January 2011
CERI Commodity Report – Natural Gas
Relevant • Independent • Objective
No Life Line in Sight for North American Natural Gas Prices The recent US economic downturn, which lasted 18 months, officially came to an end in June 2009. Since then, natural gas consumption in the four traditional demand sectors (residential, commercial, industrial, and electric power) has returned to pre-recession levels, with the electric power sector leading the way. However, this has had little impact on the price of natural gas in North America. The natural gas price at Henry Hub remains more than 50 percent below the average price in 2008, and is not expected to increase above the US$5/MCF level for quite some time. Abundant Domestic Supply The US natural gas supply picture appears drastically different today than it did five years ago. Strong US domestic natural gas production growth, led by shale gas development, has been the dominating factor affecting the price of natural gas over the past few years. In 2010, the US average annual marketed production of natural gas increased for the fifth consecutive year, since 2005, to 61.8 BCFPD, with 88 percent of the 2010 supply attributable to onshore production in the Lower-48 States.
Between 2009 and 2010, natural gas production increased by an average of 4.4 percent, or 2.61 BCFPD. Year-over-year declines in natural gas production in Alaska, and the Federal Gulf of Mexico (GoM), were more than offset by the 3.2 BCFPD (6.1 percent) production increase observed in the US Lower-48 States. Monthly average marketed production is shown, by area, in Figure 1 below. Figure 1: Monthly Marketed Natural Gas Production in 2009 and 2010, BCFPD
Source: CERI, US EIA Natural gas production in Alaska, the Federal GoM, New Mexico, Oklahoma, Texas, and Wyoming declined by a cumulative 34 percent during 2010. Over the past year, Louisiana’s annual marketed production growth outpaced that of any other natural gas producing state at 57.2 percent, or 2.4 BCFPD. According to the US EIA’s November 2010 report on US proved reserves in 2009, the development of the Haynesville shale resource in Louisiana was largely responsible for increasing the estimated proved reserves of wet gas1 in that state by a net 77 percent, or 9.2 TCF, compared to the 2008 estimate.2 Figure 2 illustrates the location of the Haynesville shale play.
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BCFPD
CERI COMMODITY REPORT - NATURAL GAS Editor-in-Chief: Mellisa Mei ([email protected]) CONTENTS FEATURED ARTICLE ...................................... 1 NATURAL GAS PRICES ................................. 5 WEATHER ..................................................... 7 CONSUMPTION AND PRODUCTION ............. 9 TRANSPORTATION ....................................... 11 STORAGE ...................................................... 13 LIQUEFIED NATURAL GAS ........................... 16 DRILLING ACTIVITY .................................... 18
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CERI Commodity Report – Natural Gas
Figure 2: Map of Haynesville Shale
Source: Oil and Gas Financial Journal, August 2009. Proved reserves in major shale gas producing states (Louisiana, Arkansas, Pennsylvania, Texas, Oklahoma), contributed to the substantial annual increase in the EIA’s estimate of proved wet gas reserves. US proved reserves of wet natural gas have reached their highest level since 1971. At the end of 2009, US wet natural gas reserves were estimated at 283.9 TCF, up 11.3 percent, or 28.8 TCF, from the EIA’s 2008 estimate.3 Shale gas accounted for 21 percent of proved wet gas reserves at the end of 2009, and more than 90 percent of the net additions to proved wet gas reserves made in 2009.4 Figure 3 displays the estimated proved reserves from US shale gas plays in 2008 and 2009.
Figure 3: Proved Reserves in Principal Shale Gas Plays, TCF
Source: CERI, EIA According to the Reference Case in the EIA’s Annual Energy Outlook 2011 (AEO2011) Early Release, shale gas production in 2010 was 14 times greater than that in 2000, and is projected to account for 45 percent of total US natural gas production by 2035.5 Estimated technically recoverable, unproved shale gas reserves increased from 353 TCF in the EIA’s 2010 outlook, to 827 TCF (as of January 1, 2009) in the EIA’s AEO2011, and accounts for 34 percent of the 2,552 TCF of technically recoverable natural gas resources in the US.6 The abundance of domestic natural gas supplies that can be extracted at relatively low costs resulted in a revision of the EIA’s natural gas price estimation methodology, to depend less on the price of oil.7 Natural gas wellhead prices, according to the AEO2011, will remain below US$5/MCF through 2022.8 Low Henry Hub gas prices, relative to the price of oil, have deterred some producers from making further capital commitments to develop natural gas resources. The natural gas directed rotary rig count, as a percentage of total operating rigs, has declined from an average of 78 percent during January 2009, to 53 percent during January 2011 (see Total US Rig Activity chart on Page 19). Several natural gas producers have shifted drilling strategies from targeting dry gas plays to exploring oil and liquids rich plays, in order to take advantage of higher oil prices. Throughout 2010, there was a substantial increase in the volume of condensate and natural gas liquids (NGLs) produced in the US.
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Page 3
Relevant • Independent • Objective
Despite weak natural gas prices, cash strapped companies are finding clever ways to finance new drilling operations. The average natural gas rotary rig count increased by nearly 18 percent between 2009 and 2010, but remained well below the 1,491 rigs operating in 2008. Joint venture agreements offer an effective solution to the challenge of accelerating production growth under capital spending constraints. In 2010, International Oil Companies (IOCs) and National Oil Companies (NOCs), such as Reliance Industries Limited (India), Chinese National Offshore Oil Corporation (China), Mitsui (Japan), and BG Group (United Kingdom), eagerly seized joint venture opportunities in prime shale gas plays. In several agreements, the IOCs or NOCs agreed to finance more than half of the development costs (typically 75 percent) in exchange for less than half of the assets. For example, CNOOC International Limited’s (CNOOC) approximately US$11,000 per net acre joint venture deal with Chesapeake Energy allowed CNOOC to acquire a 33.3 percent interest in Chesapeake’s liquids rich 600,000 net acre Eagle Ford asset, in exchange for US$1.08 million in upfront cash, an additional US$40 million payment adjustment at closing, and 75 percent of Chesapeake’s share of drilling and completion costs, paid for by CNOOC, up to a maximum of US$1.08 billion.9 In February 2011, PetroChina International Investment Company Limited agreed to purchase a 50 percent stake in Encana Corporation’s Cutbank Ridge shale gas assets, located in British Columbia and Alberta, for C$5.4 billion (C$8,504 per acre) in cash.10 Upstream merger and acquisition (M&A) activity in US shale gas plays returned to pre-recession levels in 2010, and was valued at US$39 billion.11 It is expected that 2011 will be an active year for M&As, as both IOCs and NOCs seek to gain a stronger foothold in the US shale gas industry. Declining Net US Imports The growth in US natural gas production has led to declining net imports of natural gas over the last three years. Between 2007 and 2010, the US has seen a nearly 14 percent decrease in natural gas imports from Canada (-1.41 BCFPD), and a 40 percent decrease in natural gas imports from Mexico (-0.06 BCFPD). The EIA estimates that an average of 9.08 BCFPD of natural gas was imported by pipeline during 2010. Additionally, with depressed
North American natural gas prices, US liquefied natural gas (LNG) imports experienced a decline from a peak of 2.11 BCFPD in 2007, to 1.18 BCFPD in 2010 (see Figure 4), as LNG cargoes have been diverted to higher paying European and Asian markets. It is likely that only the minimum LNG contract volumes are being shipped to LNG re-gasification facilities located in the US. Further declines in US LNG imports may occur if long-term supply contracts with Trinidad and Tobago, the largest supplier of LNG to the US, are restructured to include destination flexibility clauses.12
Figure 4: US LNG Imports, BCFPD
Source: CERI, US DOE Conversely, gross US natural gas exports (pipeline and LNG) have increased by 32 percent, since 2007, to an average of 2.96 BCFPD in 2010. Declining exports from Alaska’s Kenai LNG facility were offset by increased pipeline exports, as well as re-exports of foreign sourced LNG. A total of 37.22 BCF (or an average of 0.09 BCFPD) of foreign sourced LNG has been re-exported to 7 countries13 from the Sabine Pass and Freeport LNG terminals since December 2009. LNG re-exports are likely to increase in 2011, as the Sempra Energy’s Cameron LNG Terminal, located in Cameron Parish, Louisiana, was recently granted authorization from the US Department of Energy to re-export up to 250 BCF of previously imported LNG over a two year period, beginning in February 2011.14
Although natural gas liquefaction facilities do not currently exist in the US Lower-48 States, this could soon change. In September 2010, the US Department of Energy authorized Sabine Pass Liquefaction LLC (subsidiary of Cheniere Energy) to export approximately 2.2 BCFPD of US natural gas, over a 30 year period, beginning on or before
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CERI Commodity Report – Natural Gas
September 7, 2020.15 LNG exports from Sabine Pass are expected to begin in 2015, with an initial capacity of 1.2 BCFPD. Kitimat LNG (British Columbia), Freeport LNG (Texas), and Dominion Resources Inc. (Maryland) are also planning to export domestically sourced natural gas, in the form of LNG, by 2015. Relieving Downward Price Pressures With US natural gas supplies expected to exceed demand from traditional sectors (residential, commercial, industrial, and electric power) for many years to come, and working gas storage levels at near record highs, it is highly unlikely that natural gas prices will return to 2008 peak levels any time soon. Several factors, however, could relieve some of the downward pressure on natural gas prices. The first potential factor is a slowdown in natural gas production due to increasing regulatory costs placed on the industry (hydraulic fracturing regulations, post-Mocondo offshore drilling regulations). Second, if all four of the planned natural gas liquefaction facilities (Kitimat, Sabine Pass, Freeport, and Cove Point) are constructed on schedule, exports of surplus North American natural gas could begin as early as 2015. Finally, federal environmental regulations, or regional climate change programs, are likely to act as stimulants for natural gas demand growth, particularly in the electric power sector. Furthermore, if such regulations lead to policies that support the use of alternative transportation fuels, natural gas consumption in this unconventional demand sector could accelerate. Endnotes 1Wet natural gas proved reserves includes natural gas plant liquids. 2Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves 2009, U.S. Energy Information Administration, Office of Oil, Gas, and Coal Supply Statistics, U.S. Department of Energy, November 2010, http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/current/pdf/arrsummary.pdf, Accessed on February 5, 2011. 3Ibid. 4Ibid.
5Newell, Richard, Annual Energy Outlook 2011 Reference Case, Presentation to the Paul H. Nitze School of Advanced International Studies, U.S. Energy Information Administration, December 16, 2010. 6Ibid. 7AEO2011 Early Release Overview, U.S. Energy Information Administration, December 16, 2010, http://www.eia.gov/forecasts/aeo/pdf/0383er%282011%29.pdf, Accessed on February 5, 2011. 8Ibid. 9Chesapeake Energy Corporation and CNOOC Limited Announce Closing of Eagle Ford Shale Project Cooperation Agreement, Chesapeake Energy Corporation, News Release, November 15, 2010, http://www.chk.com/News/Articles/Pages/1496754.aspx, Accessed on February 6, 2011. 10Encana to establish joint venture with PetroChina through sale of 50 percent interest in Cutbank Ridge business assets for C$5.4 billion, News Release, Encana Corporation, February 9, 2011, http://www.encana.com/news/newsreleases/2011/0209-petrochina-jointventure.html, Accessed on February 10, 2011. 11Dittrick, Paula, WoodMac: Strong upstream M&A activity forecast in 2011, Oil and Gas Journal February 7, 2011, http://www.ogj.com/index/article-display.articles.oil-gas-journal.volume-109.issue-6.general-interest.woodmac-strong-upstream-m-a-activity.html, Accessed on February 8, 2011. 12T&T plans review of LNG sales to US, Upstream Online, February 7, 2011, http://www.upstreamonline.com/live/article243831.ece, Accessed on February 8, 2011. 13South Korea, Spain, Japan, Brazil, United Kingdom, Belgium, and India. 14DOE Authorizes Sempra to Re-Export LNG, DownstreamToday Staff, December 8, 2011, http://www.downstreamtoday.com/News/ArticlePrint.aspx?aid=24965, Accessed on February 8, 2011. 15True, Warren R., DOE approves LNG export from Sabine Pass terminal, Oil and Gas Journal, September 14, 2010, http://www.ogj.com/index/article-display/9890159905/articles/oil-gas-journal/transportation-2/lng/2010/09/doe-approves_lng_ export.html, Accessed on February 8, 2011.
Relevant • Independent • Objective
PAGE 5
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PAGE 7
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CERI Commodity Report - Natural Gas
PAGE 8
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PAGE 9
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Sta
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CERI Commodity Report - Natural Gas
PAGE 10
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Sta
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NEB.
SO
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Sta
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PAGE 11
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CERI.
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No
v-0
9J
an
-10
Mar-
10
May-1
0Ju
l-10
Sep
-10
No
v-1
0
Hu
nti
ng
do
nE
lmo
reM
on
ch
yK
ing
sg
ate
Canadian Gas Exports to the US
By Export Point -West
BC
FP
D
0123456789
10
No
v-0
9Jan
-10
Mar-
10
May-1
0Ju
l-10
Sep
-10
No
v-1
0
Oth
ers
Nia
gara
Iro
qu
ois
Em
ers
on
Canadian Gas Exports to the US
By Export Point -East
BC
FP
D
CERI Commodity Report - Natural Gas
PAGE 12
SO
URCE:
NEB.
SO
URCE:
NEB.
SO
URCE:
NEB,
EIA
.SO
URCE:
NEB.
02468
10
12
14
No
v-0
9Jan
-10
Mar-
10
May-1
0Ju
l-10
Sep
-10
No
v-1
0
Cali
forn
iaP
acif
ic N
WN
ort
he
as
tC
en
tral
US Imports of Canadian Gas
By US Region
BC
FP
D
02468
10
12
14
No
v-0
9J
an
-10
Mar-
10
Ma
y-1
0J
ul-
10
Se
p-1
0N
ov
-10
Pacif
ic N
WC
alifo
rnia
Cen
tra
lN
ort
hea
st
Average Canadian Export Price
By US Region
C$
/GJ
02468
10
12
14 No
v-0
9Jan
-10
Ma
r-10
May-1
0Ju
l-10
Sep
-10
No
v-1
0
Me
xic
oC
an
ad
a
Total US Pipeline Gas Imports
BC
FP
D
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
No
v-0
9J
an
-10
Ma
r-1
0M
ay-1
0J
ul-
10
Se
p-1
0N
ov
-10
Oth
er
St.
Cla
irS
arn
iaC
ou
rtri
gh
t
BC
FP
D
Canadian Gas Imports
By Import Point
In N
ove
mb
er,
57
.9 M
MC
FP
D o
f na
tura
l g
as w
as im
po
rte
d th
rou
gh
th
ree
tr
ad
itio
nalC
an
ad
ian
exp
ort
po
ints
-E
me
rso
n, I
roq
uo
is, a
nd
Nia
ga
ra.
Relevant • Independent • Objective
PAGE 13
SO
URCE:
CERI,
Pla
tts
Gas
Daily
.SO
URCE:
CERI,
Pla
tts
Gas
Daily
.
SO
URCE:
CERI,
Pla
tts
Gas
Daily
.SO
URCE:
CERI,
Pla
tts
Gas
Daily
.
0
10
0
20
0
30
0
40
0
50
0
60
0
70
0
JF
MA
MJ
JA
SO
ND
5-Y
ea
r A
vg
.20
10
20
11
BC
F, M
on
th E
nd
Canadian Working Gas Storage
0
100
200
300
400
500
600
700
Jan
-10
Mar-
10
May-1
0Ju
l-10
Sep
-10
No
v-1
0Jan
-11
Ea
st
We
st
Canadian Storage by Region
BC
F, M
on
th E
nd
0
500
1,0
00
1,5
00
2,0
00
2,5
00
3,0
00
3,5
00
4,0
00
4,5
00
JF
MA
MJ
JA
SO
ND
5-Y
ea
r A
vg
.2
01
02
011
BC
F, M
on
th E
nd
US Lower-48 Working Gas Storage
0
50
0
1,0
00
1,5
00
2,0
00
2,5
00
3,0
00
3,5
00
4,0
00
4,5
00
Ja
n-1
0M
ar-
10
May-1
0Ju
l-10
Sep
-10
No
v-1
0Ja
n-1
1
Pro
du
cin
g R
eg
ion
We
st
Ea
st
BC
F, M
on
th E
nd
US Storage by Region
CERI Commodity Report - Natural Gas
PAGE 14
SO
URCE:
CERI,
Pla
tts
Gas
Daily
.SO
URCE:
CERI,
Pla
tts
Gas
Daily
.
SO
URCE:
CERI,
Pla
tts
Gas
Daily
.
-80
-60
-40
-200
20
40
60
80
JF
MA
MJ
JA
SO
ND
5-Y
ea
r A
vg
.2
010
20
11
Eastern Canadian Storage
Injections/Withdrawals
BC
F, M
on
th E
nd
-150
-100
-500
50
100
150
JF
MA
MJ
JA
SO
ND
5-Y
ea
r A
vg
.2
01
02
011
Canadian Storage
Injections/Withdrawals
BC
F, M
on
th E
nd
North American Storage
•Can
ad
ian
work
ing
gas
sto
rag
ele
vels
en
ded
the
mon
tho
fJan
uary
at
38
0.7
BC
F,
ap
pro
xim
ate
ly2
perc
en
tab
ove
the
five-y
ear
avera
ge.
•Sin
ce
the
sta
rtof
the
20
10
/2011
win
ter
he
atin
gse
ason
,C
an
ad
ian
natu
ralg
as
sto
cks
have
declin
ed
by
40
perc
en
t,or
25
3.3
BC
F.
•Natu
ralg
as
sto
rag
ew
ith
dra
wals
ine
aste
rnC
an
ad
aaccou
nte
dfo
r5
9p
erc
en
tof
tota
lw
ith
dra
wals
from
Can
ad
ian
sto
rag
ed
uri
ng
Jan
uary
.
•Accord
ing
toth
eE
IA,
the
tota
lvolu
me
of
work
ing
gas
inU
Su
nd
erg
rou
nd
sto
rag
ew
as
2,3
53
BC
Fas
of
Jan
uary
28
.
•Du
ring
the
mon
thof
Jan
uary
,7
44
BC
Fof
natu
ral
gas
was
with
dra
wn
from
US
sto
rag
e,
com
pare
dto
87
0B
CF
du
rin
gth
esam
em
on
thla
st
year.
•Sto
rag
ew
ith
dra
wals
from
the
easte
rncon
su
min
gre
gio
naccou
nte
dfo
r5
7p
erc
en
to
f
the
tota
lw
ith
dra
wal
from
US
sto
rag
e.
•Net
sto
rag
ew
ith
dra
wals
inth
eU
Sp
rod
ucin
gre
gio
nan
dw
este
rncon
su
min
gre
gio
nam
ou
nte
dto
22
3B
CF
an
d9
6B
CF,re
sp
ectively
.
•Betw
een
Novem
ber
20
10
an
dJan
uary
20
11,
1,4
68
BC
Fof
natu
ral
gas
wa
sw
ith
dra
wn
from
US
un
derg
rou
nd
sto
rag
e,
com
pare
dto
1,3
82
BC
Fd
uri
ng
the
sam
e
peri
od
last
year.
•Th
eE
IAe
xpects
an
oth
er
70
2B
CF
of
natu
ralg
as
tob
ew
ith
dra
wn
from
un
de
rgro
un
dsto
rag
eb
yth
een
dof
Marc
h.
-100
-80
-60
-40
-200
20
40
60
80
JF
MA
MJ
JA
SO
ND
WC
_IJ
_W
D
5-Y
ea
r A
vg
.2
01
02
011
BC
F, M
on
th E
ndWestern Canada Storage
Injections/Withdrawals
Relevant • Independent • Objective
PAGE 15
SO
URCE:
CERI,
Pla
tts
Gas
Daily
.SO
URCE:
CERI,
Pla
tts
Gas
Daily
.
SO
URCE:
CERI,
Pla
tts
Gas
Daily
.SO
URCE:
CERI,
Pla
tts
Gas
Daily
.
-10
0
-80
-60
-40
-200
20
40
60
80
10
0
JF
MA
MJ
JA
SO
ND
5-Y
ea
r A
vg
.2
010
20
11
US Western Consuming Region Storage
Injections/Withdrawals
BC
F, M
on
th E
nd
-700
-500
-300
-100
10
0
30
0
50
0
JF
MA
MJ
JA
SO
ND
5-Y
ear
Av
g.
20
10
20
11
US Eastern Storage
Injections/Withdrawals
BC
F, M
on
th E
nd
-250
-200
-150
-100
-500
50
100
150
200
JF
MA
MJ
JA
SO
ND
5-Y
ea
r A
vg
.20
10
20
11
US Producing Region Storage
Injections/Withdrawals
BC
F, M
on
th E
nd
-100
0
-800
-600
-400
-2000
20
0
40
0
60
0
80
0
JF
MA
MJ
JA
SO
ND
5-Y
ear
Av
g.
20
10
20
11
US Storage
Injections/Withdrwals
BC
F, M
on
th E
nd
CERI Commodity Report - Natural Gas
PAGE 16
SO
URCE:
U.S
. D
OE.
SO
URCE:
U.S
. D
OE.
SO
URCE:
U.S
. D
OE.
SO
URCE:
U.S
. D
OE.
02468
10
12
14
16
18
20
22
24
Dec-0
9F
eb
-10
Ap
r-10
Ju
n-1
0A
ug
-10
Oct-
10
Dec-1
0
Co
ve P
oin
tE
lba
Isla
nd
Eve
rett
NE
Ga
tew
ay
Ne
ptu
ne
Eastern US LNG Imports By Facility
BC
F
02468
10
12
14
16
18
20
22
24
Dec
-09
Fe
b-1
0A
pr-
10
Ju
n-1
0A
ug
-10
Oct-
10
Dec-1
0
Gu
lf G
ate
wa
yF
ree
po
rtL
ak
e C
ha
rle
s
Sab
ine
Pas
sC
am
ero
nG
old
en
Pa
ss
US GoM LNG Imports By Facility
BC
F
05
10
15
20
25
30
35
40
Dec
-09
Feb
-10
Ap
r-10
Ju
n-1
0A
ug
-10
Oct-
10
Dec-1
0
Eg
yp
tN
ige
ria
Tri
nid
ad
No
rwa
yQ
ata
rY
em
en
Pe
ru
BC
F
US LNG Imports By Origin
Trinid
ad
& T
ob
ago is e
xpecte
d to
re
str
uctu
re lo
ng
-term
LN
G s
upply
co
ntr
acts
with the U
S to inculd
e
destination
flexib
ility
cla
uses.
02468
10
12
14
JF
MA
MJ
JA
SO
ND
200
82
00
92
01
0
Volume-Weighted Average LNG Price
Volume-Weighted Average LNG Price
US
$/M
MB
tu
Relevant • Independent • Objective
PAGE 17
SO
URCE:
EIA
, U
.S.
DO
E.
SO
URCE:
U.S
. D
OE.
SO
URCE:
U.S
. D
OE,
NEB.
SO
URCE:
U.S
. D
OE.
LNG Importers in 2010
Ca
nad
ian
LN
G Im
po
rters
in 2
010
(A
s o
f N
ove
mb
er
30
, 20
10
)
Co
mp
an
yV
olu
me
(B
CF
)%
of
To
tal L
NG
Im
po
rts
Rep
sol E
ne
rgy C
ana
da L
td.
69.1
100
To
tal
69.1
100
US
LN
G Im
po
rte
rs in
20
10
(A
s o
f D
ece
mb
er
31, 2
01
0)
Co
mp
an
yV
olu
me (B
CF
)%
of
To
tal L
NG
Im
po
rts
BG
LN
G S
erv
ice
s145
.53
3.8
Dis
trig
as
145
.13
3.7
Excele
rate
14.7
3.4
Sta
toil
31.6
7.3
BP
Ene
rgy C
om
pa
ny
8.8
2.0
To
tal G
as &
Po
we
r2
6.3
6.1
Sem
pra
LN
G M
ark
eting
7.0
1.6
Che
vro
n U
.S.A
.8.9
2.1
Shell
NA
LN
G3.0
0.7
Con
oco
Phill
ips
12.2
2.8
Che
nie
re M
ark
etin
g
3.2
0.7
Go
lde
n P
ass L
NG
13.0
3.0
JP
Morg
an
LN
G6.4
1.5
GD
F S
ue
z G
as N
A5.2
1.2
To
tal
431
.01
00
.0
US LNG Shippers in 2010
US
LN
G S
hip
pe
rs in
20
10
(A
s o
f D
ec
em
be
r 3
1, 2
01
0)
Co
mp
an
yV
olu
me
(B
CF
)%
of
To
tal L
NG
Sh
ipm
en
ts
Atla
ntic L
NG
2/3
Co
mp
an
y7
.41
.7A
tla
nti
c L
NG
Co
mp
an
y5
7.9
13
.4B
G9
.12
.1E
LN
G/B
GG
M5
6.2
13
.0
Ga
s N
atu
ral A
pro
vis
ion
am
ien
tos
36
.08
.3A
tla
ntic L
NG
8.8
2.0
Nig
eri
a L
NG
Lim
ite
d3
0.1
7.0
PF
LE
17
.24
.0T
rin
ling
17
.24
.0S
he
ll E
aste
rn L
NG
3.0
0.7
GD
F S
ue
z1
4.1
3.3
Ra
sG
as L
NG
8.9
2.1
Ra
sG
as
20
.14
.7Q
ata
r L
iqu
efie
d G
as C
om
pa
ny L
imite
d (II
)1
3.8
3.2
Ra
s L
aff
an
2.8
0.6
Sta
toil
AS
A, R
WE
-De
a N
org
e A
S,
He
ss N
org
e A
S5
.81
.4B
G G
as M
ark
etin
g L
td3
.00
.7S
tato
il A
SA
22
.85
.3Y
em
en
LN
G C
om
pa
ny L
td.;
TO
TA
L G
as &
Po
we
r L
td.
12
.52
.9
To
tal G
as &
Po
we
r L
imite
d5
.81
.4G
DF
Su
ez
Su
pp
ly2
3.7
5.5
BG
GS
TL
/BG
LT1
9.0
4.4
Atla
ntic L
NG
2/3
Co
mp
an
y11
.22
.6S
he
ll N
A L
NG
2.9
0.7
BP
En
erg
y C
om
pa
ny
2.8
0.6
BG
LN
G T
rad
ing
LL
C2
.90
.7R
ep
so
l Co
me
rcia
liza
do
ra d
e G
as S
A1
6.0
3.7
To
tal
43
1.0
10
0.0
01234567
Dec-0
9F
eb
-10
Ap
r-10
Ju
n-1
0A
ug
-10
Oct-
10
Dec-1
0
US LNG Exports to Japan
BC
F
01234567
De
c-0
9F
eb
-10
Ap
r-10
Ju
n-1
0A
ug
-10
Oct-
10
Dec-1
0
Co
no
co
Ph
illi
ps
Ma
rath
on
US LNG Exports
By Exporter
BC
F
Aft
er4
1 y
ears
of
opera
ting in
Ala
ska's
Coo
k Inle
t, C
onocoP
hill
ips h
as
announced
that th
e K
enai L
NG
, th
e o
nly
exis
ting U
S li
qu
efa
ction
facili
ty, w
ill b
e c
losin
g a
s e
arl
y a
s A
pril 2011
. T
he inabili
ty to
renew
supply
con
tracts
with J
apan
, and r
egio
nal n
atu
ral g
as s
upply
concern
s
have b
een
cited a
s reason
s for th
e c
losure
.
CERI Commodity Report - Natural Gas
PAGE 18
SO
URCE:
CERI,
CAO
DC,
Bake
r H
ughes.
SO
URCE:
CERI,
CAO
DC.
SO
URCE:
CERI,
CAO
DC.
SO
URCE:
CERI,
CAO
DC.
0
500
1,0
00
1,5
00
2,0
00
2,5
00
3,0
00 Jan
-02
Jan
-03
Jan
-04
Jan
-05
Jan
-06
Jan
-07
Jan
-08
Jan
-09
Jan
-10
Jan
-11
WC
SB
US
North American Active Rigs
Rig
s
0
100
200
300
400
500
600
700
800
900
1,0
00 Jan
-02
Jan
-03
Jan
-04
Jan
-05
Jan
-06
Jan
-07
Jan
-08
Jan
-09
Ja
n-1
0J
an
-11
Acti
ve
Rig
sT
ota
l Rig
Dri
llin
g F
lee
t
Canadian Rig Fleet Utilization
Weekly Average Active Rigs
Rig
s
0
100
200
300
400
500
600
700 Jan
-08
Ap
r-08
Au
g-0
8D
ec-0
8A
pr-
09
Au
g-0
9D
ec-0
9A
pr-
10
Au
g-1
0D
ec-1
0
BC
AB
SK
WCSB Active Rigs by Province
Weekly Average
Rig
s
-
10
0
20
0
30
0
40
0
50
0
60
0
70
0
80
0
15
91
317
21
25
29
33
37
41
45
49
5-Y
ear
Av
g.
20
10
20
11
Western Canada Active Rigs
Weekly Average
Rig
s
Week
Nu
mb
er
Relevant • Independent • Objective
PAGE 19
SO
URCE:
CERI,
Bake
r H
ughes.
SO
URCE:
CERI,
Bake
r H
ughes.
SO
URCE:
CERI,
Bake
r H
ughes.
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0
200
400
600
800
1,0
00
1,2
00
1,4
00
1,6
00
1,8
00
2,0
00
2,2
00 Ja
n-0
2J
an
-03
Jan
-04
Ja
n-0
5J
an
-06
Ja
n-0
7Jan
-08
Jan
-09
Ja
n-1
0J
an
-11
Oil
-Dir
ec
ted
Ga
s-D
ire
cte
dG
as
-Dir
ec
ted
%
US Total Active Rigs
Rig
s
0
500
1,0
00
1,5
00
2,0
00
2,5
00 Ja
n-0
2Jan
-03
Ja
n-0
4Ja
n-0
5J
an
-06
Ja
n-0
7J
an
-08
Jan
-09
Jan
-10
Jan
-11
On
sh
ore
Gas
-Dir
ec
ted
GO
M G
as
-Dir
ec
ted
To
tal O
il-D
ire
cte
d
Rig
s
US Total Active Rigs
0
20
40
60
80
100
120
140 Jan
-02
Jan
-03
Jan
-04
Jan
-05
Ja
n-0
6Jan
-07
Jan
-08
Jan
-09
Jan
-10
Jan
-11
Oil-D
irec
ted
Ga
s-D
ire
cte
d
US Gulf of Mexico Active Rigs
Rig
s
North American Rig Activity
•Th
eavera
ge
WC
SB
rig
utiliz
ation
rate
du
rin
gth
efo
urt
hq
uart
er
of
20
10
was
50
perc
en
t,com
pare
dto
33
perc
en
td
urin
gth
efo
urt
hq
uart
er
of
20
09
.
•In
Jan
uary
,th
eW
CS
Bri
gutiliz
ation
rate
was
66
perc
en
t.
•Mon
th-o
ver-
mon
th,
the
WC
SB
rig
activity
has
incre
ased
by
32
perc
en
t,fr
om
an
avera
ge
of
393
rig
sin
Decem
ber
to5
21
rig
sin
Jan
uary
.
•A
lbert
aaccou
nte
dfo
rn
early
81
perc
en
tof
the
tota
lin
cre
ase
inth
em
onth
lyW
CS
B
rig
activity.
•D
uri
ng
the
mon
tho
fJan
uary
,th
eavera
ge
nu
mb
er
of
rig
sop
era
tin
gin
Saskatc
hew
an
and
Bri
tish
Colu
mb
iain
cre
ased
by
8an
d12
,re
sp
ectively
.
•Th
em
on
thly
avera
ge
US
rota
ryri
gcou
nt
was
1,7
11
inJan
uary
,up
35
perc
en
t,o
r
44
5rig
s,fr
om
the
sam
ep
eri
od
last
year.
•In
Jan
uary
,n
atu
ralg
as
dir
ecte
dri
gactivity
was
resp
on
sib
lefo
r5
3p
erc
en
tof
the
tota
l
US
rig
cou
nt,
com
pare
dto
65
perc
en
tla
st
year.
•US
natu
ral
gas
directe
dri
gactivity
declin
ed
from
an
avera
ge
of
94
0rig
sin
Decem
ber,
to9
09
rig
sin
Jan
uary
.
•Th
eavera
ge
nu
mb
er
of
na
tura
lg
as
dir
ecte
doffsh
ore
rigs
incre
ased
by
4,
on
sh
ore
rig
sd
eclin
ed
by
36
rig
s.
•Sin
ce
Decem
ber,
US
oil
directe
dri
gactivity
incre
ased
by
an
avera
ge
of
4p
erc
en
t,or
34
rig
s,to
79
3ri
gs.