Industrial Applications of Reactive Distillation: Recent Trends
Natural Gas Trends and Impact on Industrial Development · Natural Gas Trends and Impact on...
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Natural Gas Trends and Impact on Industrial Development
Central G lf Coast Ind str Alliance ConferenceCentral Gulf Coast Industry Alliance Conference
Arthur R. Outlaw Convention CenterMobile Alabama
David E. Dismukes, Ph.D.C t f E St di
Mobile, AlabamaSeptember 22, 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)
Civil War
$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 May-11 Jul-11
5© LSU Center for Energy Studies
Ja 0 a 0 ay 0 Ju 0 Sep 0 o 0 Ja a ay Ju
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 Jul-11
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
Center for Energy Studies
Global Energy MarketsGlobal Energy Markets
13© LSU Center for Energy Studies
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 14© LSU Center for Energy Studies
Iraqi instabilityNigerian civil strife
Venezuelan oil strike
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 15© 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 16© LSU Center for Energy Studies
1997 1999 2001 2003 2005 2007 2009 2011
Spare Capacity World Oil Price
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 produces nearly 40 percent less CO2 than refined products.
• In 2008, NGVs used 215 million gasoline gallon equivalent (“GGE”). 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)
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
23© 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)
24© 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%
25© 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 (now CSAPR) [proposed]p ( ) [p p ]• Issued to replace the Clean Air Interstate Rule (CAIR) and its predecessor the Clean Air Transport Rule (“CATR”).
Requires 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 (some annual, some on ozone season only).
• By 2014, the rule and other state and EPA actions would reduce power plant SO2 emissions by 80% over 2005 levels. Power plant NOx emissions would drop by 58%.
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]• 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 RulePower Plant Cooling Water Intake Structures Rule• 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.
26
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)
27© 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)
28© 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
29
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
30© 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)
31© 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)
32© 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
33© 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
34© 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
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 Liquefaction Shipping & Fuel Regas Delivered Equivalent
Europe:
LowHigh
56%($/MMBtu)
$4.00$6.50
11%-17%($/MMBtu)
$1.25$1.25
20%-29%($/MMBtu)
$1.40$1.65
4%-7%($/MMBtu)
$0.50$0.50
Cost($/MMBtu)
$7.15$9.90
Oil Price*($/BOE)
$41.47$57 42High
Asia:LowHigh
$6.50
$4.00$6.50
$1.25
$1.25$1.25
$1.65
$2.90$3.45
$0.50
$0.50$0.50
$9.90
$8.95$11.70
$57.42
$51.91$67.86
36© LSU Center for Energy StudiesSource: Cheniere.Note: *uses a BOE conversion of 5.8 Mcf/BOE.
Henry Hub: $4.50$5.00
WTI: $97.00
$100.00
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
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.
38Source: 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.
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39
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Source: Pacific LNG
B i C titi
Center for Energy Studies Natural Gas Uses
Basin Competition
Close to 6,000 TCF of shale gas opportunities around the world. Coupled with 9,000 Tcfin conventional suggest a potentially solid resource base for many decades.
Canada388 Tcf
China1,275 Tcf
388 Tcf
U.S. 862 Tcf
France180 Tcf
Poland187 Tcf
Al i Lib
Brazil226 Tcf
Mexico681 Tcf
Algeria231 Tcf
Libya290 Tcf
Australia396 TcfSouth
Africa485 T f
Argentina774 Tcf
226 Tcf
Source: MIT Energy Initiative. 40© LSU Center for Energy Studies
485 Tcf
Center for Energy Studies
Policy Issue 3:Drilling-ProductionDrilling Production
Challenges & Opportunities
41© LSU Center for Energy Studies
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)
$141 200
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
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1,200
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e
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$8
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600
800
t (Ja
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y 19
enry Hub ($/M
$2
$4
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400
Rig
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ntM
cf)
$00 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10 Jan-11
N Louisiana Texas Pennsylvania New MexicoN. Louisiana Texas Pennsylvania New Mexico
Oklahoma Wyoming Natural Gas Price
Source: Baker Hughes; and Federal Reserve Bank of St. Louis. 42© LSU Center for Energy Studies
Sh l G Pl F ll C l P t T B k
Center for Energy Studies
Shale Gas Plays Full-Cycle Post Tax Breakevens
$18
Relative price changes are shifting the basin-specific economics considerably.
$12$14$16$18
(US
$/M
cf)
$$6$8
$10
x B
reak
even
Currently-economic basins
$0$2$4
Pos
t-tax
43© LSU Center for Energy StudiesSource: Estimated from: Neal Anderson. 2011. Wood Mackenzie: playing a smart shale gas hand. Oil & Gas Journal. August 10, 2011.
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 29 percent (40 rigs), while the rig count in the Eagle Ford region has increased 154 percent (60 rigs)
and the Marcellus region has increased 44 percent (34 rigs)
140
160and the Marcellus region has increased 44 percent (34 rigs)
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 A 11
44© LSU Center for Energy Studies
Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11
North Louisiana Texas - District 1 Pennsylvania
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.
$70
$80
$90
800
900
1,000
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)
Haynesville is losing its competitive advantage due to the
liquids preference associated with other shales.
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y 20
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R
45© LSU Center for Energy Studies
Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-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
R t t C ti l R
Conclusions
Return to Conventional Reserves
Permian Basin• Offers wide range of opportunities (conventional and
unconventional) for both crude oil, natural gas, and ) , g ,NGLs.
• Apache Corporation, Petrohawk, Anadarko all active in the area.
• Second most active basin (2010) in acquisitions (second only to Marcellus).
Davy Jones• In January 2010, McMoRan Exploration
d di it D J ltannounced a discovery on its Davy Jones ultra-deep prospect. Located on South Marsh Island Block 230 in approximately 20 feet of water.
• In June 2011, estimated 192 net feet of potential
46© LSU Center for Energy Studies
, phydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. Potentially 2-6 Tcfof natural gas.
Center for Energy Studies
Th N t F ti C d Oil Sh l
Conclusions
The Next Frontier: Crude Oil Shales
• Number of i demerging crude
oil shale plays that could have dynamic impact
i d ton industry.
• As much as 24 billion barrels i l hin plays such as Monterey (CA), Bakken(ND), Eagle Ford (TX) andFord (TX), and Niabrara(CO/NE).
47© LSU Center for Energy StudiesSource: Energy Information Administration.
Center for Energy Studies
C d Oil Sh l O t iti L i i
Conclusions
Crude Oil Shale Opportunities -- Louisiana
• 1998 LGS Study primary publicly-available source of yinformation on the formation.
• Lies between sands of the upper and lower Tuscaloosa.
• Varies in thickness from 500 feet (MS) to around 800 feet (LA).
• Shallowest opportunity around 10,000 feet – mostly between 11,000 to 12,000 –some areas as deep as 16,000 (EBR).
• Estimated potential resource
48© LSU Center for Energy StudiesSource: Oil and Gas Journal and Louisiana Geological Survey.
of 7 BBbls.
Center for Energy Studies
C ti d Sh l D l t Ch ll
Conclusions
Continued Shale Development Challenges
Still a number of lingering issues that create challenges for all shaleStill a number of lingering issues that create challenges for all shale development:
• Public challenges on true resource size.
• Water/aquifer contamination issues.
• Water usage issues.
• Other environmental issues (geological emissions)• Other environmental issues (geological, emissions)
• Regulatory/tax changes
• Supporting infrastructure development.
• Market demand and price support.
49© LSU Center for Energy Studies
Center for Energy Studies
ConclusionsConclusions
50© LSU Center for Energy Studies
E i I t f Additi l Eth Utili ti
Center for Energy Studies
Economic Impact of Additional Ethane Utilization
Economic Impact fromExpanded Production of Petrochemical Economic Impact from
Impact Type Employment Payroll Output Employment Payroll Output
Expanded Production of Petrochemicaland Derivatives from a 25 Percent
Increase in Ethane Production
--- (Billion $) --- --- (Billion $) ---
Economic Impact from New Investment in
Plant and Equipment
Direct Effect 17,017 2.4$ 32.8$ 54,094 4.3$ 16.2$ Indirect Effect 79,870 6.6$ 36.9$ 74,479 5.1$ 16.8$ Induced Effect 85,563 4.1$ 13.7$ 100,549 4.8$ 16.1$
Total Effect 182,450 13.1$ 83.4$ 229,122 14.2$ 49.1$Total Effect 182,450 13.1$ 83.4$ 229,122 14.2$ 49.1$
51
R t E i A t
Center for Energy Studies
Recent Expansion Announcements
Sep-2011: Williams announced an expansion at its Geismar olefins production facility (Baton Rouge, LA). The expansion will increase the facility’s ethylene production by 600 million pounds per year to a new annual capacity of 1 95 billion pounds and is expected to be in service by the third quarter of 2013annual capacity of 1.95 billion pounds and is expected to be in service by the third quarter of 2013.
Apr-2011: Dow announced plans to increase its ethylene and propylene production, and to integrate its US operations into feedstock opportunities available from increasing supplies of US shale gas. Specifically, the Company plans to increase its ethylene supply and cracking capabilities at existing Gulf Coast facilities by:• Re-starting an ethylene cracker at its St. Charles operations site near Hahnville, LA by the end of 2012;• Improving ethane feedstock flexibility for an ethylene cracker at its Plaquemine, LA site in 2014;• Increasing ethane feedstock flexibility for an ethylene cracker at the Freeport, TX site in 2016;• Constructing a new, world-scale ethylene production plant in the US Gulf Coast, for startup in 2017.
Apr-2011: Westlake Chemical Corporation announced an expansion program to increase the ethane-based ethylene capacity at Lake Charles, LA, and the evaluation of expansion options and the upgrade of ethylene production facilities at Calvert City, KY in order to capitalize on new low cost ethane and other "light" feedstocks being developed.g g p
Mar-2011: Chevron Phillips Chemical announced it is advancing a feasibility study to construct a “world-scale” ethane cracker and ethylene derivatives at one of its existing facilities in the Gulf Coast region. The new facility would utilize the advantaged feed sources expected from development of shale gas reserves.
52
Dec-2010: Sasol announced plans to construct the world’s first commercial tetramerization unit, capable of producing over 100,000 metric tons per year of combined 1-octene and 1-hexene, at its existing Lake Charles, LA Chemical Complex.
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 theeconomies (demand) will keep crude prices high and likely maintain the recently observed decoupling with natural gas prices.
• Shale continues to display great promise and significant challenges –threat to many vested interests receiving significant subsidies (renewables,threat to many vested interests receiving significant subsidies (renewables, energy efficiency).
• There are continued opportunities for expanded domestic natural gas use that should not “eat away” at the considerable reserve developments madethat should not eat away at the considerable reserve developments made over the past five years.
• The export of US shale production is risky and there are several mitigation remedies for those with concerns (long term contracting, productionremedies for those with concerns (long term contracting, production sharing agreements).
• Crude oil shale development stands to be the next big “game changer.” Could dramatically impact North American supplies and create a number of
53© LSU Center for Energy Studies
Could dramatically impact North American supplies and create a number of interesting “decoupling” dynamics already materializing in NA markets.