2009 wind technologies market report · italy 1,114 italy 4,845 france1,104 4,775 u.k. 1,077 u.k....

Energy Efficiency & Renewable Energy eere.energy.gov

1

Program Name or Ancillary Text eere.energy.gov

WIND AND WATER POWER PROGRAM

1

2009 Wind Technologies Market Report

Ryan Wiser and Mark Bolinger

Lawrence Berkeley

National Laboratory

Report Summary

August 2010


2

Presentation Overview• Introduction to 2009 edition of

U.S. wind energy market report

• Wind installation trends

• Wind industry trends

• Price, cost, and performance trends

– Power sales prices

– Installed wind project costs

– Wind turbine transaction prices

– Wind project performance

– O&M cost trends

• Policy and market drivers

• Future outlook


3

2009 Wind Technologies Market Report

Purpose, Scope, and Data:

• With a focus on 2009, summarize trends in the U.S. wind power market,

including information on wind installations, industry developments, power

sales prices, project costs, performance, O&M costs, policy/market trends

• Scope primarily includes wind turbines and projects over 100 kW in size

• Data sources include AWEA, EIA, FERC, SEC, etc. (see full report)

Report Authors:

• Primary authors: Ryan Wiser and Mark Bolinger, Berkeley Lab

• Contributions from others at Berkeley Lab, Exeter Associates, NREL

Available at: http://windandwater.energy.gov/


4

New to the 2009 Edition of the Report

• Turbine and component imports into the U.S., and import share

• Trends in hub height and rotor diameter of installed projects

• Expanded discussion of the offshore wind energy sector

• Data on wind power curtailment in Texas and the Midwest

• Impact of the Recovery Act on the U.S. wind power industry


5

Installation Trends


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Annual US Capacity (left scale)

Cumulative US Capacity (right scale)

Cu

mu

lative

Ca

pa

city (

GW

)

An

nu

al C

ap

acity (

GW

)

6

Record year for new U.S. wind power capacity:

• 10 GW of wind power added in 2009, bringing total to ~35 GW

• Nearly $21 billion in 2009 project investment

U.S. Wind Power Capacity Up >40% in 2009


7

Wind Power Contributed 39% of All New Generating Capacity in the U.S. in 2009

Wind was the 2nd-largest resource added for the 5th-straight year

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

To

tal A

nnual

Cap

acity A

dd

itio

ns (G

W)

Other non-Renewable

Coal

Gas (non-CCGT)

Gas (CCGT)

Other Renewable

Wind

Source: EIA, Ventyx, AWEA, IREC, Berkeley Lab

44% wind

39% wind

42% wind42% wind

42% wind42% wind

35% wind18% wind

12% wind

2% wind

3% wind

1% wind

4% wind

0% wind


8

U.S. Led World in Cumulative Capacity, But Fell to 2nd in Annual Capacity Growth

Annual Capacity

(2009, MW)

Cumulative Capacity

(end of 2009, MW)

China 13,750 U.S. 35,155

U.S. 9,994 China 25,853

Spain 2,331 Germany 25,813

Germany 1,917 Spain 18,784

India 1,172 India 10,827

Italy 1,114 Italy 4,845

France 1,104 France 4,775

U.K. 1,077 U.K. 4,340

Canada 950 Portugal 3,474

Portugal 645 Denmark 3,408

Rest of World 4,121 Rest of World 22,806

TOTAL 38,175 TOTAL 160,080

Source: BTM Consult; AWEA project database for U.S. capacity


9

U.S. Share of Global Wind Power Capacity: 26% of 2009 Additions, 22% of Cumulative

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. P

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Cumulative Non-US Capacity (right scale)

Cumulative US Capacity (right scale)

US Proportion of Annual Growth (left scale)

Cum

ula

tive C

ap

acity (G

W)


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alia

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rke

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ina

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zil

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pa

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TO

TA

L

Approximate Wind Penetration, end of 2009




Pro

jecte

d W

ind

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ctr

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s a

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lectr

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U.S Lagging Other Countries in Wind As a Percentage of Electricity Consumption

Note: Figure only includes the 20 countries with the most installed

wind power capacity at the end of 2009


11

Geographic Spread of Wind Power Projects in the United States Is Reasonably Broad


12

Texas Easily Led Other States in Both Annual and Cumulative Capacity

• 14 states had >1000 MW of wind capacity at the end of 2009 (3 had >2000 MW)

• 4 states have in-state wind generation that exceeds 10% of total in-state generation (10 states exceed 5%)

Annual Capacity

(2009, MW)

Cumulative Capacity

(end of 2009, MW)

Estimated Percentage of

In-State Generation

Texas 2,292 Texas 9,410 Iowa 19.7%

Indiana 905 Iowa 3,670 South Dakota 13.3%

Iowa 879 California 2,798 North Dakota 11.9%

Oregon 754 Washington 1,908 Minnesota 10.7%

Illinois 632 Oregon 1,821 Oregon 9.0%

New York 568 Minnesota 1,810 Colorado 7.7%

Washington 542 Illinois 1,547 Kansas 7.4%

North Dakota 488 New York 1,274 Texas 6.8%

Wyoming 425 Colorado 1,246 Wyoming 6.7%

Pennsylvania 388 North Dakota 1,203 Oklahoma 5.0%

Oklahoma 299 Oklahoma 1,130 Montana 4.9%

California 281 Wyoming 1,101 Washington 4.9%

Utah 204 Indiana 1,036 New Mexico 4.6%

Kansas 199 Kansas 1,014 California 3.4%

Colorado 178 Pennsylvania 748 Maine 3.1%

Missouri 146 New Mexico 597 Idaho 3.0%

Maine 128 Wisconsin 449 Indiana 2.7%

South Dakota 126 Montana 375 New York 2.2%

Montana 104 West Virginia 330 Hawaii 2.2%

New Mexico 100 South Dakota 313 Illinois 2.1%

Rest of U.S. 358 Rest of U.S. 1,376 Rest of U.S. 0.3%

TOTAL 9,994 TOTAL 35,155 TOTAL 2.5% Source: AWEA project database, EIA, Berkeley Lab estimates


13

Wind Now >10% of Nine Utilities’ Sales

See full report for

the many

assumptions used

to generate the

data in this table

Total Wind Capacity

(end of 2009, MW)

Estimated Percentage of Retail Sales

(for utilities with > 100 MW of wind)

Xcel Energy 3,176 Minnkota Power Cooperative 38.0%

MidAmerican Energy 2,923 Empire District Electric Company 18.1%

Southern California Edison 1,772 Turlock Irrigation District 18.0%

American Electric Power 1,196 Otter Tail Power 14.0%

Pacific Gas & Electric 1,131 Sunflower Electric Power Corp. 13.2%

Luminant 913 Xcel Energy 11.1%

Alliant Energy 645 Austin Energy 10.3%

City Public Service of San Antonio 579 Great River Energy 10.1%

Puget Sound Energy 479 Westar 10.1%

Austin Energy 439 Western Farmers' Electric Cooperative 9.8%

First Energy 376 MidAmerican Energy 9.6%

Portland General Electric 375 Snohomish PUD 8.5%

Minnkota Power Cooperative 357 MSR Public Power Agency 8.4%

Basin Electric 352 City Public Service of San Antonio 8.4%

SDG&E 342 Public Service New Mexico 6.8%

Great River Energy 319 Cowlitz PUD 6.5%

Westar 295 WPPI Energy 6.4%

Oklahoma Gas & Electric 272 Alliant Energy 5.9%

Empire District Electric Company 255 Puget Sound Energy 5.4%

SCPPA (not including LADWP) 233 Northwestern Energy 5.3% Source: AWEA, EIA, Berkeley Lab estimates


14

No Offshore Projects Have Been Built in the U.S., But 13 Projects Are At a More-Advanced Permitting/Development Stage

• Three projects have signed or proposed power purchase agreements

• Cape Wind granted approval by Department of Interior in April 2010


15

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Wind Natural Gas Coal Nuclear Solar Other

Nam

epla

te C

apacity (

GW

)

Entered Queue in 2009 Total in queue at end of 2009

Roughly 300 GW of Wind Power Capacity in Transmission Interconnection Queues

Not all of this capacity will be built….

Nearly three times as much wind power as

next-largest resource (natural gas) in queues


16

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MISO /

Midwest

Mountain ERCOT PJM SPP Northwest California

ISO

New York

ISO

ISO-New

England

Southeast

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epla

te W

ind P

ow

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Capacity (

GW

)

Entered queue in 2009 Total in queue at end of 2009

>90% Planned for Midwest, Mountain, ERCOT, PJM, SPP, and Northwest Regions

Not all of this capacity will be built….


17

Market for Small Wind Turbines Continued to Grow in 2009

• Sales of small wind turbines (turbine size to 100 kW) in the U.S. equaled

20.3 MW in 2009, or $82 million

• Roughly 15% growth in annual sales (in capacity terms), relative to 2008,

yielding cumulative capacity of roughly 100 MW

Year Annual Sales of Small Wind Turbines into the United States

Number of Turbines Capacity Additions Sales Revenue

2005 4,324 3.3 MW $10 million

2006 8,329 8.6 MW $33 million

2007 9,092 9.7 MW $42 million

2008 10,386 17.4 MW $73 million

2009 9,800 20.3 MW $82 million

Source: AWEA (2010b)


18

Industry Trends


19

GE Remained the Top Turbine Vendor in the U.S. Market, But a Growing Number of Other Manufacturers Are Capturing Market Share

0%

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. M

ark

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are

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Nordex

Acciona

REpower

Gamesa

Clipper

Suzlon

Mitsubishi

Siemens

Vestas

GE Wind


20

Most Wind Turbine Vendors Active in the U.S. Market Saw Growth in 2009

Turbine Installations (MW) Manufacturer

2005 2006 2007 2008 2009

GE Wind 1,433 1,146 2,342 3,585 3,995

Vestas 700 439 948 1,120 1,490

Siemens 0 573 863 791 1,162

Mitsubishi 190 128 356 516 814

Suzlon 25 92 197 736 702

Clipper 3 0 48 470 605

Gamesa 50 74 494 616 600

REPower 0 0 0 94 330

Acciona 0 0 0 410 204

Nordex 0 0 3 0 63

Other 2 2 0 12 31

TOTAL 2,402 2,454 5,249 8,350 9,994

• Chinese and South Korean manufacturers seeking entry into U.S. market

• For first time in 2009, a turbine vendor from China (Goldwind) saw sales in the U.S.


21

U.S. Wind Turbine Manufacturing Strong, But With Slower Growth

Note: map is not intended to be exhaustive

• AWEA estimates that the wind power sector provided roughly 85,000 full-time jobs in the U.S. at the end of 2009 (18,500 of which were in manufacturing)

• 7 of the 10 wind turbine vendors with the largest share of the U.S. market in 2009 have one or more manufacturing facilities operating in the U.S., while 2 of the remaining 3 have announced specific plans to open facilities in the future


0

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2006 2007 2008 2009

Billio

n 2

009$

Total Turbine Equipment Cost

(Calendar Year)

Value of Selected Imports

(Customs Value, 4 month lag,

Sept - Aug)

85% of turbine cost

73% of turbine cost

48% of turbine cost

39% of turbine costImport Fraction

22

A Growing % of Equipment Used in U.S.

Projects Has Been Sourced Domestically

• U.S. is largest importer of wind equipment; 7th largest exporter

• Wind power capacity growth has outpaced import growth

See full report for the

many assumptions

used to generate the

data in this figure


23

Average Turbine Size Higher in 2009

25% of turbines installed in 2009 were larger than 2.0 MW, up from

19% in 2008, 16% in 2006 & 2007, and just 0.1% in 2004-05

0.71 MW

0.88 MW

1.21 MW

1.43 MW

1.60 MW1.65 MW 1.66 MW

1.74 MW

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2.0

1998-99 2000-01 2002-03 2004-05 2006 2007 2008 2009

1,425 turbines 1,987 turbines 1,757 turbines 1,960 turbines 1,536 turbines 3,190 turbines 5,029 turbines 5,734 turbines

1,016 MW 1,758 MW 2,125 MW 2,803 MW 2,454 MW 5,249 MW 8,350 MW 9,994 MW

Avera

ge T

urb

ine S

ize (

MW

)


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1998-99 1283 turbines

935 MW

2000-011500 turbines

1,446 MW

2002-03 2004 turbines

2,227 MW

2004-05 1807 turbines

2,680 MW

20061500 turbines

2,394 MW

2007 2922 turbines

5,001 MW

20085047 turbines

8,376 MW

20095734 turbines

9,994 MW

Ave

rag

e R

oto

r D

iam

ete

r an

d H

ub

He

igh

t (m

)

Rotor Diameter

Hub Height

Average Hub Heights and Rotor Diameters Have Increased Over Time

On average, since 1998-99, hub heights are 22 meters (39%)

higher and rotor diameters are 33 meters (69%) larger


25

Average Project Size Resumed Its Upward Trend in 2009

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1998-99 2000-01 2002-03 2004-05 2006 2007 2008 2009

29 projects 27 projects 46 projects 44 projects 35 projects 45 projects 97 projects 110 projects

Nam

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te C

apacity (

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Average project size, by COD (excludes projects < 2 MW)


26

Investor Transaction Type Developer Announcement Date EDF (SIIF Energies) Acquisition enXco May-02

Gamesa Investment Navitas Oct-02

AES Investment U.S. Wind Force Sep-04

PPM (Scottish Power) Acquisition Atlantic Renewable Energy Corp. Dec-04

AES Acquisition SeaWest Jan-05

Goldman Sachs Acquisition Zilkha (Horizon) Mar-05

JP Morgan Partners Investment Noble Power Mar-05

Arclight Capital Investment CPV Wind Jul-05

Diamond Castle Acquisition Catamount Oct-05

Pacific Hydro Investment Western Wind Energy Oct-05

EIF U.S. Power Fund II Investment Tierra Energy, LLC Dec-05

Airtricity Acquisition Renewable Generation Inc. Dec-05

Babcock & Brown Acquisition G3 Energy LLC Jan-06

Iberdrola Acquisition Community Energy Inc. Apr-06

Shaw/Madison Dearborn Investment UPC Wind May-06

NRG Acquisition Padoma Jun-06

CPV Wind Acquisition Disgen Jul-06

BP Investment Clipper Jul-06

BP Acquisition Greenlight Aug-06

Babcock & Brown Acquisition Superior Aug-06

Enel Investment TradeWind Sep-06

Iberdrola Acquisition Midwest Renewable Energy Corp. Oct-06

Iberdrola Acquisition PPM (Scottish Power) Dec-06

BP Acquisition Orion Energy Dec-06

Naturener Acquisition Great Plains Wind & Energy, LLC Feb-07

HSH Nordbank Investment Ridgeline Energy Feb-07

Energias de Portugal Acquisition Horizon Mar-07

Iberdrola Acquisition CPV Wind Apr-07

Duke Energy Acquisition Tierra Energy, LLC May-07

Acciona Acquisition EcoEnergy, LLC Jun-07

Babcock & Brown Acquisition Bluewater Wind Sep-07

Good Energies Investment EverPower Sep-07

E.ON AG Acquisition Airtricity North America Oct-07

Wind Energy America Acquisition Boreal Oct-07

Marubeni Investment Oak Creek Energy Systems Dec-07

NTR Investment Wind Capital Group Apr-08

Canadian Pension Plan Investment Noble Power Apr-08

ArcLight and Terra-Gen Acquisition Allco Wind Energy Jun-08

Duke Energy Acquisition Catamount Jun-08

Veolia Acquisition Ridgeline Energy Oct-08

Riverstone Holdings Acquisition Babcock & Brown Jun-09

Terra Firma Acquisition Everpower Wind Aug-09

APEX Wind Energy Acquisition BQ Energy, LLC Jun-09

Global Infrastructure Partners Investment Terra-Gen Power Holdings Nov-09

NRG Energy Acquisition Bluewater Wind Nov-09

Enel Investment Geronimo Wind Nov-09

* Select list of announced transactions; excludes joint development activity

Source: Berkeley Lab

Developer Consolidation Continued in 2009• But acquisitions and investments

still below 2006-2007 pace:

2009: 6 deals = 18 GW of wind development pipeline

2008: 5 deals = 19 GW

2007: 11 deals = 37 GW

2006: 12 deals = 34 GW

2005: 8 deals = 11 GW

2002-04: 4 deals = 4 GW

• Slackening might reflect the financial crisis, and that many of the prime targets for investment and/or acquisition had already been acquired in previous years


27

Treasury Cash Grant Expanded Financing Options, Buoyed the Wind Sector• Section 1603 of Recovery Act allows choice of a cash grant in lieu

of the PTC or ITC

– Reduces dependence on tax equity investors

– Enables greater use of project-level term debt instead of tax equity

• 6400 MW (>64%) of wind power capacity built in 2009 used grant

– As much as 2400 MW may not have been built in 2009 absent the grant

– Only about 7 of >60 projects that chose grant used third-party tax equity

• Efforts to extend the grant program focus on continued shortage of tax equity in the market

• Lenders (both banks and insurance companies) now back in the market, and with improving terms

• Relatively weak demand for federal loan guarantees


28

IPP Project Ownership Remained Dominant

• Utility ownership held steady in 2009

• Community wind market share stagnant since 2004

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

Cum

ula

tive I

nsta

lled C

apacity (

GW

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Community

Publicly Owned Utility (POU)

Investor-Owned Utility (IOU)

Independent Power Producer (IPP)

Community:

180 MW (2%)

IPP: 8,247 MW

(83%)

IOU:

1,057 MW

(11%)

POU:

510 MW (5%)

2009 Capacity by

Owner Type


29

Contracted Sales to Utilities Remained the Most Common Sales Arrangement

But “merchant” plants were surprisingly (due to tight credit and

sharply lower wholesale power prices) popular in 2009

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

Cum

ula

tive I

nsta

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apacity (

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On-Site

Power Marketer

Publicly Owned Utility (POU)

Merchant/Quasi-Merchant

Investor-Owned Utility (IOU)

Merchant:

3,779 MW

(38%)

IOU:

3,578 MW

(36%)

POU:

2,189 MW

(22%)

2009 Capacity by

Off-Take Category

Marketer:

399 MW (4%)

On-Site:

50 MW (0.5%)


30

Price, Cost, and

Performance Trends


31

Upward Pressure on Wind Power Prices Continued in 2009

• Berkeley Lab maintains a database of wind power sales prices; next few slides present data from that database

• Sample includes 180 projects built from 1998-2009, totaling 12,813 MW (38% of all wind capacity added in that period)

• Prices reflect the bundled price of electricity and RECs as sold by the project owner under a power purchase agreement

– Dataset excludes merchant plants and projects that sell renewable energy certificates (RECs) separately

– Prices reflect receipt of state and federal incentives (e.g., the PTC or Treasury grant); as a result, prices do not reflect wind energy generation costs -- prices would be higher were state/federal incentives not available


32

Cumulative Average Sales Price for Sample of Projects Built After 1997 Low But Rising

Increase in prices since 2005 due to rising prices from newly built projects,

but cumulative nature of graphic mutes degree of apparent price increase

0

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20

30

40

50

60

70

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

7 9 19 32 47 65 81 100 120 146 180

450 550 702 1,450 2,303 3,112 4,065 5,140 7,709 9,843 12,813

Cumulative Capacity-Weighted Average Wind Power Price (with 25% and 75% quartiles)

Win

d P

ow

er

Price (

2009 $

/MW

h)

Year:

Projects:

MW:

Sample includes projects built from 1998-2009


33

Binning by Commercial Operation Date Shows that Prices Have Increased Recently

Graphic shows prices in 2009 from projects built from 1998-2009

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90

1998-99 2000-01 2002-03 2004-05 2006 2007 2008 2009


612 MW 853 MW 1,655 MW 1,269 MW 751 MW 2,938 MW 2,106 MW 2,629 MW

Capacity-Weighted Average 2009 Wind Power Price (by project vintage)

Individual Project 2009 Wind Power Price (by project vintage)

2009 W

ind P

ow

er

Price (

2009 $

/MW

h)


34

Regional Differences Explain Some of the Underlying Variability in Wind Sales Prices

Texas and the Heartland are lower-price regions, while the East and California

are higher-price (note: sample size is problematic in many regions)

0

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30

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60

70

80

90

Texas Heartland Mountain Great Lakes Northwest New England California East


320 MW 3,171 MW 1,452 MW 1,485 MW 1,281 MW 29 MW 383 MW 302 MW

Capacity-Weighted Average 2009 Wind Power Price (by region)

Individual Project 2009 Wind Power Price (by region)

Capacity-Weighted Average 2009 Wind Power Price (total U.S.)

2009 W

ind P

ow

er

Price (

2009 $

/MW

h)

Sample includes projects built from 2006-2009


35

Regions and Wholesale Price Hubs Used in Analysis

Mid-C

SP-15

NP-15

COB

Mead

Palo Verde

Four Corners

ERCOT West •

• •

• •

•

•

•

Cinergy Hub

•

PJM West

•

• Mass Hub

NYISO A

NYISO G

• • •

Minnesota Hub

Michigan Hub

•

Illinois Hub •

Entergy •

• NI Hub

Missouri Zone

Iowa Zone °

WAUE Interface

°

°

° DOM Zone

° Maine Zone

Northwest California Mountain Texas Heartland Great Lakes East New England Southeast


36

Sharp Drop in Wholesale Power Prices Challenges the Competitiveness of Wind

• Wholesale price range reflects flat block of power across 23 pricing nodes (see previous map)

• Wholesale price drop reflects lower natural gas prices, driven by weak economy and shale gas

0

10

20

30

40

50

60

70

80

90

2003 2004 2005 2006 2007 2008 2009

47 projects 65 projects 81 projects 100 projects 120 projects 146 projects 180 projects

2,303 MW 3,112 MW 4,065 MW 5,140 MW 7,709 MW 9,843 MW 12,813 MW

2009 $

/MW

h

Nationwide Wholesale Power Price Range (for a flat block of power)

Cumulative Capacity-Weighted Average Wind Power Price (with 25% and 75% quartiles)

Wind project sample includes

projects built from 1998-2009


37

Wind’s Struggle to Compete in 2009 Spans All Regions of the U.S.

Note: Within a region there are a range of wholesale power prices because

multiple wholesale price hubs exist in each area (see earlier map)

0

10

20

30

40

50

60

70

80

90

Texas Heartland Mountain Great Lakes Northwest New England California East Total US

3 projects 44 projects 13 projects 11 projects 11 projects 2 projects 4 projects 6 projects 94 projects

320 MW 3,171 MW 1,452 MW 1,485 MW 1,281 MW 29 MW 383 MW 302 MW 8,424 MW

Average 2009 Wholesale Power Price Range (by region)

2009 Capacity-Weighted Average Wind Power Price (by region)

Individual Project 2009 Wind Power Price (by region)

Wind project sample includes projects built from 2006-2009

2009 $

/MW

h


38

Renewable Energy Certificate (REC) Markets Remain Fragmented and Volatile

REC prices vary by:• market type: compliance vs. voluntary

• geographic region

• specific design of state RPS policies

$0

$20

$40

$60

$80

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n-0

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High-Price REC Markets

CT Class I DE Class I IL Wind

MA Class I ME New NH Class I

NJ Class I RI New

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$/M

Wh

$0

$5

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Low-Price REC Markets

DC Tier 1 MD Tier 1

PA Tier 1 TX

National (Voluntary) West (Voluntary)


39

Wind Power Sales Prices Are Affected by Installed Project Costs...

0

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900 1100 1300 1500 1700 1900 2100 2300 2500 2700

Installed Cost (2009 $/kW)

200

9 W

ind P

ow

er

Price (

20

09

$/M

Wh)

Sample includes 120 projects built from 1998-2009, totaling 10,519 MW


40

...and by Wind Power Project Performance

0

10

20

30

40

50

60

70

80

90

15% 20% 25% 30% 35% 40% 45% 50%

2009 Capacity Factor (%)

200

9 W

ind P

ow

er

Price (

20

09

$/M

Wh)

Sample includes 149 projects built from 1998-2008, totaling 10,102 MW


41

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

19

82

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Insta

lled

Pro

ject

Co

st

(20

09

$/k

W)

Individual Project Cost (405 online projects totaling 28,522 MW)

Capacity-Weighted Average Project Cost

Polynomial Trend Line

Installed Project Costs Continued to Rise in 2009, After a Long Period of Decline

Rumors of cost declines abound, but have not yet been substantiated

by the data

Increase of ~$800/kW


42

Economies of Scale Evident At Low End of Project Size Range

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

≤ 5 MW 5-20 MW 20-50 MW 50-100 MW 100-200 MW >200 MW

48 MW 222 MW 888 MW 4,576 MW 10,518 MW 3,310 MW

23 projects 18 projects 24 projects 59 projects 75 projects 13 projects

Insta

lled P

roje

ct

Cost

(2009 $

/kW

)

Average Project Cost

Individual Project Cost

Sample includes projects built in 2007, 2008, and 2009

Cost trend essentially flat above 5-20 MW project size range


43

Some Regional Differences in Wind Power Project Costs Are Apparent

No clear low-cost leaders, but California & New England highest-cost

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Texas Mountain Heartland Great Lakes Northwest East California New England


5,361 MW 2,052 MW 5,169 MW 2,575 MW 2,371 MW 1,539 MW 326 MW 169 MW

Insta

lled P

roje

ct

Cost

(2009 $

/kW

)

Capacity-Weighted Average Project Cost

Individual Project Cost

Capacity-Weighted Average Cost, Total U.S.

Sample includes projects built in 2007, 2008, and 2009


44

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10

Announcement Date

Orders <100 MW

Orders from 100 - 300 MW

Orders >300 MW

Polynomial Trend Line

Tu

rbin

e T

ran

sa

ctio

n P

rice

(2

00

9 $

/kW

)

Project Cost Increases Are a Function of Wind Turbine Prices

Relative dearth of data since 2008 makes it hard to discern any recent trend, though turbine prices are rumored to be lower

Figure depicts reported transaction prices from 69 U.S. wind turbine orders totaling 22.9 GW


45

Average Capacity Factors Have Improved Over Time, But Leveled Off in Recent Years

• General improvement reflects increase in hub height and rotor diameter (see slide 24)

• Inter-annual wind resource variation also plays a role: 2009 was a bad wind year

• Curtailment was another major factor in lower 2009 capacity factor (see slide 47)

0%

5%

10%

15%

20%

25%

30%

35%

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

11 17 77 124 137 163 190 217 258 299 242

701 1,158 2,199 3,955 4,458 5,784 6,467 9,289 11,253 16,068 22,346

Capacity

Facto

r

Year:

Projects:

MW:


46

Binning by Project Vintage and Focusing on 2009 Performance Tells A Similar Story

Projects installed since 2005 have bucked the trend of generally

increasing capacity factors among more-recently built projects

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

Pre-1998 1998-99 2000-01 2002-03 2004-05 2006 2007 2008


674 MW 746 MW 1,571 MW 1,872 MW 2,691 MW 2,180 MW 4,505 MW 8,127 MW

Capacity-Weighted Average 2009 Capacity Factor (by project vintage)

Individual Project 2009 Capacity Factor (by project vintage)

2009 C

apacity F

acto

r (b

y p

roje

ct

vin

tage) Sample includes 260 projects totaling 22.37 GW


47

Curtailment a Major Issue in Texas (ERCOT)

If there had been no curtailment in 2009, ERCOT’s fleet-wide wind power project capacity factor would have been 31.1% (rather than 25.8%), raising the national average from 30% to 32%

0

500

1,000

1,500

2,000

2,500

3,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2007 2008 2009

GW

h

Curtailed Wind Generation

Actual Wind Generation

17% of Potential

Wind Generation

Curtailed in 20098% of Potential

Wind Generation

Curtailed in 2008

1% of Potential

Wind Generation

Curtailed in 2007


48

Regional Performance Differences Are Apparent

Average capacity factors highest in Hawaii and the Mountain region, lowest in Texas (again, due largely to curtailment) and the East

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

Texas East Great Lakes Northwest New England California Heartland Mountain Hawaii

30 projects 13 projects 13 projects 16 projects 6 projects 7 projects 65 projects 14 projects 1 project

5,398 MW 1,057 MW 1,446 MW 1,930 MW 73 MW 387 MW 5,650 MW 1,533 MW 30 MW

Capacity-Weighted Average 2009 Capacity Factor (by region)

Individual Project 2009 Capacity Factor (by region)

Capacity-Weighted Average 2009 Capacity Factor (total U.S.)

2009 C

apacity F

acto

r (b

y r

egio

n)

Sample includes 165 projects built from 2004-2008 and totaling 17.5 GW


49

Average O&M Costs from 2000-2009 Are Affected By Year of Installation

Capacity-weighted average 2000-09 O&M costs for projects built in 1980s equal $32/MWh, dropping to $22/MWh for projects built in 1990s, and to $9/MWh for projects built in 2000s

Note: Sample is limited, and consists of 115 wind power projects totaling 6,097 MW; few projects in sample have complete records of O&M costs from 2000-09

0

10

20

30

40

50

60

70

19

80

19

81

19

82

19

83

19

84

19

85

19

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88

19

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19

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98

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99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

Last Year of Equipment Installation

Projects with no 2009 O&M data

Projects with 2009 O&M data

Polynomial Trend Line (all projects)

Ave

rag

e A

nn

ua

l O&

M C

ost 2

00

0-2

00

9

(20

09

$/M

Wh

)


0

10

20

30

40

50

60

<5 MW 5-20 MW 20-50 MW >50 MW

Project Size (MW)

Pre-2000 (Average +/- Std. Dev.)

2000-2002 (Average +/- Std. Dev.)

2003-2005 (Average +/- Std. Dev.)

2006-2008 (Average +/- Std. Dev.)

Last Year of Equipment Installation:

n=11n=9n=22 n=6 n=27 n=7n=3 n=14n=4Ave

rag

e A

nn

ua

l O&

M C

ost 2

00

0-2

00

9

(20

09

$/M

Wh

)

n=2 n=4

50

0

5

10

15

20

25

30

35

40

1 2 3 4 5 6 7 8

Number of Years Since the Last Year of Equipment Installation

Pre-2000

2000-2002

2003-2005

2006-2008

Last Year of Equipment Installation (projects >5 MW only):

n=

15

Ave

rag

e A

nn

ua

l O&

M C

ost 2

00

0-2

00

9(2

00

9 $

/MW

h)

n=

3

n=

20

n=

18

n=

6

n=

4

n=

7

n=

8

n=

13

n=

15

n=

4

n=

6

n=

15

n=

6

n=

3

n=

3

n=

4

n=

2

O&M Costs Appear to Increase with Project Age, Decrease with Project Size

Note: Sample size is extremely limited


51

Policy and Market Drivers


52

Federal Policy Is Now More Favorable Than At Any Other Time in the Past Decade

• The Recovery Act established a number of federal policies to support wind

• Federal PTC currently in place through 2012 (longest extension in history)

• Projects can elect a 30% ITC or a 30% cash grant in lieu of the PTC

• Subsidized financing double-dipping penalty removed for ITC / cash grant

• $2.2 billion of new Clean Renewable Energy Bonds allocated

• Expansion and enhancement of Federal loan guarantee program

• $2.3 billion in advanced energy manufacturing tax credits awarded

• Increased R&D funding

• Increased funding for USDA’s Rural Energy for America Program (REAP)

• Efforts to pass an RPS and carbon regulation at the Federal level continue

• But… major policies expire after 2012, leaving uncertainty for future years


53

State Policies Help Direct the Location and Amount of Wind Power Development

• One new state (KS) established a mandatory RPS in 2009 (total is now 29 states and Washington, D.C.)

• State renewable funds, tax incentives, utility resource planning, voluntary green power, and growing interest in carbon regulation all also played a role in 2009

Non-Binding Goal

Source: Berkeley Lab

WI: 10% by 2015

NV: 25% by 2025

TX: 5,880 MW by 2015

PA: 8.5% by 2020

NJ: 22.5% by 2021CT: 23% by 2020

MA: 11.1% by 2009 +1%/yr

ME: 40% by 2017

NM: 20% by 2020 (IOUs)

10% by 2020 (co-ops)

CA: 20% by 2010

MN: 25% by 2025

Xcel: 30% by 2020

IA: 105 MW by 1999

MD: 20% by 2022

RI: 16% by 2019

HI: 40% by 2030

AZ: 15% by 2025

NY: 30% by 2015

CO: 30% by 2020 (IOUs)

10% by 2020 (co-ops and munis)

MT: 15% by 2015

DE: 20% by 2019

DC: 20% by 2020

WA: 15% by 2020

NH: 23.8% by 2025

OR: 25% by 2025 (large utilities)

5-10% by 2025 (smaller utilities)

NC: 12.5% by 2021 (IOUs)

10% by 2018 (co-ops and munis)

IL: 25% by 2025

Mandatory RPS

VT: 20% by 2017ND: 10% by 2015

VA: 15% by 2025MO: 15% by 2021

OH: 12.5% by 2024

SD: 10% by 2015

UT: 20% by 2025

MI: 10% by 2015

KS: 20% of peak

demand by 2020

OK: 15% by 2015

AK: 50% by 2025


54

Despite Progress on Overcoming Transmission Barriers, Constraints Remain

• Cost allocation continues to be a major issue at FERC and among

the ISOs/RTOs

• The DOE, states, grid operators, and regional organizations

continue to take proactive steps to encourage transmission

investment to improve access to renewable resources

• A variety of efforts to proactively plan for transmission, often through

analyses of state and regional renewable energy zones, also

continued in 2009

• Progress was made in 2009 on some transmission projects that are

designed, in part, to support wind power – e.g., Tehachapi in

California, and NextEra’s 200-mile line in Texas


55

Integration Cost ($/MWh)

Year Study

Wind

Capacity

Penetration Regulation Load

Following Unit

Commit. Gas

Supply TOTAL

2003 Xcel-UWIG 3.5% 0 0.41 1.44 - 1.85

2003 We Energies 29% 1.02 0.15 1.75 - 2.92

2004 Xcel-MNDOC 15% 0.23 - 4.37 - 4.60

2005 PacifiCorp-2004 11% 0 1.48 3.16 - 4.64

2006 Calif. (multi-year)* 4% 0.45 trace trace - 0.45

2006 Xcel-PSCo 15% 0.20 - 3.32 1.45 4.97

2006 MN-MISO** 31% - - - - 4.41

2007 Puget Sound Energy 12% - - - - 6.94

2007 Arizona Pub. Service 15% 0.37 2.65 1.06 - 4.08

2007 Avista Utilities 30% 1.43 4.40 3.00 - 8.84

2007 Idaho Power 20% - - - - 7.92

2007 PacifiCorp-2007 18% - 1.10 4.00 - 5.10

2008 Xcel-PSCo*** 20% - - - - 8.56

2009 Bonneville (BPA)+

36% 0.22 1.14 - - 5.70

2010 EWITS++ 48% - - 1.61 - 4.54

2010 Nebraska+++

63% - - - - 1.75

* Regulation costs represent 3-year average.

** Highest over 3-year evaluation period.

*** This integration cost reflects a $10/MMBtu natural gas price scenario. This cost is much higher than the

integration cost calculated for Xcel-PSCo in 2006, in large measure due to the higher natural gas price: had the gas

price from the 2006 study been used in the 2008 study, the integration cost would drop to $5.13/MWh.

+ Costs in $/MWh assume 31% capacity factor. Aside from regulation and following reserves, the costs of BPA’s

imbalance reserves are $4.33/MWh.

++ The unit commitment costs listed in EWITS are the cost of day-ahead wind forecast error; the remaining

integration costs included in the total are for shorter term variable reserves that account for regulation and short-term

forecast errors (energy imbalance).

+++ These integration costs only capture regulating reserves and day-ahead forecast error. A sensitivity case in this

study shows that integration costs increase if the differences between the actual hourly deliveries of wind energy are

compared to daily flat block of power. The increased costs are shown in Figure 39.

Sources: Brooks et al. (2003) [Xcel-UWIG]; Electrotek Concepts, Inc. (2003) [We Energies]; EnerNex Corp. and

Wind Logics, Inc. (2004) [Xcel-MNDOC]; PacifiCorp (2005) [Pacificorp-2004]; Shiu et al. (2006) [Calif. (multi-

year)]; EnerNex Corp. (2006) [Xcel-PSCo]; EnerNex Corp. and Windlogics Inc. (2006) [MN-MISO]; Puget Sound

Energy (2007) [Puget Sound Energy]; Acker (2007) [Arizona Pub. Service]; EnerNex Corp. (2007) [Avista

Utilities]; EnerNex Corp. and Idaho Power Co. (2007) [Idaho Power]; PacifiCorp (2007) [PacifiCorp-2007];

EnerNex Corp. (2008) [Xcel-PSCo]; BPA (2009) [Bonneville]; EnerNex Corp (2010) [EWITS]; EnerNex et al.

(2010) [Nebraska]

Studies Find that the Cost of Integrating Wind into Power Systems Is Manageable

• Wind integration costs are < $10/MWh for capacity penetrations of up to or exceeding 40%

• Regulation impacts are small, load-following and unit commitment larger

• Larger balancing areas, intra-hour scheduling and use of wind energy forecasts can ease integration challenges, and grid operators are increasingly relying on these strategies


56

Studies Find that the Cost of Integrating Wind Rises with Greater Wind Penetration

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

0% 10% 20% 30% 40% 50% 60% 70%

Inte

gra

tio

n C

ost ($

/MW

h)

Wind Penetration (Capacity Basis)

Arizona Public Service

Avista Utilities

BPA

California RPS

EWITS

Idaho Power

MN-MISO

Nebraska

Pacificorp-2004

Pacificorp-2007

Puget Sound Energy

We Energies

Xcel-MNDOC

Xcel-PSCo-2006

Xcel-PSCo-2008

Xcel-UWIG

Nebraska with Additional Cost of Hourly Wind to Energy-equivalent

Daily Flat Block of Power

Xcel-PSCo-2008 at 2006 Gas Prices


57

Future Outlook


58

Forecasts Predict Slower 2010, with Resurgence in 2011 and 2012• 2010 expected to be a slower year, due to reduced demand for wind (driven

by weak economy and low wholesale prices); 2009 buoyed by projects planned for completion in 2008 but carried over as result of PTC extension

• Predictions for 2010 range from 5,500 MW to 8,000 MW; forecasts predict a market resurgence in 2011-2012

• U.S. expected to retain 2nd-largest market status, after China, from 2010-12

• Beyond 2012, federal policy is uncertain, complicating projections

Source 2010 2011 2012 Cumulative Additions

2010-2012

EIA 7,310 10,200 10,330 27,840

BTM 8,000 10,000 15,000 33,000

IHS EER 7,130 9,830 9,340 26,300

Bloomberg NEF 7,390 8,535 8,610 24,535

Macquarie 7,500 8,100 8,700 24,300

UBS 6,950 9,380 10,780 27,110

AWEA 5,500-7,500 -- -- --


59

Uncertainties in Near-Term Market Growth Reflect Conflicting Trends

Stronger Growth

• Stronger federal and state policy support than at any point in last decade

• Possible further federal policy support through extension of Recovery Act programs, RPS, climate, and/or transmission policy

• Falling wind turbine prices may improve comparative economics of wind energy

Weaker Growth

• Treasury grant eligibility expires at end of 2010, but tax equity market not fully recovered

• Natural gas and wholesale power prices / expectations have plummeted

• Softer demand from state RPS markets in near term

• Inadequate transmission infrastructure beginning to constrain new builds

• Increased competition from other renewable energy sources


60

U.S. Is on a Trajectory that May Lead to 20% of Electricity Coming from WindBut ramping up further to ~16 GW/year and maintaining that pace for a decade is an enormous challenge, and is far from pre-determined

0

2

4

6

8

10

12

14

16

18

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

0

35

70

105

140

175

210

245

280

315

Deployment Path in 20% Wind Report (annual)

Actual Wind Installations (annual)

Deployment Path in 20% Wind Report (cumulative)

Annual C

apacity (

GW

)

range of annual projections

Cum

ula

tive C

apacity (

GW

)


61

For More Information...

See full report for additional findings, a discussion of the sources of data used, etc.

• http://windandwater.energy.gov/

To contact the primary authors• Ryan Wiser, Lawrence Berkeley National Laboratory

510-486-5474, [email protected]

• Mark Bolinger, Lawrence Berkeley National Laboratory 603-795-4937, [email protected]

To contact the U.S. Department of Energy’s Wind Program• Jacques Beaudry-Losique, [email protected]

• Jim Ahlgrimm, [email protected]

2009 wind technologies market report · italy 1,114 italy 4,845 france1,104 4,775 u.k. 1,077 u.k....

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