.50 0.60 0.60 0.40 0.20 0.00 0.00 0.15 0.05 0.19 0.05 0.26 0.07Brazil 0.30 0.20 0.20 0.10 0.20 0.10 0.20 0.10 0.20 0.10 0.20 0.10 0.20 0.10 0.20 0.10 0.20 0.10 0.20 0.10 0.20 0.10 0.20 0.10 0.26 0.19 0.17 -0.09 0.15 -0.02Chile 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.52 0.52 0.52 0.52 0.52 0.52 0.52 0.52 0.52 0.52 0.52 0.52 0.30 0.24 0.40 0.10 0.52 0.12Kuwait 0.00 0.00 0.09 0.20 0.40 0.48 0.51 0.58 0.51 0.40 0.20 0.00 0.00 0.00 0.09 0.20 0.40 0.48 0.51 0.58 0.51 0.40 0.20 0.00 0.28 0.20 0.28 0.00 0.28 0.00

Liquefaction capacity 36.60 36.60 38.19 38.76 38.76 38.76 38.76 38.76 38.76 38.76 38.76 38.76 38.76 38.76 39.45 39.45 39.45 39.45 39.45 39.45 39.45 40.08 40.08 40.08 35.53 4.70 38.36 2.83 39.50 1.14LNG supply 30.23 30.94 31.73 31.72 29.82 29.18 30.85 29.22 31.38 32.10 33.26 33.17 32.83 33.79 35.01 34.77 33.26 32.63 34.12 32.51 34.52 35.04 36.31 36.22 29.65 5.61 31.13 1.49 34.25 3.12

*Actual through August 2010.**Italy, Spain, Greece, Austria and Turkey.***United kIngdom, France, Germany, Portugal, Luxembourg, Switzerland, Netherlands, Ireland and Belgium.****United States and territories, Canada and Mexico.

December 1, 2010


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