Pearce W. Hammond, Jr., C.F.A. Director, Institutional Research Simmons & Company International The...

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


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


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

4


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


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?


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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5-Dec-08 5-Feb-09 5-Apr-09 5-Jun-09 5-Aug-09 5-Oct-09 5-Dec-09

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Directional Horizontal Vertical

650

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26-Sep-08 26-Dec-08 26-Mar-09 26-Jun-09 26-Sep-09 26-Dec-09

Gas

-Dir

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d Ri

g Co

unt

SmithBits Actual Data

Drop from peak-783


8

Rig Count Breakdown and Unconventional Production Outlook

0%

10%

20%

30%

40%

50%

60%

70%

80%

0.0

5.0

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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%


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

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10,000,000

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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


Case Study: Southwestern Energy Efficiency Gains

10

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


U.S. Gas Production

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44

46

48

50

52

54

56

58

60

Jan-

06

Apr

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-06

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-08

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8

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-08

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Apr

-09

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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%.


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)


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


LNG Regas Capacity

14

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


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


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.

16


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


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.

18


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%


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


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.


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*†


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


24


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


Crude-Gas Spread Supports Gas as a Transportation Fuel

26


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


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


Q&A


Appendix


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

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ner

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Alt

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gy


Wind

32


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.


Solar

34


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


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%


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


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.

Disclaimer: This e-mail is based on information obtained from sources which Simmons & Company International believes to be reliable, but Simmons & Company does not represent or warrant its accuracy. The opinions and estimates contained in the e-mail represent the views of Simmons & Company as of the date of the e-mail, and may be subject to change without prior notice. Simmons & Company International will not be responsible for the consequence of reliance upon any opinion or statement contained in this e-mail. This e-mail is confidential and may not be reproduced in whole or in part without the prior written permission of Simmons & Company International.

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