louisiana’s natural gas advantage: can we hold it? grow it ......center for energy studies natural...

Louisiana’s Natural Gas Advantage: Can We Hold It? Grow It? Or Do We Need to be Worrying About Other Problems?

LCA/LCIA Annual Legislative Conference

David E. Dismukes, Ph.D.C t f E St di

LCA/LCIA Annual Legislative ConferenceMay 5, 2011

Center for Energy StudiesLouisiana State University

Center for Energy Studies


Pricing Trends: A Series of Different “D li ”“Decouplings”

2© LSU Center for Energy Studies

C d Oil d N t l G P i

Center for Energy Studies Pricing Trends

Crude Oil and Natural Gas Prices

Prices say a lot about what has been going on in energy markets over the past decade. Two significant breaks (decoupling) of natural gas and crude oil prices.

$14

$16

$140

$160

First price decoupling:

Recession

$8

$10

$12

$80

$100

$120

il ($

/Bbl

)N

atural Ga

Gas Up, Crude Down

$4

$6

$8

$40

$60

$80

Cru

de O

as ($/Mcf)

$0

$2

$0

$20

J 99 J 01 J 03 J 05 J 07 J 09 J 11

Second price decoupling: Crude Up, Gas Down

Jan-99 Jan-01 Jan-03 Jan-05 Jan-07 Jan-09 Jan-11

Crude Oil (WTI) Natural Gas (Henry Hub)

Source: Federal Reserve Bank 3© LSU Center for Energy Studies

T d W i ht d V l f C d Oil


Trade Weighted Value of Crude Oil

$ 0$160

Second decoupling has been associated with the exchange‐weighted differences in crude oil prices.

$30

$35

$40

$120

$140

$160 QE1:Nov-2008

to Mar-2010

QE2:Nov-2010to ~Jun-

2011

$35/BBl exchange rate‐related

differential in crude

$20

$25

$80

$100

il ($

/Bbl

)D

ifferenti

prior to recession

$5

$10

$15

$20

$40

$60

Cru

de O

al ($/Bbl)

$25/BBl exchange rate‐related

$0

$5

$0

$20

Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11

$ 5/ l exchange rate relateddifferential and growing.


Price of Crude Oil (WTI) Adjusted Price of Crude Oil Differential

Note: The adjusted price of crude oil is the nominal WTI adjusted by the Federal Reserve Bank’s Broad Index. The Broad Index is a weighted average of the foreign exchange values of the U.S. dollar against the currencies of a large group of major U.S. trading partners. Base year is 2002.Source: Federal Reserve Bank.

C d Oil P i D ti (WTI) d I t ti l (B t)


Crude Oil Prices – Domestic (WTI) and International (Brent)

Additional decoupling has materialized between domestic crude (WTI) and international priced crude (Brent)

$120

$140 Deepwater Horizon Spill

2011 Libyan Civil War

and international priced crude (Brent).

$80

$100

($/B

bl)

$40

$60

Cru

de O

il

2011 Egyptian Revolution

$0

$20

Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Jan-11 Mar-11


Ja 0 a 0 ay 0 Ju 0 Sep 0 o 0 Ja a

WTI Brent

Source: Energy Information Administration, U.S. Department of Energy


Rig MovementsRig Movements



D ti d I t ti l Ri C t

Rig Movements

Domestic and International Rig Counts

Recent changes in crude oil prices are leading to a rebound in overall U.S. rig count from 2008‐2009 recession.

200

250

250

300

0=10

0)Internation

150

200

150

200

anua

ry 2

000

nal Rig C

oun

50

100100

150

Rig

Cou

nt (J

t (January 20

0

50

0

50

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

U.S

. 000=100)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

U.S. Europe Middle East and Africa Asia Pacific Latin America

7Source: Baker Hughes.


D ti Ri C t O h Off h

Rig Movements

Domestic Rig Counts – Onshore vs. Offshore

Onshore rig counts are moving close to their pre‐recession levels, primarily motivated by increased crude oil drilling, not natural gas.

160

180

200

2 000

2,500

ntU

Deepwater Horizon Spill

y g, g

100

120

140

160

1,500

2,000

ore

Rig

Cou

nU

.S. O

ffshore

40

60

80

100

500

1,000

U.S

. Ons

hoe R

ig Count

0

20

02000 2002 2004 2006 2008 2010

Onshore Offshore

8Source: Baker Hughes.


D ti Ri C t C d Oil N t l G

Rig Movements

Domestic Rig Count – Crude Oil vs. Natural Gas

However, for the first time in 16 years, the number of oil rigs is equivalent to gas rigs.

80%

90%

100%

50%

60%

70%

Tota

l Rig

s

Gas Rigs

30%

40%

50%

Per

cent

of

Oil Rigs

0%

10%

20%Oil Rigs

9

Jul-87 Jul-90 Jul-93 Jul-96 Jul-99 Jul-02 Jul-05 Jul-08

Source: Baker Hughes.


Supply ImplicationsSupply Implications


U S C d Oil P d R d P d ti

Center for Energy Studies Supply Implications

U.S. Crude Oil Proved Reserves and Production

Crude oil reserves holding steady between 22 to 20 BBbls since 1995.DWRRA (1995) helped reverse a deteriorating trend in GOM reserve declines.

s)

3.5

4.0

35

40

Probi

llion

bar

rels

2 0

2.5

3.0

20

25

30

oduction (billR

eser

ves

(

1.0

1.5

2.0

10

15

20 ion barrels)

Deepwater Royalty Relief Act (1995) resulted in 1.6 Bbbls in

reserve growth (1998-2002)

0.0

0.5

0

5

1973 1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009

Source: Energy Information Administration, U.S. Department of Energy 11© LSU Center for Energy Studies

Reserves Production

U S N t l G P d ti d P d R J 2007 t P t


U.S. Natural Gas Production and Proved Reserves, January 2007 to Present

2006‐2007 reserves growth is the largest in over 30 years. On average, natural gas reserves have been increasing by 5 percent per year since 2000

25

30

250

300

g y p p y(except 2004‐2005 tropical season, 2 percent).

20

25

200

250

es (T

cf)P

roduc

10

15

100

150

Res

erve

tion (Tcf)

Proved gas reserves at 272.5 Tcf, their

highest level.

0

5

0

50

1973 1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 20091973 1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009

Reserves Production

Source: Energy Information Administration, U.S. Department of Energy. 12© LSU Center for Energy Studies

W ld C d Oil P d ti d R


World Crude Oil Production and Reserves

Supply fundamentals suggest that the market is not that tight, and has responded quickly to anticipated demand rather than some fundamental current supply shortfalls.q y p pp y

25

30

1,400

1,600

on b

arre

ls)

20

25

1,000

1,200

,

Production

eser

ves

(bill

io

10

15

400

600

800

(billion barreR

e

0

5

0

200

400

1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010

els)


1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010

Reserves Production

W ld C d Oil P d ti t R R ti


World Crude Oil Production to Reserve Ratio

Reserves to production ratios continue to remain strong, and in fact, have actually grown over the past several years.

Rat

io 50

60

have actually grown over the past several years.

Prod

uctio

n R

30

40

Res

erve

s to

P

20

30

R

0

10

1980 1983 1986 1989 1992 1995 1998 2001 2004 2007


W ld S l C d Oil P d ti C it


World Surplus Crude Oil Production Capacity

Global spare production capacity has also been growing, even prior to the most recent recession. Forecasted capacity is anticipated to remain strong.

) $100

$120

5

6

on (M

MB

bl/d

)

$80

$100

4

5

Price

are

Pro

duct

io

$40

$60

2

3

e ($/Bbl)

Spa

$0

$20

0

1

1997 1999 2001 2003 2005 2007 2009 2011

Note: Data is for OPEC Countries only (Algeria, Angola, Ecuador, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, the United Arab Emirates, Venezuela).Source: Energy Information Administration, U.S. Department of Energy 15© LSU Center for Energy Studies

1997 1999 2001 2003 2005 2007 2009 2011

Spare Capacity World Oil Price

W ld id T bl S t P t ti l I t P d ti


Worldwide Trouble Spots – Potential Impact on Production

Production in Trouble Spots: 14.6 MMBbl/dForecast World Growth (2015): 1.5 MMBbl/dForecast World Growth (2020): 4.8 MMBbl/d

North KoreaRussian and

Caucasus Pipelinesbl/d

Iraq

1.2 MMBbl/day

Iran4.2 MMBbls/dayLibya

1 8 MMBbl/day

Venezuela2.5 MMBbl/day

Nigeria2.2 MMBbl/day

Iraq2.4 MMBbl/day

1.8 MMBbl/day

/ y


Iraqi instabilityNigerian civil strife

Venezuelan oil strike

P t l D d W ld U S d Chi


Petroleum Demand – World, U.S. and China

Major concern is anticipated Chinese demand for energy. US demand has been decreasing even prior to the recent recession.g p

90

10025

a (M

MB

bl/d

)

50

60

70

80

15

20

World (M

U.S. demand down by 1.7 MMBbl/d or 8 percent (2005-2010)

.S. a

nd C

hin

20

30

40

50

5

10

MM

Bbl/d)Chinese demand up 1.7 MMBbl/d or

25 percent (2005-2010)

U

0

10

20

0

5

1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010


U.S. China World

C d Oil C ti GDP W ld U S d Chi


Crude Oil Consumption per GDP – World, U.S. and China

While Chinese demand has been growing, efficiency improvements have been considerable over the past two decades.

d/bi

llion

$)

10

12

p

GD

P (M

bbls

d

6

8

umpt

ion

per G

2

4

Con

su

0

2

1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010

Source: Energy Information Administration, U.S. Department of Energy; and International Monetary Fund. 18© LSU Center for Energy Studies

U.S. China World


Policy Issue 1:N t l G UNatural Gas Uses


N t l G V hi l

Center for Energy Studies Natural Gas Uses

Natural Gas Vehicles

• A natural gas vehicle (“NGV”) uses compressed natural gas (“CNG”) or, less commonly, liquefied natural gas (“LNG”) as a clean alternative to other automobile fuels.

• CNG releases over 1.6 times as much energy as that released from petroleum based fuels (or for the same amount of energy, CNG produces nearly 40 percent less CO2).

• In 2008, NGVs used 215 million gasoline-equivalent gallons. To compare, total gasoline usage in 2008 was 55 million gallons per day, or a total of 20 billion gallons.

• Currently in the U.S., about 12 to 15 percent of public transit buses in run on natural gas (either CNG or LNG).

• States with the highest consumption of natural gas for transportation are California, New York, Texas, Georgia,Massachusetts and D.C.


• One major limitation is that CNG vehicles require a greater amount of space for fuel storage.

N t l G C ti b S t


Natural Gas Consumption by Sector

Currently, NGVs account for less than 0.18 percent of U.S. natural gas consumption, but the rate of growth in consumption (158 percent) over the past

30

35

8

9

Tcf)

decade has surpassed all other end‐uses.

20

25

30

5

6

7

nsum

ptio

n (T N

GV

Cons

10

15

2

3

4

5

tura

l Gas

Co um

ption (Bcf

-

5

-

1

2

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Nat

f)


1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Residential Commercial Industrial Electric Power NGV


R t il G li P i d N t l G GGE


Retail Gasoline Prices and Natural Gas GGE

Basic economics, primarily lower relative prices, have played an important role in driving recent increases in natural gas vehicle use.

$3.50

$4.00

$2.00

$2.50

$3.00

Gal

lon

$1.00

$1.50$ pe

r

$0.00

$0.50

Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11

22© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy

Gasoline Natural Gas (GGE)

T NGV St t


Top NGV States

Most of the leading NGV states are not major producing states. Top 10 NGV states account for almost 90 percent of all U S NGV natural gas useaccount for almost 90 percent of all U.S. NGV natural gas use.

NGV CurrentNatural Gas Gasoline

Consumption Prices(MMcf) ($/gal)

California 13,132 4.30$ $New York 3,798 4.19$

Arizona 2,234 3.45$ Texas 2,206 3.91$ Georgia 1,205 3.66$ Maryland 1,078 3.83$ Massachusetts 850 3.99$ Washington 553 4.07$ Nevada 492 3.76$ Pennsylvania 325 3.79$

U S 29 150 4 01$


U.S. 29,150 4.01$

L di St t i NGV P f


Leading States in NGV Preferences

Many of these same states also have generous incentive programs that range from additional tax incentives, to infrastructure grant support. Federal benefits include alternative fuel infrastructure tax credit an excise alternative fuel tax credit and analternative fuel infrastructure tax credit, an excise alternative fuel tax credit and an

alternative fuel tax exemption.

Alternative fuel tax credits and/or infrastructure development credits

24© LSU Center for Energy StudiesSource: U.S. Department of Energy

p

Alternative fuel use and infrastructure grant support

P t ti l N t l G C ti NGV


Potential Natural Gas Consumption – NGV

NGV consumption of natural gas is estimated to increase at an average annual rate of 7 percent through 2035 At best this usage will be considerably less than 1 Tcf

0.70%0.18

f)

of 7 percent through 2035. At best, this usage will be considerably less than 1 Tcfand slightly over one‐half of one percent of total natural gas market.

N

0 40%

0.50%

0.60%

0 10

0.12

0.14

0.16

sum

ptio

n (T

cfN

GV

ConsumNGV use of natural

0.20%

0.30%

0.40%

0 04

0.06

0.08

0.10

ral G

as C

ons

mption (%

of T

gas will stay below one percent of total U.S. natural gas consumption.

0.00%

0.10%

0.00

0.02

0.04

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Nat

urTotal)


2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Consumption Percent of Total


U S P G ti F l Mi


U.S. Power Generation – Fuel Mix

Over 250,000 MWs of natural gas power generation capacity has been added over the past decade at the expense of coal and nuclear.

Petroleum Other Other Petroleum

2000 2010

Petroleum3%

Other1% 1% 1%

Renewables 9% Renewables 10%

Coal51%

Natural Gas16% Coal

45%Nuclear

19%

Nuclear20%

Natural Gas24%



El t i I d t E i t l R l ti C t U t i t f C lElectric Industry Environmental Regulations Create Uncertainty for Coal

National Ambient Air Quality Standards (NAAQS)• Sets acceptable levels for six criteria pollutants (carbon monoxide, lead, nitrogen dioxide, particulate matter, ozone,

lf di id )sulfur dioxide).• A network of 4,000 State and Local Air Monitoring Stations is used to determine if geographic areas are meeting or

exceeding the NAAQS.

Transport Rule (CATR) [proposed]p ( ) [p p ]• Issued to replace the Clean Air Interstate Rule (CAIR) and require 31 states (and D.C.) to improve air quality by reducing

power plant emissions (SO2 and NOX) that contribute to ozone and fine particulate pollution in other states.• By 2014, the rule and other state and EPA actions would reduce power plant SO2 emissions by 71% over 2005 levels.

Power plant NOx emissions would drop by 52%.

Utility Maximum Achievable Control Technology (MACT) [to be proposed]• EPA must set emission limits for hazardous air pollutants. The rule is expected to replace the Clean Air Mercury Rule

(CAMR) and add standards for lead, arsenic, acid gases, dioxins and furans.

Coal Combustion Residuals (CCR) [proposed]Coal Combustion Residuals (CCR) [proposed]• Would establish, for the first time under the Resource Conservation and Recovery Act (RCRA) requirements for the

proper disposal of coal ash generated by coal combustion at electric power plants.

Power Plant Cooling Water Intake Structures RuleS ti 316(b) f th Cl W t A t i i t d d t dd i t l i t f li t i t k t d• Section 316(b) of the Clean Water Act is intended to address environmental impacts from cooling water intake to and discharge from power plant cooling systems. Requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact.

27

C l Fi d C it Sh b A C t


Coal-Fired Capacity Share by Age Category

There is a considerable amount of legacy coal capacity (45 GWs) that is relatively old, and in some instances, has few to little controls to meet anticipated standards.

Less than 30 years:79,876 MW; 22% of capacity;

Greater than 50 years:45,382 MW; 12% of capacity;

, p

73 plants (averaging 1,094 MW)72 units (averaging 630 MW)

30 to 50 years:238,934 MW; 66% of capacity;

208 plants (averaging 1,149 MW)


C l Fi d C it Sh b H t R t


Coal-Fired Capacity Share by Heat Rate

Despite the age, many of these assets operate at relatively competitive fuel efficiencies for older steam generators.

Less than 10,000 Btu/kWh:85,507 MW; 23% of

Over 15,000 Btu/kWh:2 958 MW; 1% of 85,507 MW; 23% of

capacity;57 plants (averaging 1,500 MW)

2,958 MW; 1% of capacity;13 units (averaging 228 MW)

10 000 t 13 000 Bt /kWh

13,000 to 15,000 Btu/kWh:2,103 MW; 1% of

it 10,000 to 13,000 Btu/kWh:273,625 MW; 75% of capacity;

272 plants (averaging 1,006 MW)

capacity;11 plants (averaging 191 MW)



Summary of Retirement Studies Related to EPA RulesSummary of Retirement Studies Related to EPA Rules

Study Retired Capacity Regulation Requirements

Levelized costs (@2008 CF) after retrofitting each unit for the environmental regulations compared to the cost of a new gas-fired unit

80Estimated GW of Retired Coal

10 20 30 40 50 60 70

Scenario 1 - Transport Rule

Scenario 2 - Transport Rule, MACTScenario 3 - Transport Rule, MACT, 316(b) Cooling Water, Coal Ash

Cost of retrofitting coal plant compared to cost of new CC

fired unit.NERC (October 2010)

47 to 76 GW by 2018 (total fossil fuel capacity, including oil and gas)

Scenario 1 - Transport Rule, MACTScenario 2 - Transport Rule, MACT, CWA 316(b)

Regulated Units - 15-year present value of costs > replacement power from a CC or CT. Merchant unit - 15 year present value of cost > revenues from energy

gas CC

B ttl G 50 t 65 GW b

ICF/IEE (May 2010)

25 to 60 GW by 2015

Transport Rule, MACT, 316(b) Cooling Water, Coal Ash

Size and existing controls

Transport Rule, MACT

15-year present value of cost > revenues from energy and capacity markets.

Brattle Group (December 2010)

50 to 65 GW by 2020

Credit Suisse (September 2010) 60 GW


Switch to lower sulfur coal, install emission controls, or retire

T t R l MACT

In-house model (NEEMS) optimizing costs of existing capacity and costs of potential new capacity.

MJ Bradley (August 2010) 30 to 40 GW

Charles River Associates (December 2010)

39 GW by 2015

Source: Synapse Energy Economics, Inc., “Public Policy Impacts on Transmission Planning, Prepared for Earthjustice”, December 10, 2010; and “Miller, P. A Primer on Pending Environmental Regulations and their Potential Impacts on Electric System Reliability. Working Draft, JD Northeast States for Coordinated Air Use Management. January 24, 2011.



FGS + emissions on all coal fired units by 2015Bernstein Research (October 2010)

51 GW

30

P t ti l N t l G C ti N G ti U (R ti d C l)


Potential Natural Gas Consumption – New Generation Use (Retired Coal)

The retirement of 45 gigawatts of capacity would likely still have only a limited i ll l

2 500

3,000

)

impact on overall natural gas usage.

2,000

2,500

umpt

ion

(Bcf

)

1,000

1,500

al G

as C

onsu

0

500

Nat

ura


NGV New Generation (Retired Coal)

Note: Assumes 160 Bcf of NGV natural gas use. Also assumes retirement of 45 GW of coal-fired capacity, replaced with new natural gas generation with an 85 percent capacity factor and a 7,600 Btu/kWh heat rate.

N t l G Fi d C it Sh b A C t


Natural Gas-Fired Capacity Share by Age Category

Despite the significant recent investment, there is still a considerable amount of legacy gas (steam) generation.

Greater than 50 years:

B t 30 t 50

12,642 MW; 3% of capacity;38 plants (averaging 333 MW)

L th 30

Between 30 to 50 years94,663 MW;23% of capacity;175 plants( i 541 MW) Less than 30 years:

311,061 MW; 74% of capacity;596 plants (averaging 596 MW).

(averaging 541 MW)


N t l G Fi d C it Sh b H t R t


Natural Gas-Fired Capacity Share by Heat Rate

A considerable amount of this legacy generation operates at heat rates considerably higher than newer combined cycle units.

Over 15,000 Btu/kWh:31 565 MW; 8% of capacity;

Less than

31,565 MW; 8% of capacity;143 units (averaging 221 MW)

13 000 to 15 000 Btu/kWh: Less than10,000 Btu/kWh:

220,275 MW;53% of capacity;

277 plants

13,000 to 15,000 Btu/kWh:29,223 MW; 7% of capacity;72 plants (averaging 406 MW)

277 plants(averaging 795 MW)

10,000 to 13,000 Btu/kWh:137,303 MW; 33% of capacity;243 plants (averaging 565 MW)


p ( g g )


N t l G Fi d C it Sh b P i M


Natural Gas-Fired Capacity Share by Prime Mover

Displacement of legacy gas generation could make a more meaningful contribution to overall natural gas consumption but one still within meaningful levels.

3,500

4,000

Bcf

)

g p g

2,500

3,000

onsu

mpt

ion

(

1 000

1,500

2,000

atur

al G

as C

o

0

500

1,000

Na


NGV New Generation (Retired Coal) New Generation (Retired Natural Gas)

Note: Assumes 160 Bcf of NGV natural gas use. Also assumes retirement of 45 GW of coal-fired capacity, replaced with new natural gas generation with an 85 percent capacity factor and a 7,600 Btu/kWh heat rate. In addition, 17 GW of natural gas-fired capacity is replaced with new generation, with an 85 percent capacity factor and a 7,600 Btu/kWh heat rate.


Policy Issue 2:LNG d US N t l G E tLNG and US Natural Gas Exports



Considerable Underutilized LNG Regasification Capacity along GOMConsiderable Underutilized LNG Regasification Capacity along GOM

A

Existing

JFRegasification O

T

B

ExistingExistingA. Everett, MA: 1.035 BcfdB. Cove Point, MD: 1.8 BcfdC. Elba Island, GA: 1.6 Bcfd (+0.5 Expansion)D. Lake Charles, LA: 2.1 Bcfd

Under ConstructionApproved

Liquefaction

Q

SB

E. Energy Bridge, GOM: 0.5 BcfdF. Northeast Gateway, Offshore MA: 0.8 BcfdG. Freeport, TX: 1.5 Bcfd (+2.5 Expansion)H. Sabine, LA: 4.0 BcfdI. Hackberry, LA: 1.8 Bcfd (+0.85 Expansion)J N t Off h MA 0 4 B fd

Existing

Liquefaction

Under Construction

Approved

C

J. Neptune, Offshore MA: 0.4 BcfdK. Sabine Pass, TX: 1.0 Bcfd (+ 1.0 Expansion)Under ConstructionL. Pascagoula, MS: 1.0 BcfdApprovedM Corpus Christi TX: 1 0 Bcfd

Approved

C

D

M. Corpus Christi, TX: 1.0 BcfdN. Corpus Christi, TX: 2.6 BcfdO. Fall River, MA: 0.8 BcfdP. Port Arthur, TX: 3.0 BcfdQ. Logan, NJ: 1.2 BcfdR. Port Lavaca, TX: 1.0 Bcfd

HIKG

L

MN

P

ES. Baltimore, MD: 1.5 BcfdT. LI Sound, NY: 1.0 Bcfd

M R


Moti ations for Mo ing Shale Gas to Global Cons ming AreasMotivations for Moving Shale Gas to Global Consuming Areas

Japan LNG U.K. NBP U.S. Henry Hub FSU @ German Border

14

16

18

p y @

• Excess U.S. shale production.

10

12

14

mmbtu

• Growing global energy demand.

4

6

8

$/m

• Climate change issues.

• Global natural

0

2

Jan‐05 Jan‐06 Jan‐07 Jan‐08 Jan‐09 Jan‐10 Jan‐11

Global natural gas price differentials.

37Source: Marathon

LNG V l Ch i


LNG Value Chain

Feedstock (production) costs will be critical in determining the location of basin-specific production along the global LNG supply curve.

Feedgas Cost$3.50 / MMBtu

50% of total cost

Capacity fee$1.75 / MMBtu

25% of total cost

Shipping*$0.75 / MMBtu

11% of total cost

Regasification$0.40 / MMBtu6% of total cost

Plant losses$0.72 / MMBtu

10% of total cost

38© LSU Center for Energy StudiesSource: Squarespace

Cost out of Plant$7.12 – $7.62 / MMBtu

Note: *depends upon the distance shipped


2009 LNG E ports2009 LNG Exports

U.S. does export some LNG primarily from Alaska to Tokyo Electric

404550

253035

ic m

eter

s

5101520

Bill

ion

cubi

05

39Source: BP Statistical Review.


LNG Liq efaction Capacit ers s DemandLNG Liquefaction Capacity versus Demand

Some analysts suggest the market is close to, or long, on liquefaction capacity until about g, q p y

2023.

40Source: Pacific LNG


LNG S ppl S rpl ses Sho ld Contin eLNG Supply Surpluses Should Continue

North American shale is going to have to compete in a very tight market. Not a foregone conclusion that all the gas is getting exported.

41Source: Charles River Associates.


FOB Gas Price Necessar to Yield 12 Percent Ret rn (Atlantic Deli er )FOB Gas Price Necessary to Yield 12 Percent Return (Atlantic Delivery)

212

U.S. is likely to be at the upper end of the global LNG supply chain.

.5 7.7

8.8

11.

8

10

12

2 4 .5 3.6

5.7 6.

0 6.1 6.

6

7. 7

4

6

8

MM

Btu

0.0 0.

4 0.7

0.7 1.

1 1.4 1.5

1.5 1.7

1.7

1.7 1.8 2.0

2.0

2.0 2.1 2.2 2.4 2.6 2.7 2.9

2.9 3.

2 3.4 3. 3

0

2

4

$/M

0

AD

GA

SQ

atar

gas-

4A

run

Niu

gini

Gas

Alta

ntic

LN

GB

onta

ngQ

atar

gas

tic L

NG

2&

3Q

alha

t LN

Gan

tic L

NG

4E

G L

NG

ELN

G 2

Dam

ietta

ELN

G 1

Dar

win

Bru

nei L

NG

OLN

GM

LNG

Tig

aTa

nggu

hB

rass

LN

GM

LNG

Yem

en L

NG

MLN

G D

uaP

eru

LNG

h W

est S

helf

Ango

la L

NG

Ken

aiS

Sha

le G

asS

nohv

itQ

CLN

GP

NG

LN

GP

luto

Gor

gon

Sak

halin

2

42

Liqu

id A

Alta

nt Atl Y

Nor

th A

US

Source: Pacific LNG

B i C titi


ShaleBasin Competition ShaleResources

(Tcf)

Asia Pacific 6,155 North America 3,842 Middl E t 2 548

Basin competition from shale produced around the world will continue to put pressure on LNG deliveries

globally Middle East 2,548 South America 2,117 Asia 627 Europe 549 Africa 274

Worldwide 16 112

globally.

Worldwide 16,112



Policy Issue 3:Louisiana Drilling andLouisiana Drilling andProduction Challenges


Center for Energy Studies LA Drilling/Production Challenges

A A l Ri C tAverage Annual Rig Count

160Time Period N.LA S.LA-L S.LA-W S.LA-O

1987 1992 16 7% 25 0% 43 5% 41 5%

Percent ChangeNorth LA the only area of the state seeing any significant

120

1401987-1992 -16.7% -25.0% -43.5% -41.5%1993-2001 172.7% 100.0% 75.0% 98.3%2002-2010 495.7% -50.0% -18.8% -67.4%

g y gdrilling activity.

80

100

g C

ount

20

40

60Ri

0

20

1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

Note: 2010 is through September.Source: Louisiana Department of Natural Resources.

North Louisiana South Louisiana - LandSouth Louisiana - Inland Water South Louisiana - Offshore



Hi t i l Ri C t d C d Oil P i (E h St t M d R l ti t 1999 l l)

LA Drilling/Production Challenges

Historical Rig Count and Crude Oil Prices (Each State Measured Relative to 1999 level)

$120450

Relative drilling activity down compared to other regions.

$

$100350

400June 2002

Corbello Decision

e ($

/Bbl

)

00)

$60

$80

200

250

300

s In

term

edia

te

ount

(199

9=10

$20

$40

100

150

Wes

t Tex

as

Rig

Co

$00

50

1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

Source: Baker Hughes; St. Louis Federal Reserve Bank

Texas New Mexico OklahomaWyoming Louisiana - South Louisiana - OffshoreWTI



E ti t d C t f D illi d E i i W ll (All T ) 1980 2007


Estimated Cost of Drilling and Equipping Wells (All Types), 1980-2007

$200$3.0 e)

AverageTime Period Cost/Well N.LA S.LA LA-O

1987-1992 0 14 -64 2% 37 0% 301 2%

Cost Premium (%)

$140

$160

$180

$200

$2.5

$3.0

($)

ana-

Offs

hore1987-1992 0.14 -64.2% 37.0% 301.2%

1993-2001 0.26 -49.8% 90.4% 289.4%2002-2007 9.16 -96.5% -83.8% 576.2%

Drilling

~ $70MM/Well

$100

$120

$140

$1.5

$2.0

Wel

l per

foot

oot (

$, L

ouis

iacosts have been

explosive. ~ $35MM/Well

$40

$60

$80

$0 5

$1.0

Cos

t per

W

er W

ell p

er fo

~ $20MM/Well

$-

$20

$-

$0.5

1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007

Cos

t pe

Source: Joint Association Survey, American Petroleum Institute

Texas New Mexico OklahomaWyoming Louisiana - North Louisiana - SouthLouisiana - Offshore



C d Oil P d ti


Crude Oil Production

Crude oil production decline rates are accelerating particularly in state waters.

140

160

N.LA S.LA LA-O

1986-1998 -41.8% -37.9% -38.6%

Percent Change

80

100

120

lion

Bar

rels

) 1998-2009 -49.8% -41.0% -74.7%

Trend = - 3.8% per year

40

60

80

oduc

tion

(Mill

p y


0

20

40

Pro

Source: Louisiana Department of Natural Resources.

01986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

North Louisiana South Louisiana Offshore Louisiana48© LSU Center for Energy Studies


N t l G P d ti T d


Natural Gas Production Trends

North Louisiana production is offsetting the decline in conventional South Louisiana natural gas production.

1.20

1.40N.LA S.LA LA-O

1986-2001 7% -18% -55%2002-2009 148% -44% -24%

Percent Change


0.80

1.00

Tcf

0.40

0.60


0.00

0.20

Source: Louisiana Department of Natural Resources. Note “offshore” is state water production and not federal OCS.

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

North Louisiana South Louisiana Offshore Louisiana



N t l G P d ti Sh


Natural Gas Production Shares

80%

North Louisiana natural gas production shares are changing relative positions with South Louisiana natural gas production.

60%

70%

80%

40%

50%

60%

of T

otal

(%)

20%

30%

Per

cent

0%

10%

Source: Louisiana Department of Natural Resources.

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

North Louisiana South Louisiana Offshore Louisiana


L i i Ri C t d N t l G P d ti

Center for Energy Studies Energy Opportunities

Louisiana Rig Count and Natural Gas Production

Louisiana natural gas production was relatively constant until late 2008 when Haynesville production started to come on-line.

200

250

200

250

150

200

150

200

r of R

igs

Producti

50

100

50

100

Rig CountHaynesville Era

Num

ber on -Bcf

00

n-05

r-05 l-0

5t-0

5n-

06r-

06 l-06

t-06

n-07

r-07 l-0

7t-0

7n-

08r-

08 l-08

t-08

n-09

r-09 l-0

9t-0

9n-

10r-

10 l-10

t-10

n-11

Rig CountProduction

Jan

Apr

Jul

Oct

Jan

Apr

Jul

Oct

Jan

Apr

Jul

Oct

Jan

Apr

Jul

Oct

Jan

Apr

Jul

Oct

Jan

Apr

Jul

Oct

Jan

51© LSU Center for Energy StudiesSource: Baker Hughes; and Energy Information Administration, U.S. Department of Energy.

Ri C t d C d Oil P i (E h St t M d R l ti t 1999 A ti it )

Center for Energy Studies Natural Gas Trends

Rig Count and Crude Oil Price, (Each State Measured Relative to 1999 Activity)

$141 000

North Louisiana has been the shining opportunity in the industry during the recent price downturn/correction. However, that competitive advantage is starting to deteriorate.

$10

$12

$14

700

800

900

1,000

999

= 10

0) West Tex

$6

$8

$10

400

500

600

700

t (Ja

nuar

y 19

xas Intermedi

$2

$4

100

200

300

400

Rig

Cou

nt ate ($/BB

l)

$00

100

Jan-07 Jun-07 Nov-07 Apr-08 Sep-08 Feb-09 Jul-09 Dec-09 May-10 Oct-10

N. Louisiana S. Louisiana - Inland Water S. Louisiana - LandN. Louisiana S. Louisiana Inland Water S. Louisiana Land

Texas New Mexico Oklahoma

Wyoming Natural Gas PriceSource: Baker Hughes; and Federal Reserve Bank of St. Louis. 52© LSU Center for Energy Studies


Ri C t N th L i i (H ill ) d T Di t i t 1 (E l F d)


Rig Count, North Louisiana (Haynesville) and Texas District 1 (Eagle Ford)

In the past year, the rig count in North Louisiana has fallen 18 percent (25 rigs),while the rig count in the Eagle Ford region has increased 110 percent (43 rigs)

120

140

160

80

100

120

Cou

nt

40

60

80

Rig

0

20

J 09 A 09 J l 09 O t 09 J 10 A 10 J l 10 O t 10 J 11


Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11

North Louisiana Texas - District 1

Source: Baker Hughes. Rig counts represent the number of active drilling rigs in each reported area.


Ri C t N th L i i (H ill ) d T Di t i t 1 (E l F d)


Rig Count, North Louisiana (Haynesville) and Texas District 1 (Eagle Ford)

Indexing the rig change from January 2009 highlights the recent, fast and dramatic shift in basin preference. Has less to do with incentives than markets.

$70

$80

$90

600

700

800

=100

)

Haynesville is losing its competitive advantage due to the

liquids preference associated with other shales.

$50

$60

$70

400

500

600

nuar

y 20

09=

$/BO

$20

$30

$40

200

300

400

Rig

Cou

nt (J

aO

E

$0

$10

$20

0

100

J 09 A 09 J l 09 O t 09 J 10 A 10 J l 10 O t 10 J 11

R


Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11

North Louisiana Texas - District 1 Spot Price Differential

Source: Baker Hughes. Rig counts are indexed to the level of active drilling rigs in each reported area as of January 2009.


U S C d Oil P d ti F t


U.S. Crude Oil Production Forecast

Deepwater production is forecast to increase by almost 20 percent between 2010 and 2030.

4.0

4.5

5.0

per d

ay) Projection

2.5

3.0

3.5

ion

(MM

Bbl

s

Anticipated deepwater production growth from 900 MBbls/d to 1.75 MMBbls/d

1.0

1.5

2.0

e O

il P

rodu

cti

0.0

0.5

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035

Cru

de

Onshore Lower 48 GOM - Deep Water GOM - Shallow Water

Offshore Pacific & Atlantic Alaska55© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy. Annual Energy Outlook.


Sh ll t d illi i ti it


Shallow-water drilling rig activity

Total pre-spill shallow-water activity currently down by about 35 percent.

Other StandbyA 20

50

60

70 y

Active - Other Active - DrillingApr-20:Accident

30

40

50 Reduced Activity

10

20

30

0 5-Apr-10 17-May-10 28-Jun-10 16-Aug-10 27-Sep-10 8-Nov-10 20-Dec-10 31-Jan-11 14-Mar-11

Note: “Active-Other” includes Completion; Recomplete; and Workover categories; “Standby” includes Assigned; Circulate; Under Tow; Waiting on Location; Orders or Weather; Mobilizing, Monitoring and Standby categories.“Other” includes Plug & Abandon; Run Casing; Rigging Up; Logging; Moving On and Other categories.Source: RigData. 56© LSU Center for Energy Studies


D t d illi i ti it


Deepwater drilling rig activity

Total pre-spill deepwater activity currently down by about 65 percent.

Other StandbyA 20

50

60 y

Active - Other Active - DrillingApr-20:Accident

30

40

Reduced Activity

10

20

0 5-Apr-10 17-May-10 28-Jun-10 16-Aug-10 27-Sep-10 8-Nov-10 20-Dec-10 31-Jan-11 14-Mar-11

Note: “Active-Other” includes Completion; Recomplete; and Workover categories; “Standby” includes Assigned; Circulate; Under Tow; Waiting on Location; Orders or Weather; Mobilizing, Monitoring and Standby categories.“Other” includes Plug & Abandon; Run Casing; Rigging Up; Logging; Moving On and Other categories.Source: RigData. 57© LSU Center for Energy Studies


ConclusionsConclusions



C l i

Conclusions

Conclusions

• Speculation regarding geo-political supply interruptions and emerging economies (demand) will keep crude prices high and likely maintain the ( ) p p g yrecently observed decoupling with natural gas prices.

• Shale continues to display great promise and significant challenges –threat to many vested interests receiving significant subsidies (renewables, y g g ( ,energy efficiency).

• There are continued opportunities for expanded domestic natural gas use that should not “eat away” at the considerable reserve developments made y pover the past five years.

• The export of shale production is highly, highly speculative and there are several mitigation remedies for those with concerns (long term contracting, g ( g gproduction sharing agreements).

• Drilling and production trends in South Louisiana are changing in a very unfavorable fashion that will not turn our well for Louisiana if continued.


We are already seeing a movement of relative drilling activity away from Haynesville, and towards Eagle Ford and other liquids-rich shales.


Q ti C t d Di iQuestions, Comments and Discussion

[email protected]

60

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