ceri commodity report – natural gas · ceri commodity report – natural gas figure 2: map of...

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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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


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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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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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.


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ate

Canadian Gas Exports to the US

By Export Point -West

BC

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10

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v-0

9Jan

-10

Mar-

10

May-1

0Ju

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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


PAGE 12

SO

URCE:

NEB.

SO

URCE:

NEB.

SO

URCE:

NEB,

EIA

.SO

URCE:

NEB.

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US Imports of Canadian Gas

By US Region

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Average Canadian Export Price

By US Region

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/GJ

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Me

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Total US Pipeline Gas Imports

BC

FP

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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

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JA

SO

ND

5-Y

ea

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vg

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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

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ar-

10

May-1

0Ju

l-10

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-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


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


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

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en

to

f

the

tota

lw

ith

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from

US

sto

rag

e.

•Net

sto

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ew

ith

dra

wals

inth

eU

Sp

rod

ucin

gre

gio

nan

dw

este

rncon

su

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nam

ou

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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



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


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


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


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


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

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16

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20

22

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Dec-0

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ve P

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Eastern US LNG Imports By Facility

BC

F

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16

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20

22

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20

25

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35

40

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Volume-Weighted Average LNG Price

Volume-Weighted Average LNG Price

US

$/M

MB

tu


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

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toil

31.6

7.3

BP

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rgy C

om

pa

ny

8.8

2.0

To

tal G

as &

Po

we

r2

6.3

6.1

Sem

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LN

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ark

eting

7.0

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Che

vro

n U

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.8.9

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Shell

NA

LN

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0.7

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Phill

ips

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2.8

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nie

re M

ark

etin

g

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0.7

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lde

n P

ass L

NG

13.0

3.0

JP

Morg

an

LN

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1.5

GD

F S

ue

z G

as N

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1.2

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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

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tal L

NG

Sh

ipm

en

ts

Atla

ntic L

NG

2/3

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mp

an

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c L

NG

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mp

an

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7.9

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LN

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GG

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13

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Ga

s N

atu

ral A

pro

vis

ion

am

ien

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36

.08

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tla

ntic L

NG

8.8

2.0

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eri

a L

NG

Lim

ite

d3

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7.0

PF

LE

17

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rin

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17

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he

ll E

aste

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NG

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GD

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as L

NG

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Ra

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as

20

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efie

d G

as C

om

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imite

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s L

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A, R

WE

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ez

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GS

TL

/BG

LT1

9.0

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Atla

ntic L

NG

2/3

Co

mp

an

y11

.22

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he

ll N

A L

NG

2.9

0.7

BP

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erg

y C

om

pa

ny

2.8

0.6

BG

LN

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rad

ing

LL

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0.0

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Dec-0

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eb

-10

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10

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US LNG Exports to Japan

BC

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-10

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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

.


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


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.

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