louisiana’s natural gas advantage: can we hold it? grow it ......center for energy studies natural...
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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
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
Center for Energy Studies Pricing Trends
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.
4© LSU Center for Energy Studies
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)
Center for Energy Studies Pricing Trends
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
5© LSU Center for Energy Studies
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
Center for Energy Studies
Rig MovementsRig Movements
6© LSU Center for Energy Studies
Center for Energy Studies
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.
Center for Energy Studies
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.
Center for Energy Studies
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.
Center for Energy Studies
Supply ImplicationsSupply Implications
10© LSU Center for Energy Studies
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
Center for Energy Studies Supply Implications
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
Center for Energy Studies Supply Implications
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)
Source: Energy Information Administration, U.S. Department of Energy 13© LSU Center for Energy Studies
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
Center for Energy Studies Supply Implications
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
Source: Energy Information Administration, U.S. Department of Energy 14© LSU Center for Energy Studies
W ld S l C d Oil P d ti C it
Center for Energy Studies Supply Implications
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
Center for Energy Studies Supply Implications
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
Source: Energy Information Administration, U.S. Department of Energy 16© LSU Center for Energy Studies
Iraqi instabilityNigerian civil strife
Venezuelan oil strike
P t l D d W ld U S d Chi
Center for Energy Studies Supply Implications
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
Source: Energy Information Administration, U.S. Department of Energy 17© LSU Center for Energy Studies
U.S. China World
C d Oil C ti GDP W ld U S d Chi
Center for Energy Studies Supply Implications
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
Center for Energy Studies
Policy Issue 1:N t l G UNatural Gas Uses
19© LSU Center for Energy Studies
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.
20© LSU Center for Energy Studies
• 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
Center for Energy Studies Natural Gas Uses
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)
21© LSU Center for Energy Studies
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Residential Commercial Industrial Electric Power NGV
Source: Energy Information Administration, U.S. Department of Energy
R t il G li P i d N t l G GGE
Center for Energy Studies Natural Gas Uses
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
$0.50
Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11
22© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy
Gasoline Natural Gas (GGE)
T NGV St t
Center for Energy Studies Natural Gas Uses
Top NGV States
Most of the leading NGV states are not major producing states. Top 10 NGV states account for almost 90 percent of all U S NGV natural gas useaccount for almost 90 percent of all U.S. NGV natural gas use.
NGV CurrentNatural Gas Gasoline
Consumption Prices(MMcf) ($/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$
23© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy
U.S. 29,150 4.01$
L di St t i NGV P f
Center for Energy Studies Natural Gas Uses
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
Center for Energy Studies Natural Gas Uses
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)
25© LSU Center for Energy Studies
2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Consumption Percent of Total
Source: Energy Information Administration, U.S. Department of Energy
U S P G ti F l Mi
Center for Energy Studies Natural Gas Uses
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%
26© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy
Center for Energy Studies
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
Center for Energy Studies Natural Gas Uses
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)
28© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy
C l Fi d C it Sh b H t R t
Center for Energy Studies Natural Gas Uses
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)
29© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy
Center for Energy Studies
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
Transport Rule, MACT
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.
Transport Rule, MACT
Transport Rule, MACT
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)
Center for Energy Studies Natural Gas Uses
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
31© LSU Center for Energy Studies
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
Center for Energy Studies Natural Gas Uses
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)
32© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy
N t l G Fi d C it Sh b H t R t
Center for Energy Studies Natural Gas Uses
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)
33© LSU Center for Energy Studies
p ( g g )
Source: Energy Information Administration, U.S. Department of Energy
N t l G Fi d C it Sh b P i M
Center for Energy Studies Natural Gas Uses
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
34© LSU Center for Energy Studies
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.
Center for Energy Studies
Policy Issue 2:LNG d US N t l G E tLNG and US Natural Gas Exports
35© LSU Center for Energy Studies
Center for Energy Studies
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
Center for Energy Studies
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
Center for Energy Studies Natural Gas Uses
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
Center for Energy Studies
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.
Center for Energy Studies
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
Center for Energy Studies
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.
Center for Energy Studies
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
Center for Energy Studies Natural Gas Uses
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
43© LSU Center for Energy StudiesSource: Energy Information Administration, U.S. Department of Energy
Center for Energy Studies
Policy Issue 3:Louisiana Drilling andLouisiana Drilling andProduction Challenges
44© LSU Center for Energy Studies
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
45© LSU Center for Energy Studies
Center for Energy Studies
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
46© LSU Center for Energy Studies
Center for Energy Studies
E ti t d C t f D illi d E i i W ll (All T ) 1980 2007
LA Drilling/Production Challenges
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
47© LSU Center for Energy Studies
Center for Energy Studies
C d Oil P d ti
LA Drilling/Production Challenges
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
Trend = - 4.56% per year
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
Center for Energy Studies
N t l G P d ti T d
LA Drilling/Production Challenges
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
Trend = - 1.3% per year
0.80
1.00
Tcf
0.40
0.60
Trend = - 8.2% per year
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
49© LSU Center for Energy Studies
Center for Energy Studies
N t l G P d ti Sh
LA Drilling/Production Challenges
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
50© LSU Center for Energy Studies
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
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)
LA Drilling/Production Challenges
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
53© LSU Center for Energy Studies
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.
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)
LA Drilling/Production Challenges
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
54© LSU Center for Energy Studies
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.
Center for Energy Studies
U S C d Oil P d ti F t
LA Drilling/Production Challenges
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.
Center for Energy Studies
Sh ll t d illi i ti it
LA Drilling/Production Challenges
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
Center for Energy Studies
D t d illi i ti it
LA Drilling/Production Challenges
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
Center for Energy Studies
ConclusionsConclusions
58© LSU Center for Energy Studies
Center for Energy Studies
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.
59© LSU Center for Energy Studies
We are already seeing a movement of relative drilling activity away from Haynesville, and towards Eagle Ford and other liquids-rich shales.