natural gas watch - energianews.com · consequently, we lower our 2011 nymex natural gas price...
TRANSCRIPT
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
+44(20)7774-6112 [email protected] Goldman Sachs International
Johan Spetz
+44(20)7552-5946 [email protected] Goldman Sachs International
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
Goldman Sachs Global Economics, Commodities and Strategy Research 3
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
Source: Goldman Sachs Global ECS Research.
December 1, 2010
Goldman Sachs Global Economics, Commodities and Strategy Research 4
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
Goldman Sachs Global Economics, Commodities and Strategy Research 5
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
Goldman Sachs Global Economics, Commodities and Strategy Research 6
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
Goldman Sachs Global Economics, Commodities and Strategy Research 7
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
Goldman Sachs Global Economics, Commodities and Strategy Research 8
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
Goldman Sachs Global Economics, Commodities and Strategy Research 9
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
Goldman Sachs Global Economics, Commodities and Strategy Research 10
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.
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
Goldman Sachs Global Economics, Commodities and Strategy Research 11
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.
Source: DOE, 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
Jan-00 Jan-02 Jan-04 Jan-06 Jan-08 Jan-10
Barnett Haynesville Fayetteville Woodford Marcellus
December 1, 2010
Goldman Sachs Global Economics, Commodities and Strategy Research 12
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
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10
Average IP of wells drilled with horizontal rigs
December 1, 2010
Goldman Sachs Global Economics, Commodities and Strategy Research 13
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
Goldman Sachs Global Economics, Commodities and Strategy Research 14
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
Source: Goldman Sachs Global ECS Research.
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
Goldman Sachs Global Economics, Commodities and Strategy Research 15
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
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
5-year average 2012E 2011E 2010E
3979 Bcf
1870 Bcf
December 1, 2010
Goldman Sachs Global Economics, Commodities and Strategy Research 16
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
Goldman Sachs Global Economics, Commodities and Strategy Research 17
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%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2012E 2011E 2010E 2010 2009 2008 2007
December 1, 2010
Goldman Sachs Global Economics, Commodities and Strategy Research 18
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
Source: Goldman Sachs Global ECS Research, Waterborne Energy.
Source: Goldman Sachs Global ECS Research, Waterborne Energy.
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
Goldman Sachs Global Economics, Commodities and Strategy Research 19
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.
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
Goldman Sachs Global Economics, Commodities and Strategy Research 20
Exhibit 22: US dry natural gas production
Bcf/d
Exhibit 23: US LNG imports
Bcf/d
Source: DOE and Goldman Sachs Global ECS Research.
Source: DOE and Goldman Sachs Global ECS Research.
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
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
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
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2012E 2011E 2010E 2010 2009 2008 2007
December 1, 2010
Goldman Sachs Global Economics, Commodities and Strategy Research 21
Exhibit 24: US natural gas pipeline imports
Bcf/d
Exhibit 25: US natural gas pipeline exports
Bcf/d
Source: DOE and Goldman Sachs Global ECS Research.
Source: DOE and Goldman Sachs Global ECS Research.
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
Source: DOE and Goldman Sachs Global ECS Research.
Source: DOE and Goldman Sachs Global ECS Research.
6.0
7.0
8.0
9.0
10.0
11.0
12.0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2012E 2011E 2010E 2010 2009 2008 2007
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2012E 2011E 2010E 2010 2009 2008 2007
2.0
7.0
12.0
17.0
22.0
27.0
32.0
37.0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
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
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2012E 2011E 2010E 2010 2009 2008 2007
December 1, 2010
Goldman Sachs Global Economics, Commodities and Strategy Research 22
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
Source: DOE and Goldman Sachs Global ECS Research.
Source: DOE and Goldman Sachs Global ECS Research.
14
15
16
17
18
19
20
21
22
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2012E 2011E 2010E 2010 2009 2008 2007
10
15
20
25
30
35
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2012E 2011E 2010E 2010 2009 2008 2007
Decem
ber 1, 2010
Goldm
an Sachs Global Econom
ics, Com
modities and Strategy R
esearch
23
Exhibit 30: US natural gas balance table
Bcf/d unless otherwise indicated
Source: Goldman Sachs Global ECS Research.
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
ics, Com
modities and Strategy R
esearch
24
Exhibit 31: Global LNG balance table Bcf/d unless otherwise indicated
Source: Goldman Sachs Global ECS Research.
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
Goldman Sachs Global Economics, Commodities and Strategy Research 25
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