Pearce W. Hammond, Jr., C.F.A.
Director, Institutional Research
Simmons & Company International
The Challenge to Renewables in a More Abundant Natural Gas World
TREIA Policy Forum
Austin, Texas
January 21, 2010
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Overview
• Shale Gas
• Gas Supply Trends
• Impact to Renewable Energy
• Key Trends in Renewable Energy for 2010
• Conclusion
• Q&A
2
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Shale Gas: Driving Big Change in Energy Outlook
• From the American Petroleum Institute.• Shale gas is defined as natural gas from shale formations.• Shale gas is an uncoventional gas source along with coalbed methane, tight sands and
methane hydrates.• Shales ordinarily have insufficient permeability to allow meaningful flow to the well bore
—therefore production requires fractures to improve permeability.• More recent shale wells are horizontal and need artificial stimulation, like hydraulic
fracturing, to produce.• Significant advances in horizontal drilling and well stimulation technologies are leading
to the shale boom. Hydraulic fracturing is the most significant of these.• Estimates of total natural gas resources in North America exceed 2,300 Tcf, with shale
gas resources alone within this assessment accounting for over 500 Tcf of recoverable natural gas (combining U.S. and Canada).
• In Apr ‘09 report, “Modern Shale Gas Development in the U.S.”, the U.S. DOE stated that the current recoverable resource estimate provides enough natural gas to supply the U.S. for the next 90 years. Other estimates carry this above 100 years.
3
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Shale Plays
• Big Four
– Haynesville (LA, TX) Likely to become one of the largest natural gas fields in the U.S. Currently ~12% of U.S. shale gas production.
– Marcellus (Northeast) Likely to become one of the largest natural gas fields in the U.S. Currently very small production.
– Barnett (TX) Largest producing field in the U.S. today and produces ~50-60% of all shale gas in the U.S.
– Fayetteville (AR) Currently ~18% of U.S. shale gas production.
• Other Shale Plays:
– Bakken
– Fayetteville
– Woodford
– Horn River
– Utica
– Chattanooga
– Huron
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Pearce Hammond, CFA | 713.546.7269 | [email protected]
Validating the Shale: Two Recent Signature Transactions
• ExxonMobil/ XTO Energy:– All share transaction.
– $41 bn total value (includes $10 bn in debt).
• Total/ Chesapeake:– CHK has agreed to sell a 25% interest in its upstream Barnett Shale assets to
Total E&P USA for $9.0 bn.
– CHK has also agree to discuss a JV in the Eagle Ford Shale with TOT and to work with TOT in evaluating several Canadian natural gas shale plays in which it has shown interest.
5
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Shale Play Economics from CHK and XTO
6
PlayWell
Cost ($ MM)
Gross EUR
(bcfe)
F&D Costs
($/Mcfe)
Nat Gas @$7.50
ROR
Nat Gas @ $5.00
RORBarnett Core 2.80 3.30 1.13 92% 47%Fayetteville 2.70 2.20 1.46 65% 36%Woodford 5.00 3.80 1.55 53% 32%Haynesville 8.00 6.50 1.58 59% 36%Marcellus 3.50 3.00 1.34 99% 70%
PlayGross EUR
(bcfe)
Well Costs
($MM)Royalty
F&D Cost ($/mcfe)
Pre-Carry IRR $7 Gas/
$70 OilHaynesville 6.50 7.00 25% 1.44 55%Marcellus 4.20 4.50 15% 1.26 66%Barnett 2.65 2.60 25% 1.31 36%Fayetteville 2.40 3.00 17% 1.51 31%Colony Granite Wash 5.70 6.25 20% 1.37 141%TX PH Granite Wash 4.75 5.50 20% 1.45 128%Average 4.36 4.80 20% 1.39 76%
CHK Play Economics
Source: CHK.
XTO Play Economics
Source: XTO.
•Very high IRR’s—even at low nat gas prices.
•Efficiencies and productivity should get better over time.
•Big question is what are threshold economics?
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Current Drilling Activity, Trends and Mix Shift
7
• U.S. Gas directed rig count reached an all-time high on October 17, 2008 and has imploded ~50-60% from peak ’08 levels.
• The majority of the rigs that were dropped were drilling vertical wells leading to a mix shift favoring more productive highly economic unconventional resource focused horizontal wells.
• As a simple rule of thumb, horizontal wells have EURs that are 3x vertical wells and IP rates that are 4-5x vertical wells.
Source: Smith Bits
Graph of Rig Count Change by Well TypeU.S. Gas Directed Rig Count
Source: Smith Bits
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Gas
-Dir
ecte
d Ri
g Co
unt
SmithBits Actual Data
Drop from peak-783
Pearce Hammond, CFA | 713.546.7269 | [email protected]
8
Rig Count Breakdown and Unconventional Production Outlook
0%
10%
20%
30%
40%
50%
60%
70%
80%
0.0
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1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018
Perc
enta
ge o
f To
tal D
omes
tic
Prod
ucti
on
Prod
ucti
on (B
cf/d
)Tight Gas CBM Shale % Unconventional
Source: DOE Shale Gas Primer and SCI
• Mix shift toward more economic and productive horizontal wells drove the recent production growth (~8% growth y/y) and is a trend we see increasing going forward.
• Unconventional resource provide the market with an abundantly accessible inventory of gas that will be on the lower end of the cost curve insuring the ability to meet natural gas demand for the foreseeable future.
• Prolific production from unconventional plays will likely reduce the required rigs, cycle to cycle, to keep production flat.
SCI Rig Count as of January 8, 2009Basin (Horizontal Gas) 01/08/10 Q1TD Q4 % Δ Q/Q Peak % off peakHaynesville/CV/James Lime 165 164 145 13% 165 0%Barnett Shale 66 67 60 11% 169 -61%Anadarko Basin 63 64 46 37% 88 -28%Woodford Shale 24 25 25 -1% 51 -53%Marcellus Shale 77 75 67 11% 80 -4%Other Appalachia (Huron,CBM,TG) 12 9 16 -43% 25 -52%Fayetteville Shale/Arkoma TG 33 33 32 5% 60 -45%Eagleford Shale 25 22 16 40% 26 -4%Other 16 17 15 11% 34 -53%Total U.S. Land Horizontal Gas 481 473 421 12% 546 -12%
Basin (Vertical Gas) 01/08/10 Q1TD Q4 % Δ Q/Q Peak % off peakHaynesville/CV/James Lime 53 51 42 20% 225 -76%Anadarko Basin 26 25 24 4% 146 -82%South Texas 27 26 28 -6% 97 -72%Appalachia 44 44 47 -7% 87 -49%Rockies 16 15 15 -5% 96 -83%Permian Basin 15 16 17 -8% 86 -83%Other 19 20 17 14% 76 -75%Total U.S. Land Vertical Gas 200 196 191 2% 768 -74%
Basin (Directional Gas) 01/08/10 Q1TD Q4 % Δ Q/Q Peak % off peakRockies 65 65 66 -2% 164 -60%Haynesville/CV/James Lime 26 27 27 -2% 53 -51%Onshore GC (ex. E Tx) 17 18 19 -6% 56 -70%Anadarko Basin 8 8 7 13% 25 -68%Permian Basin 5 6 4 32% 18 -72%Other 14 13 15 -14% 35 -60%Total U.S. Land Directional Gas 135 136 139 -2% 317 -57%
Total U.S. Land Gas Drilling 816 805 750 7% 1597 -49%
Pearce Hammond, CFA | 713.546.7269 | [email protected]
SCI estimates a 150 Gas-Directed Rig Increase from Trough by YE’10 based on a Partial Economic Recovery
9
US Domestic Base Decline Cotton Valley Vertical Rockies Directional
Barnett Shale Horizontal Anadarko Vertical Gulf Coast Directional
Haynesville Horizontal South Texas Vertical Cotton Valley Directional
Fayetteville Shale Horizontal Appalachia Vertical Anadarko Directional
Woodford Shale Horizontal Rockies Vertical Permian Directional
Granite Wash Horizontal Permian Vertical Other Directional
Marcellus Shale Horizontal Other Vertical ---
Ardmore-Woodford Horizontal --- HPDI data ---
Other Horizontal --- EIA data
Dry Gas Production + Drill. & Uncompl. (DUC) Wells
Dry Gas Production + Curtailments + DUC wells
• Based on our rig driven gas supply model, we estimate production to decline in 1 Bcf/d by YE’09 and to decline by an additional 0.5 Bcf/d by June 2010.
• Given an expectation for a partial recovery in the economy (gas demand begins to increase in 2010) coupled with declining production we anticipate the industry will need to add ~150 gas directed rigs to keep supply and demand in balance despite LNG imports and assuming normal weather.
• Regardless of the economic scenario we employ, their will be a need to add anywhere from 100 to 500 rigs, but utilization will remain low with 1,000 or less rigs envisioned to be running in 2010 under our best case scenario. Well bellow the 1,600 peak in October 2009.
Source: EIA, HPDI, SmithBits, Simmons & Company International.
0
5,000,000
10,000,000
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20,000,000
25,000,000
30,000,000
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50,000,000
55,000,000
60,000,000
65,000,000
70,000,000
75,000,000
80,000,000
History Match Forecast
Prod
uctio
n (M
cfe/
d)
Sept '08 Hurricane Activity
Call on '09 Gas Production - 69.0 Bcf/d
'10 Supply -69.5 Bcf/d
Call on '10 Gas Production- 70.2 Bcf/d
'09 Supply - 71.9 Bcf/d
-950 rigs +150 rigs
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Case Study: Southwestern Energy Efficiency Gains
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Source: SWN Quarterly Earnings Release, Fayetteville Shale.
18
2.6
1.3
$2.9
14
3.6
2.1$2.8
11
4.1
3.0 $2.9
0
2
4
6
8
10
12
14
16
18
20
Time to Drill (Days) Average Lateral Length in Feet (Thousands)
30 Day Avg IP Rate (MMcf/d) Drilling & Completion cost ($MM)
Vari
ous
Pearce Hammond, CFA | 713.546.7269 | [email protected]
U.S. Gas Production
11
44
46
48
50
52
54
56
58
60
Jan-
06
Apr
-06
Jul-0
6
Oct
-06
Jan-
07
Apr
-07
Jul-0
7
Oct
-07
Jan-
08
Apr
-08
Jul-0
8
Oct
-08
Jan-
09
Apr
-09
Jul-0
9
Oct
-09
U.S. Nat Gas Production (Bcf/d)
Source: EIA.
•U.S. natural gas production was 57.6 bcf/d in Oct ‘09.
•Despite the steep drop in the rig count, the production in Oct ‘09 was down just 0.9 bcf/d from record 58.5 bcf/d in Feb ‘09.
•Oct ‘07 production was 52.9 bcf/d.
•In 2 years production grew by 4.7 bcf/d or 9%.
Pearce Hammond, CFA | 713.546.7269 | [email protected]
12
LNG Liquefaction Additions Could be Significant in 2009/2010
Note: Projects are subject to further delays.
Country Facility Primary Market 3Q'08 4Q'08 1Q'09 2Q'09 3Q'09 4Q'09 2010 2011Nigeria NLNG, Train 6 Atlantic Basin 0.5 0.5 0.5 0.5 0.5Qatar QatarGas II, Train 4 Europe, UK 1.0 1.0 1.0 1.0 1.0Qatar RasGas, Train 6 NAM 1.0 1.0 1.0 1.0
Australia NWS, Train 5 Japan, Korea 0.6 0.6 0.6 0.6 0.6 0.6 0.6Indonesia Tangguh Mexico, Asia 1.0 1.0 1.0 1.0Yemen Yemen LNG, Train 1 US, Korea 0.4 0.4 0.4Yemen Yemen LNG, Train 2 US, Korea 0.4 0.4Russia Sakhalin II Asia, NAM-WC 0.6 0.6 0.6 1.3 1.3Qatar QatarGas II, Train 5 Europe, UK 1.0 1.0 1.0 1.0Qatar RasGas, Train 7 Asia & Other 1.0 1.0 1.0Qatar QatarGas III, Train 6 Asia, NAM 1.0 1.0Qatar QatarGas IV, Train 7 Asia 1.0Total 0.0 0.6 0.6 2.8 5.9 7.4 9.4 10.4
Liquefaction Capacity Summary (bcfd)
Pearce Hammond, CFA | 713.546.7269 | [email protected]
13
2008 LNG Imports by Country (bcfd)
US2.1110%
France1.256%
Spain2.3411%
India0.974%
Japan8.5939%
South Korea3.3315%
Taiwan1.065%
Other2.2610%
2008 LNG Exports by Country (bcfd)
Trinidad & Tobago
1.88%
Oman1.26%
Qatar3.8
17%
Algeria2.5
11%
Egypt1.46%
Nigeria2.19%
Australia2.09%
Brunei0.94%
Indonesia2.8
12%
Malaysia3.0
13%
Other1.15%
Key Nations Involved in LNG Trade
Pearce Hammond, CFA | 713.546.7269 | [email protected]
LNG Regas Capacity
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U.S. and NAM Capacity is plentifulBCFD 2007 2008 2009Cove Point 0.8 1.6 1.6Elba Island 0.8 0.8 0.8Everett 0.7 0.7 0.7Gulf Gateway 0.5 0.5 0.5Lake Charles 1.8 1.8 1.8Free Port 1.5 1.5NE Gateway 0.5 0.5Sabine Pass 2.6 4Cameron LNG 1.5Golden Pass 2Total U.S. Regas Capacity 4.6 10 14.9U.S. LNG Imports 2.1 1 2.1Utilization % 0.46 0.1 0.14Mexico and Canada AdditionsAltamira, Mexico 0.7 0.7 0.7Costa Azul, Mexico 1 1Canaport, Canada 1Total NAM Capacity 0.7 1.7 2.7Regas Capacity 5.3 11.7 17.6
Global Regas AdditionsCountry City BCM Planned Start DatesArgentina Buenos Aires 4 0.4 June-09
Bahia Blanca 1.5 0.1 Mid 2009Brazil Guanabara Bay 4.8 0.5 Mid 2009
Pecem FSRU 2 0.2 January-09Kuwait Mina al-Amadi 3 0.3 May-09India Ratnagiri 7.5 0.7 1Q 2009
Dahej Expansion 8.2 0.8 1Q 2009China Shanghai Y 4.1 0.4 Mid 2009Italy Adriatic LNG 8 0.8 Mid 2009France Fos Cavaou 8.3 0.8 Mid 2009U.K. Grain Expansion 9.1 0.9 November-09
South Hook 10.6 1 March-09Dragon 6 0.6 May-09
Canada Canaport 10.3 1 May-09U.S. Cameron 15 1.5 2Q 2009
Golden Pass 21.2 2.1 March-09Chile Mejillones 1.8 0.2 Late 2009
Quintero 3.4 0.3 Mid 2009128.8 12.6
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Does More Abundant Natural Gas Prevent Renewable Energy Adoption?
• No.
• Why? 1. Subsidy support
2. Gas compliments renewables.
3. Renewables produce little to no carbon.
4. Renewable Portfolio Standards.
5. Increasing EPA scrutiny of gas.
6. Crude-to-gas spread supports gas as a transportation fuel.
• But, cheap natural gas does create a headwind for the sector.
15
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Subsidy Support
• LCOE for a combined cycle gas plant at $5.00/mmbtu gas with a $25/ton carbon price is $0.054/kwh.
• Onshore wind is $0.06-$0.09/kwh.
• Tough to compete for wind, but there is a subsidy (Production Tax Credit) of $0.021/kwh which help close the gap and mandates which stimulate demand.
• In addition, there are opportunities to lower wind technology costs (as well as other alternative energy technologies) over time.
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Pearce Hammond, CFA | 713.546.7269 | [email protected]
Gas Compliments Renewables
• More abundant natural gas is much more a threat to coal and nuclear power both for new builds (coal, nuke) and existing capacity (coal).
• In ‘09, the U.S. coal industry lost ~40 MM tons of demand (4% of ‘08 utility coal burn) due to lower priced natural gas.
• Gas-fired generation can cycle up/down quickly making it ideal to compliment with intermittent renewable power generation.
17
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Renewables Produce Little to No Carbon
• While the global warming movement might be peaking (temporarily?), there is still a strong desire among citizens to have cleaner, more efficient forms of generation.
• While gas produces less carbon than does coal, it still produces carbon.
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Pearce Hammond, CFA | 713.546.7269 | [email protected]
Proposed Climate Legislation: U.S. CO2 Emissions
19
The Waxman Bill calls for a 17% reduction of greenhouse gases (GHG) from ‘05 levels by 2020.
In 2005, U.S. energy-related CO2 emissions were 5,975 MM tonnes. Therefore, the Waxman Bill is calling for energy-related CO2 emissions to reach 4,960 MM tonnes by 2020 (-1.2% CAGR).
Total emissions of U.S. GHG were 7,282 MM tonnes in 2007. Energy-related CO2 emissions accounted for 81% of that total.
Between 1988-2008, U.S. CO2 emissions increased to 5,802 MM tonnes from 4,993 MM tonnes (0.75% CAGR).
Electricity accounts for 41% of U.S. CO2 emissions with coal 81% of total electricity-related CO2 emissions.
0
1,000
2,000
3,000
4,000
5,000
6,000
7,00019
4919
5219
5519
5819
6119
6419
6719
7019
7319
7619
7919
8219
8519
8819
9119
9419
9720
0020
0320
06
CO2
(in M
M to
nnes
)
Electricity Transportation Industrial Commercial Residential
U.S. Energy-Related CO2 Emissions
Source: EIA.
2007 U.S. CO2 Emissions by End Use
Source: EIA.
Electricity41%
Transportation33%
Industrial16%
Commercial4%
Residential6%
U.S. Electricity CO2 Emissions
Source: EIA.
Petroleum3%
Coal 81%
Natural Gas15%
Other1%
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Proposed Climate Legislation: Impact to Alternative Energy
20
What is the impact from a combined nationwide RES and climate bill? In the first scenario, we assumed that non-hydro renewables increased their share from 3% currently to 15%. Moreover, we
assumed that the U.S. reached the 17% CO2 reduction target. The impacts:
• Coal’s share of U.S. electricity would decline from 49% currently to 32% (2.4% per annum decline between ’07-’20).• Natural gas’ share of U.S. electricity would increase to 29% from 21% and this would result in incremental gas
demand (from ’07 levels) of 10.6 bcf/d.• Non-hydro renewable capacity would increase from 46 GW to 264 GW or 218 GW of incremental capacity. This
represents a staggering 19.8 GW per annum of additional capacity over the next 11 years. To place this figure in perspective, the U.S. wind industry installed a record 8.4 GW of turbines in 2008.
Under all scenarios that we ran, renewables increased share and natural gas demand increased. Keep in mind that running the existing U.S. combined cycle fleet at a 60% capacity factor (instead of 38%) could result in 8.1 bcf/d
of incremental gas demand.
Scenario One: 2020 Generation with 15% Renewable Assumption – Reaching 17% CO2 Reduction
Source: EIA , SNL Energy and Simmons & Co. International.
TypeCapacity
(GW)Capacity Factor
GWhs (in 000s)
CO2 Footprint (tonnes of CO2/MWh)
CO2 Emissions (MM tonnes)
% Electricity Mix
'07-'20 GWhs CAGR
Coal 315.7 53.0% 1,466 0.956 1,401 31.7% -2.42%Petroleum 51.8 10.0% 45 0.800 36 1.0% -2.81%
Combined Cycle Gas 205.5 65.9% 1,187 0.400 475 25.7%Peaker Gas 210.9 7.4% 137 0.570 78 3.0%
Total Gas 416.4 36.3% 1,324 0.418 553 28.7% 2.93%Nuclear 101.7 93.0% 828 0.000 0 17.9% 0.21%Hydro 99.7 30.0% 262 0.000 0 5.7% 0.66%
Non-Hydro Renewables 264 30.0% 693 0.000 0 15.0% 15.60%Total 1,248.9 4,618 1,990 100.0%
CO2 Emission Target by 2020 1,990
Pearce Hammond, CFA | 713.546.7269 | [email protected]
21
Carbon Legislation: Impact to Merchants
0.44
0.850.89 0.90
0.97
0.40
0.50
0.60
0.70
0.80
0.90
1.00
CPN DYN NRG RRI MIR
CO2
Tons
/MW
h
IPP Carbon Intensity Fuel Mix by Region
Fuel Type Carbon Tons/MWhCoal 1.0Fuel Oil 1.0Combustion Turbine 0.6Combined Cycle 0.4Geothermal 0.1
Carbon Intensity by Fuel Type
•For coal fired generators that operate in markets where gas sets the price of power (NRG in Texas, Mirant in PJM East, and RRI in Central PJM), carbon legislation has the potential to significantly reduce margins.
•If carbon legislation is stringent enough, combined cycle assets have the ability to displace coal fired capacity especially in the Southeast.
• In markets where high heat rate combustion turbine (CT) gas assets often set the price of power, efficient CCGT gas assets should see a benefit in spark spreads.
•CPN benefits from stringent carbon legislation
Current legislation passed in the House is extremely favorable to coal based merchants and should cause minimal earnings detriment over the next decade.
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Renewable Portfolio Standards
State renewable portfolio standard
State renewable portfolio goal
www.dsireusa.org / January 2010
Solar water heating eligible*†
Extra credit for solar or customer-sited renewables
Includes non-renewable alternative resources
WA: 15% by 2020*
CA: 33% by 2020
☼ NV: 25% by 2025*
☼ AZ: 15% by 2025
☼ NM: 20% by 2020 (IOUs)
10% by 2020 (co-ops)
HI: 40% by 2030
☼ Minimum solar or customer-sited requirement
TX: 5,880 MW by 2015
UT: 20% by 2025*
☼ CO: 20% by 2020 (IOUs)
10% by 2020 (co-ops & large munis)*
MT: 15% by 2015
ND: 10% by 2015
SD: 10% by 2015
IA: 105 MW
MN: 25% by 2025(Xcel: 30% by 2020)
☼ MO: 15% by 2021
WI: Varies by utility;
10% by 2015 goal
MI: 10% + 1,100 MW by 2015*
☼ OH: 25% by 2025†
ME: 30% by 2000New RE: 10% by 2017
☼ NH: 23.8% by 2025
☼ MA: 15% by 2020
+ 1% annual increase(Class I Renewables)
RI: 16% by 2020
CT: 23% by 2020
☼ NY: 24% by 2013
☼ NJ: 22.5% by 2021
☼ PA: 18% by 2020†
☼ MD: 20% by 2022
☼ DE: 20% by 2019*
☼ DC: 20% by 2020
VA: 15% by 2025*
☼ NC: 12.5% by 2021 (IOUs)
10% by 2018 (co-ops & munis)
VT: (1) RE meets any increase in retail sales
by 2012; (2) 20% RE & CHP by
2017
29 states &
DC have an RPS
6 states have goals
KS: 20% by 2020
☼ OR: 25% by 2025 (large utilities)*
5% - 10% by 2025 (smaller utilities)
☼ IL: 25% by 2025
WV: 25% by 2025*†
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Increased EPA Scrutiny of Gas
• Hydraulic fracturing has come under pressure.
• Water usage is also a concern.
• Look for the coal lobby to strike back.
23
Pearce Hammond, CFA | 713.546.7269 | [email protected]
24
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Crude-Gas Spread Supports Gas as a Transportation Fuel
• Compressed natural gas is cheaper than diesel and gasoline.
• Retail pump prices for CNG total $2.00/GGE (gallon of gasoline equivalent) in Houston and even lower in other parts of the country where stations or pipeline natural gas is more available.
• This compares with retail gasoline at $2.67/gal.
• The spread of $0.67/GGE or 25% discount is enticing and falls just short of the average discount for CNG over the last 4.5 years of 28%.
• Potential: if 10% of the total regional trucking fleet in the U.S. switched to natural gas, this would equate to 3 bn GGE’s annually or 1 Bcf/d of incremental demand.
25
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Crude-Gas Spread Supports Gas as a Transportation Fuel
26
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Alternative Energy: Key Trends for 2010
1. No carbon bill in D.C., but maybe an energy bill.
2. More robust capital markets.
3. Consolidation
4. Better demand and financing.
5. Higher interest rates
27
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Conclusion
• Shale gas appears to be a significant change to the energy landscape.
• More abundant natural gas does make it more difficult to adopt renewables, but it does not prevent adoption.
• More abundant natural gas ultimately is a headwind for the renewable energy sector.
• There are complimentary adoption strategies for renewables and natural gas: bridge fuel to lower carbon era and solution for renewable intermittency.
• We believe it is of paramount importance that investors focus on those alternative energy technologies that illustrate the clearest path to becoming economic without a subsidy.
28
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Q&A
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Appendix
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Technology Cost Comparison
31
Non-Subsidized Levelized Cost of Electricity
Source: EIA, IEA, Simmons & Co. International.
Technology Capital Cost ($/kw)Delivered Fuel Cost ($/mmbtu)
Levelized Cost (cents/kwh)
Levelized Cost with $15/ton CO2
(cents/kwh)
Levelized Cost with $25/ton CO2
(cents/kwh)
U.S. Installed Capacity - Net Summer Capacity (GW)
Global Installed Capacity
(GW)
Energy Consumption to
Produce 1 kw
Coal $2,000-$2,500 3.13 5.0-6.0 7.0-7.5 8.0-8.5 315 1,382 ~1lb of coal
Natural Gas--Combined Cycle
$800-$1,000 7.00 6.50 7.00 7.50 200 1,124* 7,000 btu
Natural Gas--Peaker $500-$800 7.00 11.5-12.5 12.5-13.5 13-14 220 * 12,000 btu
Hydro $4,000+ Free 4.00 4.00 4.00 100 919 Free
Nuclear $5,000-$6,000 0.67 8.400 8.400 8.400 100 368 <1g of uranium
Oil $700-$1,000 8.93 12.5-13.0 13.5-14.0 14.5-15.0 50 415 10,000 btu
Solar PV $4,000-$6,000 Free 21-32 21-32 21-32 2 16 Free
Wind--Onshore $1,800 - $2,000 Free 6.0-9.0 6.0-9.0 6.0-9.0 25 130 Free
Wind--Offshore $4,000+ Free 10-12 10-12 10-12 0 2 Free
Tra
dit
ion
al E
ner
gy
Alt
ern
ativ
e E
ner
gy
Pearce Hammond, CFA | 713.546.7269 | [email protected]
33
Wind: Growth Forecast
Wind Sector Demand Overview (in MW)
Source: Global Wind Energy Council and BTM Consult
RegionAccum.
end of 20052005 2006 2007 2008 2009E 2010E 2011E 2012E 2013E
Total Accum.
Americas 10,061 2,671 3,515 5,815 9,527 7,650 10,450 12,450 16,200 18,300 93,968
Europe 40,857 6,372 7,682 8,285 9,179 11,580 13,505 15,900 18,080 20,150 145,218
South & East Asia 5,743 1,836 3,220 5,010 8,201 9,650 10,300 12,400 13,400 15,300 83,224
OECD - Pacific 2,121 484 491 597 1,051 1,100 1,350 1,600 1,900 2,250 12,460
Other Areas 412 44 109 86 232 645 1,035 1,470 1,810 2,520 8,319Total MW New Capacity Every Year
11,407 15,017 19,791 28,190 30,625 36,640 43,820 51,390 58,520 343,153
Accumulated Capacity (MW)
59,194 74,211 94,002 122,158 152,783 189,423 233,243 284,633 343,153
2009 growth stunted – market expectations -5% to +5% y/y. We believe ‘09 will be down y/y to 25 GW, ‘10 could be start
of next multi year ramp. Slightly slower growth rate: ~20% per annum moving forward instead of 25%.
5-year growth projections – doubling of annual market Grid dependent growth to ~900 GW by 2018 (8% of global
electric needs) U.S. Market Factors: RES, PTC extension, Obama energy policy Global Market Factors: Industry dealing with turbine over-
supply, EU 20% by 2020, China explosive growth, transmission is a great challenge.
Global Wind Installed Capacity Growth
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
E
2010
E
2011
E
2012
E
2013
E
MW
Installed MW Cumulative MW'08-'13E CAGRCumulative: 23%Installed: 16%
Source: BTM Consult.
Pearce Hammond, CFA | 713.546.7269 | [email protected]
2010 Solar Outlook
• We expect a relatively strong 1H’10 as installers rush to get German projects on the ground ahead of the speculated EEG decline. Overall, 2010 should be a better year than 2009.
• Supply/Demand: We are estimating 8.4 GW (+45% y/y) of module demand in 2010 with 13 GW of potential supply.
• ASPs: We estimate mid-$1.00/W by the end of 2010 for wholesale module prices. Some recent contracts have been between $1.60-$1.75/W.
• Key Market to Watch: Germany with EEG revision.
35
Pearce Hammond, CFA | 713.546.7269 | [email protected]
Current U.S. Generation Mix
36
Waxman Bill has Nationwide Renewable Electricity Standard (RES) that calls for 20% of U.S. electricity to come from non-hydro renewable sources by 2020. However, 5 percentage points can be met through energy efficiency leaving an effective RES of 15%.
In 2007, just 3% of U.S. electricity was from non-hydro renewable sources.
2008 U.S. Net Renewable (Non-Hydro) Electrical Generation
Coal49%
Petroleum Liquids
1%Petroleum Coke
0%
Natural Gas21%
Other Gases0%
Nuclear20%
Total Hydro
6%
Total Non-Hydro Renewables
3%
Other0%
2008 U.S. Generation by Fuel
Source: IEA Source: IEA
Wind42.09%
Solar (Thermal +
PV)0.68%
Wood31.38%
Geothermal12.02%
Other Biomass13.82%
Pearce Hammond, CFA | 713.546.7269 | [email protected]
37
Unconventional Gas Metrics
MetricsMarcellus
(dry)Horn River
Eagle Ford
Fayetteville (core)
Barnett (Core)
Haynesville WoodfordAnadarko-Woodford
Jonah/ Pinedale
(vert)
Granite Wash
Piceance (vert)
James Lime
Uinta (vert)
CV (vert)
Nora CBM RatonPowder
RiverSan Juan
Cost per Well ($MM) $3.7 $10.0 $5.0 $3.1 $2.8 $7.5 $5.0 $8.0 $5.3 $6.0 $1.6 $2.7 $1.7 $1.7 $0.4 $0.5 $0.3 $1.9EUR per Well (Bcfe) 3.5 10.0 5.5 2.6 3.0 6.5 4.0 8.1 3.9 6.4 1.0 2.0 1.2 1.0 0.4 0.6 0.3 1.4Royalty (%) 15% 15% 25% 20% 25% 25% 15% 20% 15% 15% 17% 20% 17% 20% 15% 15% 13% 17%F&D Cost ($/Mcfe) $1.24 $1.18 $1.22 $1.48 $1.23 $1.54 $1.48 $1.25 $1.60 $1.11 $1.87 $1.71 $1.71 $2.18 $1.20 $1.15 $1.16 $1.72IP Rate (MMcf/d) 3.5 8.2 9.0 2.8 2.5 14.0 3.6 6.0 5.0 7.5 1.0 5.0 1.2 1.0 0.04 0.09 0.04 0.14Differential (%) 3% -15% 12% -8% -8% -2% -8% -8% -18% -8% -15% -5% -15% -7% 3% -15% -15% -15%LOE ($/Mcfe) 0.90 1.00 0.95 0.70 0.90 0.85 0.80 0.75 0.70 0.80 0.85 1.06 0.85 0.92 0.70 1.61 2.50 1.05G&A ($/Mcfe) 0.55 0.55 0.55 0.00 0.00 0.55 0.00 0.00 0.55 0.55 0.55 0.55 0.55 0.55 0.55 0.55 0.55 0.55Production tax (%) 5% 5% 5% 5% 8% 33% 7% 7% 6% 8% 6% 2% 6% 2% 3% 12% 12% 13%1st Yr Decline (%) -62% -65% -82% -64% -65% -85% -59% -58% -76% -72% -58% -86% -63% -67% 66% 57% 214% 254%2nd Yr Decline (%) -35% -34% -41% -35% -34% -41% -43% -34% -35% -37% -35% -46% -34% -33% -7% 0% 11% 11%3rd Yr Decline (%) -21% -19% -22% -21% -19% -26% -32% -22% -9% -30% -22% -35% -16% -18% -9% 2% 8% -4%Out Yr Decline (%) -5% -6% -5% -5% -6% -5% -5% -6% -10% -6% -5% -6% -6% -7% -6% -5% -18% -17%Threshold Price ($/Mcfe) $3.85 $5.25 $4.10 $3.95 $4.10 $4.90 $5.00 $4.50 $5.75 $4.40 $5.70 $5.03 $5.80 $6.65 $5.20 $6.00 $6.50 $6.25Source: Various Company reports
Tight Gas CBMShales
Pearce Hammond, CFA | 713.546.7269 | [email protected]
38
Appendix D
• Appendix D• Analyst Certification:
I, Pearce Hammond, hereby certify that the views expressed in this research report to the best of my knowledge, accurately reflect my personal views about the subject compan(ies) and its (their) securities; and that, I have not been, am not, and will not be receiving direct or indirect compensation in exchange for expressing the specific recommendation(s) or views in this research report.
Important Disclosures: For detailed rating information, go to http://publicdisclosure.simmonsco-intl.com. Additional information is available upon request. Simmons & Company's ratings system categorizes individual stock performance as Underweight, Neutral or Overweight relative to the performance of the S&P 500 Index and its discrete energy sub-sector over a 12 month period. Research analysts compensation is based upon (among other things) the firm's general investment banking revenues. Simmons & Company International may seek compensation for investment banking services from other companies for which research coverage is provided. The firm would expect to receive compensation for any such services. Foreign Affiliate Disclosure: This report may be made available in the United Kingdom through distribution by Simmons & Company International Capital Markets Limited, a firm authorized and regulated by the Financial Services Authority to undertake designated investment business in the United Kingdom. Simmons & Company International Capital Markets Limited's policy on managing investment research conflicts is available by request. The research report is directed only at persons who have professional experience in matters relating to investments who fall within the definition of investment professionals in Article 19(5) Financial Services and Markets Act (Financial Promotion) Order 2001 (as amended) ("FPO"); persons who fall within Article 49(2)(a) to (d) FPO (high net worth companies, unincorporated associations etc.) or persons who are otherwise market counterparties or intermediate customers in accordance with the FSA Handbook of Rules and Guidance ("relevant persons"). The research report must not be acted on or relied upon by any persons who receive it within the EEA who are not relevant persons. Simmons & Company International Capital Markets Limited is located at Sackville House, 40 Piccadilly, Mezzanine, London, United Kingdom.
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