2011 WINDTECHNOLOGIESMARKET REPORTAUGUST 2012

NOTICEThis report was prepared as an account of work sponsored by an agency of the United States government.
Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty,
express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of
any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately
owned rights. Reference herein to any specific commercial product, process, or service by trade name,trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation,or favoring by the United States government or any agency thereof. The views and opinions of authors
expressed herein do not necessarily state or reflect those of the United States government or any agency thereof.
Available electronically at http://www.osti.gov/bridge
Available for a processing fee to U.S. Department of Energy
and its contractors, in paper, from:
U.S. Department of Energy
Office of Scientific and Technical Information
P.O. Box 62
Oak Ridge, TN 37831-0062
phone: 865.576.8401
fax: 865.576.5728
email: mailto:reports@adonis.osti.gov
Available for sale to the public, in paper, from:
U.S. Department of Commerce
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
phone: 800.553.6847
fax: 703.605.6900
email: orders@ntis.fedworld.gov
online ordering: http://www.ntis.gov/help/ordermethods.aspx
This publication received minimal editorial review at NREL

Printed on paper containing at least 50% wastepaper, including 10% post consumer waste.

2011 Wind Technologies Market Report
Primary authors
Ryan Wiser, Lawrence Berkeley National Laboratory
Mark Bolinger, Lawrence Berkeley National Laboratory
With contributions fromGalen Barbose, Naïm Darghouth, Ben Hoen, Andrew Mills (Berkeley Lab)
Kevin Porter, Michael Buckley, Sari Fink (Exeter Associates)
Frank Oteri, Suzanne Tegen (National Renewable Energy Laboratory)

Table of Contents

Acknowledgments ......................................................................................................................... i
List of Acronyms ........................................................................................................................... ii
Executive Summary .................................................................................................................... iii
1. Introduction ............................................................................................................................... 1
2. Installation Trends ................................................................................................................... 3
3. Industry Trends ...................................................................................................................... 14
4. Cost Trends ............................................................................................................................ 32
5. Performance Trends.............................................................................................................. 41
6. Wind Power Price Trends ..................................................................................................... 48
7. Policy and Market Drivers .................................................................................................... 57
8. Future Outlook ........................................................................................................................ 69
Appendix: Sources of Data Presented in this Report .......................................................... 72
References .................................................................................................................................. 76

Acknowledgments

For their support of this ongoing report series, the authors thank the entire U.S. Department of Energy (DOE) Wind
& Water Power Program team, and in particular Patrick Gilman and Mark Higgins. For reviewing elements of thisreport or providing key input, we also acknowledge: J. Charles Smith (Utility Variable-Generation Integration
Group); Erik Ela, Eric Lantz, and KC Hallett (National Renewable Energy Laboratory, NREL); Michael Goggin,
Liz Salerno, and Emily Williams (American Wind Energy Association); Thomas Carr (Western Governors’
Association); Ed DeMeo (Renewable Energy Consulting Services, Inc.); Patrick Gilman, Cash Fitzpatrick, and Liz
Hartman (DOE); Alice Orrell (Pacific Northwest National Laboratory, PNNL); Jim Walker (enXco); Matt McCabe(Clear Wind); Andrew David (US International Trade Commission); Charlie Bloch and Bruce Hamilton (Navigant
Consulting); Steve Clemmer (Union of Concerned Scientists); Chris Namovicz (Energy Information
Administration); and David Drescher (Exelon Generation). Thanks to the American Wind Energy Association for
the use of their database of wind power projects. We also thank Amy Grace (Bloomberg New Energy Finance) for
the use of Bloomberg NEF’s graphic on domestic wind turbine nacelle assembly capacity; Charlie Bloch and Bruce
Hamilton (Navigant Consulting) for assistance with the section on offshore wind; Donna Heimiller and Billy
Roberts (NREL) for assistance with the wind project and wind manufacturing maps; and Kathleen O’Dell (NREL)
for assistance with layout, formatting, and production. Berkeley Lab’s contributions to this report were funded by
the Wind & Water Power Program, Office of Energy Efficiency and Renewable Energy of the U.S. Department ofEnergy under Contract No. DE-AC02-05CH11231. The authors are solely responsible for any omissions or errors
contained herein.

i2011 Wind Technologies Market ReportList of Acronyms
AWEA
BPA
CAISO
CCGT
COD
CREZ
DOE
EIA
ERCOT
FERC
GE
GW
IOU
IPP
ISO
ISO-NE
ITC
kW
kWh
MISO
MW
MWh
NERC
NREL
NYISO
OEM
O&M
PJM
POU
PPA
PTC
PUC
REC
RFI
RPS
RTO
SPP
WAPA

American Wind Energy Association
Bonneville Power Administration
California Independent System Operator
combined cycle gas turbine
commercial operation datecompetitive renewable energy zone
U.S. Department of Energy
Energy Information Administration
Electric Reliability Council of Texas
Federal Energy Regulatory Commission
General Electric Corporation
gigawatt
investor-owned utility
independent power producer
independent system operator
New England Independent System Operator
investment tax credit
kilowatt
kilowatt-hour
Midwest Independent System Operator
megawatt
megawatt-hour
North American Electric Reliability Corporation
National Renewable Energy Laboratory
New York Independent System Operator
original equipment manufacturer
operations and maintenance
PJM Interconnection
publicly owned utility
power purchase agreement
Production Tax Credit
public utility commission
renewable energy certificate
request for information
renewables portfolio standard
regional transmission organization
Southwest Power Pool
Western Area Power Administrationii
2011 Wind Technologies Market Report

Executive Summary
The U.S. wind power industry is facing uncertain times. With 2011 capacity additions having
risen from 2010 levels and with a further sizable increase expected in 2012, there are – on thesurface – grounds for optimism. Key factors driving growth in 2011 included continued stateand federal incentives for wind energy, recent improvements in the cost and performance ofwind power technology, and the need to meet an end-of-year construction start deadline in orderto qualify for the Section 1603 Treasury grant program. At the same time, the currently-slated
expiration of key federal tax incentives for wind energy at the end of 2012 – in concert with
continued low natural gas prices and modest electricity demand growth – threatens todramatically slow new builds in 2013.
Key findings from this year’s “Wind Technologies Market Report” include:
•

•

•

•

Wind Power Additions Increased in 2011, with Roughly 6.8 GW of New Capacity
Added in the United States and $14 Billion Invested. Wind power installations in 2011were 31% higher than in 2010, but still well below the levels seen in 2008 and 2009.
Cumulative wind power capacity grew by 16% in 2011, bringing the total to nearly 47 GW.
Wind Power Comprised 32% of U.S. Electric Generating Capacity Additions in 2011.
This is up from 25% in 2010, but below its historic peak of 42-43% in 2008 and 2009. In
2011, for the sixth time in the past seven years, wind power was the second-largest new
resource (behind natural gas) added to the U.S. electrical grid in terms of gross capacity.
The United States Remained the Second Largest Market in Annual and Cumulative
Wind Power Capacity Additions, but Was Well Behind the Market Leaders in Wind
Energy Penetration. After leading the world in annual wind power capacity additions from2005 through 2008, the U.S. has now – for three years – been second to China, comprisingroughly 16% of global installed capacity in 2011, up slightly from 13% in 2010, but down
substantially from 26-30% from 2007 through 2009. In terms of cumulative capacity, theU.S. also remained the second leading market, with nearly 20% of total global wind power
capacity. A number of countries are beginning to achieve relatively high levels of windenergy penetration in their electricity grids: end-of-2011 wind power capacity is estimated tosupply the equivalent of roughly 29% of Denmark’s electricity demand, 19% of Portugal’s,
19% of Spain’s, 18% of Ireland’s, and 11% of Germany’s. In the United States, thecumulative wind power capacity installed at the end of 2011 is estimated, in an average year,
to equate to roughly 3.3% of the nation’s electricity demand.
California Added More New Wind Power Capacity than Any Other State, While Six
States Are Estimated to Exceed 10% Wind Energy Penetration. With 921 MW added,
California led the 29 other states in which new large-scale wind turbines were installed in2011, ending Texas’ six-year reign (Texas fell to ninth place in 2011). Other states withmore than 500 MW added in 2011 included Illinois, Iowa, Minnesota, Oklahoma, andColorado. On a cumulative basis, Texas remained the clear leader. Notably, the wind power
capacity installed in South Dakota and Iowa as of the end of 2011 is estimated, in an average
year, to supply approximately 22% and 20%, respectively, of all in-state electricity
generation. Four other states are also estimated to exceed 10% penetration by this metric:
Minnesota, North Dakota, Colorado, and Oregon.
iii
2011 Wind Technologies Market Report

•

•

•

•

No Offshore Turbines Have Been Commissioned in the United States, but Offshore
Project and Policy Developments Continued in 2011. At the end of 2011, global offshore
wind power capacity stood at roughly 4,000 MW, with the vast majority located in Europe.
To date, no offshore projects have been installed in the United States. Nonetheless,significant strides have been made recently in the federal arena, through both the Departmentof the Interior's responsibilities with regard to regulatory approvals and the Department ofEnergy's investments in offshore wind R&D. Interest exists in developing offshore windenergy in several parts of the country – e.g., Navigant finds that ten projects totaling 3,800
MW are somewhat more advanced in the development process. Of these, two have signed
power purchase agreements (a third offshore wind PPA was recently canceled).
Data from Interconnection Queues Demonstrate that an Enormous Amount of Wind
Power Capacity Is Under Consideration. At the end of 2011, there were 219 GW of wind
power capacity within the transmission interconnection queues administered by independent
system operators, regional transmission organizations, and utilities reviewed for this report.
This wind power capacity represented 45% of all generating capacity within these queues atthat time, and was 1.5 times as much capacity as the next-largest resource (natural gas). Of
note, however, is that the absolute amount of wind and coal power capacity in the sampledinterconnection queues has declined in recent years, whereas natural gas and solar capacity
has increased. Most (96%) of the wind power capacity is planned for the Midwest, PJM
Interconnection, Texas, Mountain, Northwest, Southwest Power Pool, and California regions.
Projects currently in interconnection queues are often very early in the development process,so much of this capacity is unlikely to be built as planned; nonetheless, these data
demonstrate the continued high level of developer interest in wind power.
Despite the Ongoing Proliferation of New Entrants, the “Big Three” Turbine Suppliers
Have Gained U.S. Market Share Since 2009. GE and Vestas both secured roughly 29% of
U.S. market share (by capacity installed) in 2011, followed by Siemens (18%), Suzlon and
Mitsubishi (both at 5%), Nordex and Clipper (both at 4%), REpower (3%), and Gamesa(2%). There has been a notable increase in the number of wind turbine manufacturers serving
the U.S. market – those installing more than 1 MW has increased from just 5 in 2005 to 20
manufacturers in 2011. Recently, however, there is evidence of gains in the aggregate
market share of the three leading manufacturers: GE, Vestas, and Siemens. On a worldwide
basis, Chinese turbine manufacturers continue to occupy positions of prominence: four of
the top ten, and seven of the top 15, leading global suppliers of wind turbines in 2011 hailfrom China. To date, that growth has been based almost entirely on sales to the Chinese
market. However, 2011 installations by Chinese and South Korean manufacturers in the U.S.
include those from Sany Electric (10 MW), Samsung (5 MW), Goldwind (4.5 MW), Hyundai(3.3 MW), Sinovel (1.5 MW), and Unison (1.5 MW).
Domestic Wind Turbine and Component Manufacturing Capacity Has Increased, but
Uncertainty in Future Demand Has Put the Wind Turbine Supply Chain Under Severe
Pressure. Eight of the ten wind turbine manufacturers with the largest share of the U.S.
market in 2011 had one or more manufacturing facilities in the United States at the end of
2011. In contrast, in 2004 there was only one active utility-scale wind turbine manufacturer
assembling nacelles in the United States (GE). In addition, a number of new wind turbine
and component manufacturing facilities were either announced or opened in 2011, by bothforeign and domestic firms. The American Wind Energy Association (AWEA) estimatesthat the entire wind energy sector directly and indirectly employed 75,000 full-time workers
iv
2011 Wind Technologies Market Report

•

•

•

•

in the United States at the end of 2011 – equal to the jobs reported in 2010 but fewer than in2008 and 2009. Though domestic manufacturing capabilities have grown, uncertain
prospects after 2012 – due primarily to the scheduled expiration of federal incentives – arepressuring the wind industry’s domestic supply chain as margins drop and concerns about
manufacturing overcapacity deepen, potentially setting the stage for significant layoffs. The
growth in U.S. wind turbine manufacturing capability and the drop in wind power plantinstallations since 2009 led to an estimated over-capacity of U.S. turbine nacelle assembly
capability of more than 5 GW in 2011, in comparison to 4 GW of under-capacity in 2009.
Over-capacity relative to U.S. turbine demand is anticipated to be even more severe in 2013
and 2014. As a result of this over-supply, coupled with increasing competition, includingfrom new entrants from China and Korea, a wide range of turbine manufacturers havereported weakened financial results, with companies throughout the U.S. wind industry’s
supply chain announcing cuts to their U.S. workforce.
A Growing Percentage of the Equipment Used in U.S. Wind Power Projects Has Been
Sourced Domestically in Recent Years. U.S. trade data show that the United Statesremained a large importer of wind power equipment in 2011, but that growth in installedwind power capacity has outpaced the growth in imports in recent years. As a result, a
growing percentage of the equipment used in wind power projects is being sourced
domestically. When presented as a fraction of total equipment-related wind turbine costs,
domestic content is estimated to have increased significantly from 35% in 2005-2006 to 67%
in 2011. Exports of wind-powered generating sets from the United States have also
increased, rising from $15 million in 2007 to $149 million in 2011.
The Average Nameplate Capacity, Hub Height, and Rotor Diameter of Installed Wind
Turbines Increased. The average nameplate capacity of wind turbines installed in the
United States in 2011 increased to 1.97 MW, up from 1.80 MW in 2010 and the largest
single-year increase in more than six years. Since 1998-99, average turbine nameplate
capacity has increased by 174%. Average hub heights and rotor diameters have also scaledwith time, to 81 and 89 meters, respectively, in 2011. Since 1998-99, the average turbine
hub height has increased by 45%, while the average rotor diameter has increased by 86%. In
large part, these increases have been driven by new turbines designed to serve lower-windspeed sites. Industry expectations as well as new turbine announcements (mostly
surrounding additional low-wind-speed turbines) suggest that significant further scaling,
especially in average rotor diameter, is anticipated in the near term.
Project Finance Was a Mixed Bag in 2011, as Debt Terms Deteriorated While Tax
Equity Held Steady. After steady improvement in both the debt and tax equity markets
throughout 2010, progress faltered somewhat in 2011 on the debt side as the latest
Greek/European debt crisis drove a new round of retrenchment. At the same time, newbanking regulations took hold, driving considerably shorter bank loan tenors (institutional
lenders, meanwhile, continued to offer significantly longer products). In contrast to theweakened debt market, the market for tax equity improved somewhat in 2011, with pricing
remaining fairly stable and a handful of new or returning investors entering the market. As
the number of grandfathered Section 1603 grant deals begins to taper off in 2012, however,
attrition in tax equity investors is possible, as some have indicated no interest in PTC deals.
IPPs Remain the Dominant Owners of Wind Projects, But Utility Ownership Increased
Significantly in 2011, Largely On the Back of One Utility. Independent power producers(IPPs) own 73% of all new wind power capacity installed in the United States in 2011, andv
2011 Wind Technologies Market Report

•

•

•

•

•

•

82% of the cumulative installed capacity. Utility ownership jumped to nearly 25% in 2011
(as MidAmerican Energy alone added nearly 600 MW in Iowa), up from 15% in the two
previous years, and reached 17% on a cumulative basis.
Long-Term Contracted Sales to Utilities Remained the Most Common Off-Take
Arrangement, but Scarcity of Power Purchase Agreements and Looming PTC
Expiration Drove Continued Merchant Development. Electric utilities continued to be
the dominant purchasers (i.e., off-takers) of wind power in 2011, either owning (25%) or
buying (51%) power from 76% of the new capacity installed last year. Merchant/quasimerchant projects were less prevalent in 2011 than they have been in recent years,
accounting for 21% of all new capacity. With power purchase agreements (PPAs) in
relatively short supply in comparison to wind developer interest, wholesale power prices at
low levels, and a scheduled PTC expiration looming, it is likely that many of themerchant/quasi-merchant projects built in 2011 are merchant by necessity rather than bychoice – i.e., building projects on a merchant basis may, in some cases, simply have been themost expedient way to ensure the deployment of committed turbines in advance of thescheduled expiration of important federal incentives. Some of these projects are, therefore,
likely still seeking long-term PPAs. On a cumulative basis, utilities own (17%) or buy (50%)
power from 66% of all wind power capacity in the United States, with merchant/quasimerchant projects accounting for 24% and power marketers 10%.
With Increased Competition among Manufacturers, Wind Turbine Prices Continued to
Decline in 2011. After hitting a low of roughly $700/kW from 2000 to 2002, average windturbine prices increased by approximately $800/kW (>100%) through 2008, rising to an
average of more than $1,500/kW. Wind turbine prices have since dropped substantially,
despite continued technological advancements that have yielded increases in hub heights andespecially rotor diameters. A number of turbine transactions announced in 2011 had pricing
in the $1,150-$1,350/kW range and price quotes for recent transactions are reportedly in therange of $900-$1,270/kW, depending on the technology. These price reductions, coupledwith improved turbine technology and more-favorable terms for turbine purchasers, should,
over time, exert downward pressure on total project costs and wind power prices.
Though Slow to Reflect Declining Wind Turbine Prices, Reported Installed Project
Costs Finally Turned the Corner in 2011. Among a large sample of wind power projects
installed in 2011, the capacity-weighted average installed project cost stood at nearly$2,100/kW, down almost $100/kW from the reported average cost in both 2009 and 2010.
Moreover, a preliminary estimate of the average installed cost among a relatively small
sample of projects that either have been or will be built in 2012 suggests that average
installed costs may decline further in 2012, continuing to follow lower turbine prices.
Installed Costs Differ By Project Size, Turbine Size, and Region. Installed project costs
are found to exhibit some weak economies of scale, at least at the lower end of the project
and turbine size range. Texas is found to be the lowest-cost region, while California and
New England were the highest-cost regions.
Newer Projects Appear to Show Improvements in Operations and Maintenance Costs.
Despite limited data availability, it appears that projects installed more recently have, on
average, incurred lower O&M costs than older projects in their first several years ofoperation, and that O&M costs increase as projects age.
Sample-Wide Wind Project Capacity Factors Have Generally Improved Over Time.
Boosted primarily by taller towers and larger rotor diameters (relative to nameplate capacity),vi
2011 Wind Technologies Market Report

•

•

•

•

average sample-wide wind power project capacity factors have, in general, gradually
increased over time, from 25% in 1999 (for projects installed through 1998) to a high ofnearly 34% in 2008 (for projects installed through 2007). In 2009 and 2010, however,sample-wide capacity factors dropped to around 30%, before 2011 brought a resurgence backto 33% (for projects installed through 2010). The drop in 2009 and 2010 was likely due to a
combination of lackluster wind speeds throughout much of the U.S. in both 2009 and 2010 aswell as wind power curtailment (particularly severe in 2009).
Some Stagnation in Wind Project Capacity Factor Improvement Is Evident Among
Projects Built from 2006 through 2010, Due in Part to a Build Out of Projects in
Progressively Weaker Wind Resource Areas. Focusing only on capacity factors in 2011
parsed by project vintage reveals that average capacity factors have been largely stagnant
among projects built from 2006 through 2010 (though the maximum capacity factor attainedby any individual project in 2011 increased noticeably among projects built in 2009 and2010, and the fact that rotor scaling continued for projects built in 2011 suggests that further
increases in capacity factors are likely in 2012, all else equal). Three main drivers appear tobe behind this stagnation: the average hub height of wind power projects has only increased
by a few meters since 2006 (after growing rapidly in earlier years), the average rotor swept
area relative to turbine nameplate capacity (i.e., the inverse of “specific power”) also held
steady during much of this period (though increased considerably in both 2010 and 2011),
while the average quality of the wind resource among those projects built in each year has
deteriorated significantly since 2008. This final trend of building projects in progressively
less-energetic wind resource sites may be driven by the proliferation of low wind speed
turbine designs (see above), siting challenges (including transmission constraints), and evenpolicy design (the value of the Section 1603 cash grant does not depend on how energetic agiven site is).
Regional Variations in Capacity Factor Reflect the Strength of the Wind Resource.
Based on a sub-sample of wind power projects built from 2004 through 2010, capacityweighted average capacity factors were the highest in the Heartland (37%) and Mountain(36%) regions in 2011, and lowest in the East (25%) and in New England (28%). Not
surprisingly, these regional rankings are roughly consistent with the relative quality of thewind resource in each region.
Unlike Turbine Prices and Installed Project Costs, Cumulative, Sample-Wide Wind
Power Prices Continued to Move Higher in 2011. After having declined through 2005,
sample-wide average wind power prices have risen steadily, such that in 2011, thecumulative sample of 271 projects totaling 20,189 MW built from 1998 through 2011 had an
average power sales price of $54/MWh. This general temporal trend of falling and thenrising prices is consistent with – but lags, due to the cumulative nature of the sample – theturbine price and installed project cost trends (at least through 2008 and 2010, respectively)
described earlier.
Binning Wind Power Sales Prices by Project Vintage Also Fails to Show a Price
Reversal. The capacity-weighted average 2011 sales price, based on projects in the sample
built in 2011, was roughly $74/MWh – essentially unchanged from the average among
projects built in 2010 (the spread of individual project prices is also similar among projects
built in 2010 and 2011), and more than twice the average of $32/MWh among projects built
during the low point in 2002 and 2003. Although the similarity in pricing among 2010 and2011 projects may actually portend a peak (with lower prices likely among 2012 projects),
vii
2011 Wind Technologies Market Report

•

•

•

•

the fact that neither calendar year prices (among a cumulative sample) nor 2011 prices(binned by project vintage) show any sort of price reversal is nevertheless surprising,particularly given the degree to which turbine prices have dropped since 2008, along withgrowing evidence of aggressive pricing in wind PPAs.
Binning Wind Power Sales Prices by PPA Execution Date Shows Steeply Falling Prices.
An abnormally long lag between when PPAs were signed and when projects were built
appears to be largely responsible for the stubborn lack of a price reversal in 2011 whenviewed by calendar year or project vintage. Only two projects within the sample that werebuilt in 2011 actually signed PPAs in 2011. All other 2011 projects in the sample signed
PPAs in 2010, 2009, or even back as far as 2008 – i.e., at the height of the market for
turbines – thereby locking in prices that ended up being above market in 2011. Binning by
PPA signing date reveals that the average price peaked in 2009 and then progressively fell inboth 2010 and 2011. Among a sample of “full term” wind project PPAs signed in 2011, thecapacity-weighted average levelized PPA price is $35/MWh, down from $59/MWh for PPAs
signed in 2010 and $72/MWh for PPAs signed in 2009.
Wind Power PPA Prices Vary Widely By Region. Texas, the Heartland, and the Mountainregions appear to be among the lowest-price regions, on average, while California is, by far,the highest price region. California also accounts for nearly one quarter of the 2011 projectsample, thereby disproportionately inflating the capacity-weighted average price in 2011 (asit also did in 2010, when it made up almost 20% of the sample).
Low Wholesale Electricity Prices Continued to Challenge the Relative Economics ofWind Power. Average wind power prices compared favorably to wholesale electricity
prices from 2003 through 2008. Starting in 2009, however, increasing wind power prices,
combined with a sharp drop in wholesale electricity prices (driven by lower natural gas
prices), pushed wind energy to the top of (and in 2011 above) the wholesale power pricerange. Although low wholesale electricity prices are, in part, attributable to the recessioninduced drop in energy demand, the ongoing development of significant shale gas deposits
has also resulted in reduced expectations for gas price increases going forward. While
comparing wind and wholesale electricity prices in this manner is not appropriate if one’s
goal is to fully account for the costs and benefits of wind energy relative to its competition,these developments may nonetheless put the near-term comparative economic position ofwind energy at some risk absent further reductions in the price of wind power and absent
supportive policies for wind energy. That said, levelized PPA prices in the $30-$40/MWh
range (currently achievable, with the PTC, in many parts of the interior U.S.) are fullycompetitive with the range of wholesale power prices seen in 2011.
Uncertainty Reigns in Federal Incentives for Wind Energy Beyond 2012. The Recovery
Act enabled wind power projects placed in service prior to the end of 2012 to elect a 30%
investment tax credit (ITC) in lieu of the production tax credit (PTC). More importantly,
given the relative scarcity of tax equity in the immediate wake of the financial crisis, theRecovery Act also enabled wind power projects to elect a 30% cash grant from the Treasury
in lieu of federal tax credits. More than 60% of the new wind capacity installed in 2011
elected the cash grant. However, in order to qualify for the grant, wind power projects musthave been under construction by the end of 2011, must apply for a grant by October 1, 2012,and must be placed in service by the end of 2012. With the PTC, ITC, and bonus
depreciation all also currently scheduled to expire at the end of 2012, the wind energy sector
is currently facing serious federal policy uncertainty looking to 2013 and beyond.
viii
2011 Wind Technologies Market Report

•

•

•

State Policies Play a Role in Directing the Location and Amount of Wind Power
Development, but Current Policies Cannot Support Continued Growth at the Levels
Seen in the Recent Past. From 1999 through 2011, 65% of the wind power capacity built in
the United States was located in states with renewables portfolio standards (RPS); in 2011,
this proportion was 78%. As of July 2012, mandatory RPS programs existed in 29 states andWashington D.C., and a number of states strengthened previously established programs in
2011. However, existing RPS programs are projected to drive average annual renewableenergy additions of roughly 4-5 GW/year (not all of which will be wind) between 2012 and2020, which is less than the amount of wind capacity added in recent years and demonstrates
the limitations of relying exclusively on state RPS programs to drive future deployment.
Despite Progress on Overcoming Transmission Barriers, Constraints Remain.
Transmission development has continued to gain traction during recent years, with about
2,300 circuit miles of new transmission additions under construction near the end of 2011,
and with an additional 17,800 circuit miles planned through 2015. The wind industry has
identified near-term transmission projects that – if all were completed – could carry almost
45 GW of wind power capacity. In July 2011, the Federal Energy Regulatory Commission(FERC) issued an order that requires public utility transmission providers to improvetransmission planning processes and to determine a cost allocation methodology for new
transmission facilities. States, grid operators, utilities, regional organizations, and theDepartment of Energy also continue to take proactive steps to encourage transmission
investment. Finally, construction and development progress was made in 2011 on a numberof transmission projects designed, in part, to support wind power. Nonetheless, siting,planning, and cost allocation issues remain key barriers to transmission investment, and windcurtailment continues to be a problem in some areas.
Integrating Wind Energy into Power Systems Is Manageable, but Not Free of Costs,
and System Operators Are Implementing Methods to Accommodate Increased
Penetration. Recent studies show that wind energy integration costs are below $12/MWh –and often below $5/MWh – for wind power capacity penetrations of up to or even exceeding
40% of the peak load of the system in which the wind power is delivered. The increase inbalancing reserves with increased wind power penetration is projected, in most cases, to be
below 15% of the nameplate capacity of wind power, and typically considerably less than
this figure, particularly in studies that use intra-hour scheduling. Moreover, a number ofstrategies that can help to ease the integration of increasing amounts of wind energy –including the use of larger balancing areas, the use of wind forecasts, and intra-hourscheduling – are being implemented by grid operators across the United States.

With federal tax incentives for wind energy currently slated to expire at the end of 2012, newcapacity additions in 2012 are anticipated to exceed 2011 levels and perhaps even the highs in2009 as developers rush to commission projects. At the same time, despite the improved cost,
performance, and price of wind energy, policy uncertainty – in concert with continued low
natural gas prices, modest electricity demand growth, and the aforementioned slack in existingstate policies – threatens to dramatically slow new builds in 2013 and beyond. Forecasts for2013 and beyond therefore span a particularly wide range, depending in large measure on
assumptions about the possible extension of federal incentives.

ix
2011 Wind Technologies Market Report

1. Introduction
The U.S. wind power industry is facing uncertain times. With 2011 capacity additions having
risen from 2010 levels and with a further sizable increase expected in 2012, there are – on thesurface – grounds for optimism. At the same time, the currently-slated expiration of key federal
tax incentives for wind energy at the end of 2012 – in concert with continued low natural gas
prices and modest electricity demand growth – threatens to dramatically slow new builds in
2013, despite recent improvements in the cost and performance of wind power technology. In
combination with growing global competition within the sector, these trends have alreadynegatively impacted the U.S. wind power industry’s supply chain.
The wind power sector is dynamic, making it difficult to keep up with evolving trends in themarketplace. This annual report – now in its sixth year – meets the need for timely, objective
information on the industry and its progress by providing a detailed overview of developments
and trends in the United States wind power market, with a particular focus on 2011. As withprevious editions, this report begins with an overview of key installation-related trends: trends inwind power capacity growth; how that growth compares to other countries and generation
sources; the amount and percentage of wind energy in individual states; the status of offshore
wind power development; and the quantity of proposed wind power capacity in various
interconnection queues in the United States. Next, the report covers an array of wind powerindustry trends, including: developments in turbine manufacturer market share; manufacturing
and supply-chain investments; wind turbine and component imports into and exports from theUnited States; wind turbine size, hub height, and rotor diameter; project financing developments;
and trends among wind power project owners and power purchasers. The report then turns to a
discussion of wind power cost, performance, and pricing trends. In so doing, it describes trends
in wind turbine transaction prices, installed project costs, operations and maintenance expenses,
and project performance. It also reviews the prices paid for wind power in the United States, andhow those prices compare to short-term wholesale electricity prices. Next, the report examines
policy and market factors impacting the domestic wind power market, including federal and statepolicy drivers, transmission issues, and grid integration. Finally, the report concludes with apreview of possible near-term market developments.
This sixth edition of the annual report updates data presented in previous editions, while
highlighting key trends and important new developments from 2011. New to this edition is asummary of trends in the wind resource conditions in which wind power projects have beensited, as well as differences in how wind power sales prices are reported – including new data on
full-term power purchase agreement (PPA) prices levelized over the full contract term. The
report concentrates on larger-scale wind turbines, defined here as individual turbines that exceed
100 kW in size. 1 The U.S. wind power sector is multifaceted, however, and also includes
smaller, customer-sited wind turbines used to power residences, farms, and businesses. Data on
these latter applications are not the focus of this report, though a brief discussion on Small Wind
1This 100 kW threshold between ‘small’ and ‘large’ wind turbines is applied starting with 2011 projects (to better
match AWEA’s historical methodology), and is justified by the fact that the U.S. tax code makes a similar
distinction. In years prior to 2011, however, different cut-offs are used to (a) better match AWEA’s reported
capacity numbers and (b) to ensure that older utility-scale wind power projects in California are not excluded fromthe sample.

1
2011 Wind Technologies Market ReportTurbines is provided on page 4. Because this report has an historical focus and all wind power
projects installed in the U.S. have been land-based, its treatment of trends in the offshore wind
power sector is limited to a brief summary of recent developments. A companion report fundedby the U.S. Department of Energy that focuses exclusively on offshore wind energy will be
published later this year.
Much of the data included in this report were compiled by Berkeley Lab, and come from avariety of sources, including the American Wind Energy Association (AWEA), the Energy
Information Administration (EIA), and the Federal Energy Regulatory Commission (FERC).
The Appendix provides a summary of the many data sources used in the report, and a list of
specific references follows the Appendix. Data on wind power capacity additions in the UnitedStates are based largely on information provided by AWEA, though minor methodologicaldifferences may yield slightly different numbers from AWEA (2012a) in some cases. In othercases, the data shown here represent only a sample of actual wind power projects installed in the
United States; furthermore, the data vary in quality. As such, emphasis should be placed on
overall trends, rather than on individual data points. Finally, each section of this document
primarily focuses on historical market information, with an emphasis on 2011; with some limited
exceptions (including the final section of the report), the report does not seek to forecast future
trends.

2
2011 Wind Technologies Market Report2. Installation Trends
Wind Power Additions Increased in 2011, with Roughly 6.8 GW of New
Capacity Added in the United States and $14 Billion Invested
The U.S. wind power market grew more rapidly in 2011 than in 2010, with 6,816 MW of new
capacity added, bringing the cumulative total to nearly 47,000 MW (Figure 1). 2 This growthtranslates into $14.3 billion (real 2011 dollars) invested in wind power project installation in
2011, for a cumulative investment total of $95 billion since the beginning of the 1980s. 3 Windpower installations in 2011 were 31% higher than in 2010, but still well below the levels seen in2008 and 2009. Cumulative wind power capacity grew by 16% in 2011.

9

Annual US Capacity (left scale)45

8Cumulative US Capacity (right scale)

40

5

0

0

2011

1

2010

10

2009

2

2008

15

2007

3

2006

20

2005

4

2004

25

2003

5

2002

30

2001

6

2000

35

1999

7

Source: AWEA project database

Figure 1. Annual and Cumulative Growth in U.S. Wind Power Capacity

Key factors driving growth in 2011 included: continued state and federal incentives for windenergy, recent improvements in the cost and performance of wind power technology, and theneed to meet an end-of-year construction start deadline in order to qualify for the Section 1603
Treasury grant program. With the Section 1603 grant and other federal tax incentives for windenergy scheduled to expire at the end of 2012, new capacity additions in 2012 are anticipated to
substantially exceed 2011 levels as developers rush to commission projects. At the same time,
this scheduled expiration – in concert with continued low natural gas prices, modest electricity
demand growth, and existing state policies that are not sufficient to support continued capacity
additions at the levels witnessed in recent years – threatens to dramatically slow new builds in2013 and beyond.
2

When reporting annual wind power capacity additions, this report focuses on gross capacity additions of large
wind turbines. The net increase in capacity each year can be somewhat lower, reflecting turbine decommissioning.
3
These investment figures are based on an extrapolation of the average project-level capital costs reported later inthis report, and do not include investments in manufacturing facilities, research & development expenditures, or
operations and maintenance (O&M) costs.

3
2011 Wind Technologies Market Report

Cumulative Capacity (GW)

50

1998

Annual Capacity (GW)

10

Small Wind Turbines
Small wind turbines can provide power directly to homes, farms, schools, businesses, and industrial facilities,
offsetting the need to purchase some portion of the host’s electricity from the grid; such wind turbines can also
provide power to off-grid sites. Wind turbines used in these applications are often much smaller – generally
ranging in size from a few hundred watts to 100 kW – than the larger-scale turbines that are the primary focus of
this report.
The table below summarizes sales of small wind turbines, 100 kW and less in size, into the U.S. market from2005 through 2011. Roughly 19 MW of small wind turbines were sold in the U.S. in 2011, most of which camefrom turbines manufactured by U.S. companies. These installation figures represent a 26% decline in annual
sales – in capacity terms – relative to 2010, yielding a cumulative installed capacity of small wind turbines in the
United States of 198 MW by the end of 2011 (AWEA 2012b).
Within this market segment, there has been a general trend towards larger, grid-tied systems. Sales of turbines<1 kW in size (often used off-grid) were flat or even declined from 2006-11, averaging roughly 2-3 MW peryear. Sales of 1-10 kW turbines (often used in the grid-tied residential market), on the other hand, grew fromless than 2 MW in 2006 to more than 8 MW in 2010, before dropping to approximately 6 MW in 2011. Sales of
11-100 kW turbines (often used in the grid-tied commercial / light industrial / government market) grew fromaround 3 MW in 2006 to more than 15 MW in 2010, before dropping to roughly 12 MW in 2011 (AWEA
2012b).
Year
2005
2006
2007
2008
2009
2010
2011

Annual Sales of Small Wind Turbines (≤ 100 kW) into the United States
Number of Turbines
Capacity Additions
Sales Revenue
4,324
3.3 MW$11 million
8,330
8.6 MW$36 million
9,102
9.7 MW$43 million
10,38617.4 MW$74 million
9,820
20.4 MW$91 million
7,811
25.6 MW$139 million
7,303
19.0 MW$115 million

Source: AWEA (2012b)

Sales in this sector have historically been driven – at least in part – by a variety of state incentive programs. In
addition, wind turbines equal to or under 100 kW in size are eligible for an uncapped 30% federal investment tax
credit (in place through 2016). The Section 1603 Treasury Grant Program and programs administered by the
USDA have also played a role in the recent growth of the sector. The decline in U.S. sales in 2011 is attributed
by AWEA (2012b) in part to inconsistent state incentives, with several states suspending or defunding theirsmall wind incentive programs in 2011, as well as the poor state of the U.S. economy.

Wind Power Comprised 32% of U.S. Electric Generating Capacity Additionsin 2011Wind power has represented one of the largest new sources of electric capacity additions in the
United States in recent years. In 2011, wind power was again (for the sixth time in seven years)
the second-largest new resource added to the U.S. electrical grid in terms of gross capacity
additions, behind the 10,500 MW of new natural gas capacity. 4 New wind power projects
4

Data presented here are based on gross capacity additions, not considering retirements.

42011 Wind Technologies Market Report

100

50%

80

40%

60

30%

40

20%

20

10%

0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Wind

Gas

Coal

Other Renewable

Other Non-Renewable

Wind (% of Total)0%Wind Capacity Additions(% of Total Annual Capacity Additions)

Total Annual Capacity Additions (GW)

contributed roughly 32% of the new nameplate capacity added to the U.S. electrical grid in 2011,
compared to 25% in 2010, 42% in 2009, 43% in 2008, 34% in 2007, 18% in 2006, 12% in 2005,
and less than 4% from 2000 through 2004 (Figure 2).

Source: EIA, Ventyx, AWEA, IREC, SEIA/GTM, Berkeley Lab

Figure 2. Relative Contribution of Generation Types in Annual Capacity Additions

EIA’s (2012) reference-case forecast projects that total U.S. electricity supply will need toincrease at an average pace of roughly 35 TWh (0.8%) per year from 2011 to 2035 in order tomeet demand growth. On an energy basis, the annual amount of electricity expected to begenerated by the new wind power capacity added in 2011 represents roughly 54% of this averageannual projected growth in supply. By extension, if wind power additions continued through2035 at the same pace as in 2011, then roughly 54% of the nation’s projected increase inelectricity generation from 2011 through 2035 would be met with wind electricity. Although
future growth trends are hard to predict, it is clear that a significant portion of the country’s new
generation needs is already being met by wind energy.

The United States Remained the Second Largest Market in Annual andCumulative Wind Power Capacity Additions, but Was Well Behind theMarket Leaders in Wind Energy Penetration
On a worldwide basis, a record of roughly 42,000 MW of wind power capacity was added in2011, up 6% from the additions experienced in 2010 and bringing the cumulative total to241,000 MW (BTM 2012; Table 1). 5 In terms of cumulative capacity, the United States ended5

Yearly and cumulative installed wind power capacity in the United States are from the present report, while global
wind power capacity comes from BTM (2012), but updated with the U.S. data presented here. Some disagreement
exists among these data sources and others, e.g., Windpower Monthly, the Global Wind Energy Council, andAWEA.

52011 Wind Technologies Market Reportthe year with almost 20% of total global wind power capacity, but is now a distant second to
China by this metric (Table 1).6 Over the past 10 years, cumulative wind power capacity has
grown by an average of 27% per year in the United States, somewhat higher than the 25%
growth rate globally. Annual growth in cumulative capacity was down in 2011, however, at 16%
for the U.S. and 21% globally.
After leading the world in annual wind power capacity additions from 2005 through 2008, theU.S. has now – for three years – been second to China (Table 1), representing roughly 16% of
global installed capacity in 2011, up slightly from 13% in 2010, but down substantially from
26% in 2009, 30% in 2008, and 27% in 2007. China now dominates global wind power
rankings, with an approximate 42% share of the global market for new wind power additions in
2011. India, Germany, and the U.K. rounded out the top five countries in 2011 for annual
capacity additions.
Table 1. International Rankings of Wind Power Capacity
Annual Capacity(2011, MW)
China
U.S.
India
Germany
U.K.
CanadaSpain
Italy
FranceSwedenRest of World
TOTAL

17,631
6,816
3,300
2,007
1,293
1,267
1,050
950
875
763
5,766
41,718Cumulative Capacity(end of 2011, MW)
China
62,412
U.S.
46,916
Germany
29,248Spain
21,350India
16,266
U.K.
7,155
France
6,836
Italy
6,733
Canada5,278
Portugal
4,214
34,453
Rest of World
TOTAL
240,861

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

A number of countries are beginning to achieve relatively high levels of wind energy penetrationin their electricity grids. Figure 3 presents data on end-of-2011 (and end-of-2006/07/08/09/10)
installed wind power capacity, translated into projected annual electricity supply based onassumed country-specific capacity factors, and divided by projected 2012 (and actual or
projected 2007/08/09/10/11) electricity consumption. Using this approximation for thecontribution of wind power to electricity consumption, and focusing only on the 20 countries
with the greatest cumulative installed wind power capacity, end-of-2011 installed wind power isestimated to supply the equivalent of roughly 29% of Denmark’s electricity demand, 19% ofPortugal’s, 19% of Spain’s, 18% of Ireland’s, and 11% of Germany’s. In the United States, thecumulative wind power capacity installed at the end of 2011 is estimated, in an average year, toequate to roughly 3.3% of the nation’s electricity demand (up from 2.9% at the end of 2010, and6Wind power additions and cumulative capacity in China are from BTM (2012), and include a considerable amountof capacity that was installed but that had not yet begun to deliver electricity by the end of 2011, due to a lack of
coordination between wind developers and transmission providers, and the lengthier time that it takes to build
transmission and interconnection facilities. All of the U.S. capacity reported here, on the other hand, was capable ofelectricity delivery.

6
2011 Wind Technologies Market Reportjust 0.9% at the end of 2006). 7 On a global basis, wind energy’s contribution at the end of 2011
is estimated to be 2.9%.
30%

Estimated Wind Generation as a
Proportion of Electricity Consumption

28%

Approximate Wind Penetration, end of 2011

26%

Approximate Wind Penetration, end of 2010

24%
22%

Approximate Wind Penetration, end of 200920%

Approximate Wind Penetration, end of 2008

18%

Approximate Wind Penetration, end of 2007

16%

Approximate Wind Penetration, end of 2006

14%
12%
10%
8%
6%
4%

TOTAL

Japan

BrazilCanadaAustralia

TurkeyChina

FranceU.S.

Poland

India

Italy

Netherlands

SwedenUK

GreeceGermany

IrelandSpain

Portugal

0%

Denmark

2%

Source: Berkeley Lab estimates based on data from BTM Consult, EIA, and elsewhere

Figure 3. Approximate Wind Energy Penetration in the Twenty Countries with theGreatest Installed Wind Power Capacity

California Added More New Wind Power Capacity than Any Other State,
While Six States Are Estimated to Exceed 10% Wind Energy Penetration
New large-scale 8 wind turbines were installed in 30 states in 2011. With 921 MW installed,
California added the most new wind capacity in 2011, ending Texas’ six-year reign (Texas fell toninth place in 2011, with 297 MW). As shown in Figure 4 and Table 2, other leading states interms of new capacity (each with more than 500 MW) included Illinois, Iowa, Minnesota,
Oklahoma, and Colorado. Nineteen states added more than 100 MW each in 2011.
On a cumulative basis, Texas remained the clear leader among states, with 10,394 MW installedat the end of 2011 – more than 6,000 MW more than the next-highest state (Iowa, with 4,322
MW). In fact, Texas has more installed wind power capacity than all but five countries(including the U.S.) worldwide. States following (distantly) Texas in cumulative installedcapacity include Iowa, California, Illinois, Minnesota, Washington, Oregon, and Oklahoma – allwith more than 2,000 MW. Twenty-nine states had more than 100 MW of wind capacity
installed as of the end of 2011, with twenty of these topping 500 MW, eight topping 2,000 MW,
7

In terms of actual 2011 deliveries, EIA reports that wind energy represented 2.9% of net electricity generation and3.2% of national electricity consumption in the United States. These figures are below the 3.3% figure provided
above in part because 3.3% is a projection based on end-of-year 2011 wind power capacity.
8“Large-scale” turbines are defined consistently with the rest of this report – i.e., turbines over 100 kW.

72011 Wind Technologies Market Reportand one (Texas) topping 10,000 MW. Although all wind power projects in the United States todate have been installed on land, offshore development activities continued in 2011, as discussed
in the next section.

Note: Numbers within states represent cumulative installed wind capacity and, in parentheses, annual additions in 2011.

Figure 4. Location of Wind Power Development in the United States

Some states are beginning to realize relatively high levels of wind energy penetration. The righthalf of Table 2 lists the top 20 states based on both actual wind electricity generation in 2011 as
well as estimated wind electricity generation from end-of-2011 wind power capacity, both
divided by total in-state electricity generation in 2011. 9 Using either method, the same four
upper Midwest states – North and South Dakota, Minnesota, and Iowa – lead the list (though in aslightly different order). Most notably, the wind power capacity installed in South Dakota andIowa as of the end of 2011 is estimated, in an average year, to supply approximately 22% and9Wind energy penetration can either be expressed as a percentage of in-state load or in-state generation. In-state
generation is used here, primarily because wind energy (like other energy resources) is often sold across state lines,
which tends to distort penetration levels expressed as a percentage of in-state load. The actual penetration of windelectricity generation in 2011 is based exclusively on preliminary EIA data for 2011, and matches what AWEA
provides in its U.S. Wind Industry Annual Market Report (AWEA 2012a). For the estimated penetration – which
captures the full, rather than partial, impact of new wind power capacity added in 2011 – end-of-2011 wind power
capacity is translated into estimated annual wind generation based on estimated state-specific capacity factors thatderive from the project performance data reported later in this report. The resulting state-specific wind electricity
generation estimates are then divided by preliminary EIA data on total in-state electricity generation in 2011.

8
2011 Wind Technologies Market Report20%, respectively, of all in-state electricity generation. Four other states are also estimated to
exceed 10% penetration by this metric: Minnesota (14.9%), North Dakota (14.1%), Colorado(10.7%), and Oregon (10.5%).
Table 2. United States Wind Power Rankings: The Top 20 States
Capacity (MW)

Percentage of In-State Generation

Annual (2011)
California
921
Illinois
692
Iowa
647
Minnesota
542
Oklahoma
525
Colorado
506
Oregon409
Washington
367
Texas
297
Idaho
265
Michigan
213
Kansas200
Wisconsin
162
West Virginia
134
Maine
131
New York
129
Nebraska
125
Utah
102
Ohio
102
South Dakota
75
Rest of U.S.
274

Cumulative (end of 2011)
Texas
10,394Iowa
4,322
California
3,917
Illinois
2,742
Minnesota
2,718
Washington
2,573
Oregon2,513
Oklahoma
2,007
Colorado
1,805
North Dakota
1,445
Wyoming
1,412
New York
1,403
Indiana
1,340
Kansas
1,274
Pennsylvania
789
South Dakota
784
New Mexico
750
Wisconsin
631
Idaho
618
West Virginia
564
Rest of U.S.
2,915

Actual (2011)*
South Dakota
22.3%
Iowa
18.8%
North Dakota
14.7%
Minnesota
12.7%
Wyoming
10.1%
Colorado
9.2%
Kansas
8.2%
Idaho
8.2%
Oregon8.2%
Oklahoma
7.1%
Texas
6.9%
New Mexico
5.4%
Washington
5.3%
Maine
4.5%
Montana
4.2%
California
4.0%
Illinois
3.1%
Hawaii
3.1%
Nebraska
2.9%
Indiana
2.7%
Rest of U.S.
0.4%

Estimated (end of 2011)**
South Dakota
22.1%
Iowa
20.0%
Minnesota
14.9%
North Dakota
14.1%
Colorado
10.7%
Oregon
10.5%
Idaho
9.7%
Kansas9.2%
Oklahoma
9.1%
Wyoming
8.8%
Texas
7.3%
Maine
6.5%
New Mexico
5.8%
Washington
5.5%
California
4.7%
Montana
3.8%
Illinois
3.7%
Hawaii
3.7%
Indiana
3.0%
Nebraska
2.9%
Rest of U.S.
0.5%

TOTAL

TOTAL

TOTAL

TOTAL

6,816

46,916

2.9%

3.2%* Based on 2011 wind and total generation by state from EIA’s Electric Power Monthly.
** Based on a projection of wind electricity generation from end-of-2011 wind power capacity, divided by total in-state electricity
generation in 2011.
Source: AWEA project database, EIA, Berkeley Lab estimates

No Offshore Turbines Have Been Commissioned in the United States, but
Offshore Project and Policy Developments Continued in 2011 10
At the end of 2011, global offshore wind power capacity stood at roughly 4,000 MW (BTM
2012), with the vast majority of 2011 additions and cumulative capacity located in Europe. Just
470 MW of new offshore wind power capacity was commissioned in 2011, a two-thirds decrease
from 2010, though BTM (2012) reports that more than 1,500 MW are likely to be installed in
2012.
10

A companion report funded by the U.S. Department of Energy that focuses exclusively on offshore wind energy
will be published later this year, and will provide a detailed summary of the status of the offshore wind sector in the
United States.

9
2011 Wind Technologies Market ReportTo date, no offshore projects have been installed in the United States, and the emergence of aU.S. offshore wind power market faces both challenges and opportunities. Perhaps mostimportantly, the projected near-term costs of offshore wind energy remain high. Additionally,planning, siting, and permitting can be challenging, as demonstrated in the long history of theCape Wind project. At the same time, interest in developing offshore wind energy exists inseveral parts of the country. Driving this interest is the proximity of offshore wind resources topopulation centers, the potential for local economic development benefits, advances intechnology, and superior capacity factors (and, in some instances, peak load coincidence)compared to the finite set of developable land-based wind power projects available in someregions. Moreover, significant strides relating to offshore wind energy have been made recently
in the federal arena, both through the Department of the Interior's responsibilities with regards toregulatory approvals and the Department of Energy's investments in offshore R&D.

Figure 5. Proposed Offshore Wind Power Projects in a Relatively Advanced State ofDevelopment

Figure 5 identifies ten proposed offshore wind power projects in the United States that have been
identified by Navigant Consulting as being more-advanced in development process: generally,
this includes projects that have signed power purchase agreements, those with a partnership witha potential power offtaker, those that are pursuing detailed surveying/permitting efforts, and102011 Wind Technologies Market Reportthose that are expecting to install demonstration or pilot-phase turbines in the relatively near
future. In total, these proposed projects equal 3,800 MW, and are primarily located in the
Northeast and Mid-Atlantic, though proposed projects also exist in the Great Lakes and Gulf of
Mexico. It is not certain which of these projects will ultimately come to fruition, while manyother proposed projects not listed in Figure 5 are in earlier planning phases.
Of the projects identified in Figure 5, two have signed power purchase agreements (PPAs): CapeWind (Massachusetts) and Deepwater Wind (Rhode Island). The nation's first offshore wind
PPA, for NRG Bluewater’s project off the coast of Delaware, was canceled by the developer in2011.

Data from Interconnection Queues Demonstrate that an Enormous Amountof Wind Power Capacity Is Under Consideration
One testament to the continued interest in land-based wind energy is the amount of wind power
capacity currently working its way through the major transmission interconnection queues acrossthe country. Figure 6 provides this information for wind power and other resources aggregatedacross 41 different interconnection queues administered by independent system operators (ISOs),
regional transmission organizations (RTOs), and utilities. 11 These data should be interpretedwith caution: though placing a project in the interconnection queue is a necessary step in project
development, being in the queue does not guarantee that a project will actually get built. In fact,projects currently in interconnection queues are often very early in the development process. As
a result, efforts have been and are being taken by the Federal Energy Regulatory Commission(FERC), ISOs, RTOs, and utilities to reduce the number of speculative projects that have – inrecent years – clogged these queues. One consequence of those efforts, as well as perhaps theuncertain magnitude of the future wind market in the U.S. given the impending scheduled
expiration of federal tax incentives, is that the total amount of wind power capacity in thenation's interconnection queues has declined in recent years.

11

The queues surveyed include PJM Interconnection (PJM), Midwest Independent System Operator (MISO), NewYork ISO (NYISO), ISO-New England (ISO-NE), California ISO (CAISO), Electric Reliability Council of Texas(ERCOT), Southwest Power Pool (SPP), Western Area Power Administration (WAPA), Bonneville Power
Administration (BPA), and 32 other individual utilities. To provide a sense of sample size and coverage, the ISOs,
RTOs, and utilities whose queues are included here have an aggregated peak demand of almost 70% of the U.S.
total. Figures 6 and 7 only include projects that were active in the queue at the end of 2011 but that had not yet been
built; suspended projects are not included.

11
2011 Wind Technologies Market Report

250

Nameplate Capacity (GW)Entered queue in 2011

Total in queue at end of 2011

200

150

100

50

0
Wind

Natural Gas

Solar

Nuclear

Coal

Other

Source: Exeter Associates review of interconnection queues

Figure 6. Nameplate Resource Capacity in 41 Selected Interconnection Queues

Even with this important caveat, the amount of capacity in the nation’s interconnection queues
still provides at least some indication of the amount of wind power development that is in theplanning phase. At the end of 2011, even after reforms by a number of ISOs, RTOs, and utilities
to reduce the number of projects in their queues, there were 219 GW of wind power capacity
within the interconnection queues reviewed for this report – almost five times the installed wind
power capacity in the United States. 12 This 219 GW represented 45% of all generating capacity
within these selected queues at that time, and was 1.5 times as much capacity as the next-largest
resource, natural gas. In 2011, 40 GW of gross wind power capacity entered the interconnection
queues, compared to 54 GW of natural gas and 25 GW of solar; relatively little nuclear and coalcapacity entered these queues in 2011. Of note, however, is that the absolute amount of windand coal power in the sampled interconnection queues (considering gross additions and projectdrop-outs) has declined in recent years, whereas natural gas and solar capacity has increased.
Much of this wind power capacity is planned for the Midwest, PJM Interconnection, Texas,
Mountain, Northwest, Southwest Power Pool, and California regions: wind power projects in theinterconnection queues in these regions at the end of 2011 accounted for 96% of the aggregate
219 GW of wind power in the selected queues (Figure 7). Smaller amounts of wind power
capacity were represented in the interconnection queues of the New York ISO (2.6%), ISO-New
England (1.4%), and the Southeast (0.3%).

12

As a rough benchmark, 300 GW of wind power capacity is the approximate amount of capacity required to reach
20% wind energy penetration in the United States in 2030, as estimated in DOE (2008).

12
2011 Wind Technologies Market ReportNameplate Wind Power Capacity (GW)

50Entered queue in 201145

Total in queue at end of 2011

40
35
30
25
20
15
10
5
0
MISO /
MidwestPJM

ERCOT Mountain Northwest

SPP

California New York ISO-New Southeast
ISO
ISO
England

Source: Exeter Associates review of interconnection queues

Figure 7. Wind Power Capacity in 41 Selected Interconnection Queues

As a measure of the near-term development pipeline, Ventyx (2012) estimates that – as of midJune 2012 – approximately 40 GW of wind power capacity was either under construction or insite preparation (11 GW of the 40 GW total), in-development and permitted (14 GW of the 40
GW), or in-development with pending permit and/or regulatory applications (the remaining 15
GW of the 40 GW total). This total is similar to the 38 GW that was in the development pipeline
as of last year at approximately the same time (April 2011), indicating, potentially, that thedevelopment pipeline remains robust despite political uncertainty at the federal level. AWEA
(2012c), meanwhile, reports 1,695 MW of wind power capacity installed in the first quarter of
2012, with another 8,900 MW under construction as of the end of March 2012.

132011 Wind Technologies Market Report

3. Industry Trends
Despite the Ongoing Proliferation of New Entrants, the “Big Three” Turbine
Suppliers Have Gained U.S. Market Share Since 2009
New U.S. wind projects built in 2011 deployed 2,006 MW of GE Wind turbines, compared to1,969 MW of Vestas turbines, representing a roughly 29% market share for each manufacturer. 13
Following GE Wind and Vestas were Siemens (with an 18% market share), Suzlon and
Mitsubishi (both at 5%), Nordex and Clipper (both at 4%), REpower (3%), 14 and Gamesa (2%).
Other utility-scale (>100 kW) wind turbines installed in the U.S. in 2011 (and that fall into the“Other” category in Figure 8) were manufactured by Alstom (43 MW), Sany Electric (10 MW),
Vensys (6 MW), Samsung (5 MW), Goldwind (4.5 MW), Hyundai (3.3 MW), Kenersys (2.5MW), Northern Power Systems (2.3 MW), Sinovel (1.5 MW), Unison (1.5 MW), Nordic
Windpower (1 MW), PowerWind (0.9 MW), and Aeronautica (0.75 MW). This list of turbine
suppliers is increasingly global in nature, with manufacturers no longer hailing just from theUnited States, Europe, Japan, and India, but now also from China and South Korea.
Turbine Manufacturer U.S. Market Share

100%

Other

90%

Acciona80%

Gamesa70%

REpower

60%

Clipper50%

Nordex40%

Mitsubishi

30%

Suzlon20%

Siemens
Vestas

10%0%

GE Wind

2005

2006

2007

2008

2009

2010

2011

Source: AWEA project database

Figure 8. Annual U.S. Market Share of Wind Manufacturers by MW, 2005-2011

Figure 8 and Table 3 depict a notable increase in the number of wind turbine manufacturers
serving the U.S. market since 2005, when just five manufacturers (compared to twenty in 2011)
installed more than 1 MW, and just four manufacturers captured 99% of the market (compared tothe ten it took to reach 99% in 2011). Despite steady growth in the number of turbine
manufacturers serving the U.S. market over time, however, the “big three” turbine suppliers –GE Wind, Vestas, and Siemens – have, in aggregate, actually gained market share since
2008/2009 (from 66% in both 2008 and 2009 up to 76% in 2011), reversing some of their earlier
13

Market share reported here is in MW terms, and is based on project installations in the year in question, notturbine shipments or orders.
14
As of October 2011, REpower became a wholly owned subsidiary of Suzlon.

142011 Wind Technologies Market Reportlosses through 2008. This recapture may, in part, reflect a legacy of the financial crisis (i.e., aheightened preference among investors for projects using “bankable” turbines), coupled with
ample turbine supply (relative to demand), which reduces the need to consider less-bankabletechnology.
Table 3. Annual U.S. Turbine Installation Capacity, by Manufacturer
Manufacturer
GE Wind
VestasSiemens
SuzlonMitsubishi
NordexClipper
REpower
GamesaAcciona
Other
TOTAL

2005
1,431
699
0
0
190
0
3
0
50
0
2
2,375

2006
1,146
439
573
92
128
0
0
0
74
0
2
2,454

Turbine Installations (MW)
2007
2008
2009
2,342
3,585
3,995
948
1,120
1,488
863
791
1,162
197
738
702
356
516
814
3
0
63
48
470
605
0
94
330
494
616
600
0
410
204
0
22
38
5,249
8,361
10,000

2010
2,543
221
828
413
350
20
70
68
564
99
37
5,214

2011
2,006
1,969
1,233
334
318
288
258
172
154
0
85
6,816

Source: AWEA project database

Globally, U.S.-owned GE remained the third-leading supplier of turbines worldwide in 2011,
with an 8.8% market share (down from 9.3% in 2010), behind Vestas’ 12.9% and Goldwind's
9.4% (BTM 2012). No other U.S.-owned manufacturer cracked the top-15. 15 On a worldwide
basis, Chinese turbine manufacturers continue to occupy positions of prominence: four of the
top ten, and seven of the top 15, leading global suppliers of wind turbines in 2011 hail from
China.
To date, the growth of Chinese turbine manufacturers has been based almost entirely on sales to
the Chinese market. With the Chinese market beginning to show signs of cooling, however,
Chinese (and South Korean) manufacturers have begun to look abroad and penetrate theinternational wind turbine market, including with limited sales into Europe and the United States.
In the United States, for example, 2011 installations by Chinese and South Korean manufacturers
included those from Sany Electric (10 MW), Samsung (5 MW), Goldwind (4.5 MW), Hyundai(3.3 MW), Sinovel (1.5 MW), and Unison (1.5 MW). Many of these early installations havebeen developed and financed by the turbine suppliers themselves, and until there is sufficient
operating experience to mitigate uncertainty over turbine quality and bankability, widespread
entry by Chinese suppliers into the U.S. market seems unlikely. Nevertheless, the historicallydominant wind turbine suppliers in the U.S. market are likely to face growing competition fromnew entrants in the coming years.

15

These statements emphasize the sale of large wind turbines. U.S. manufacturers are major players in the global
market for smaller-scale turbines (AWEA 2012b).

15
2011 Wind Technologies Market Report

Domestic Wind Turbine and Component Manufacturing Capacity Has
Increased, but Uncertainty in Future Demand Has Put the Wind Turbine
Supply Chain Under Severe Pressure
Faced with substantial expected growth in wind power capacity additions in 2012, but uncertain
prospects after 2012, the wind industry’s domestic supply chain faces conflicting pressures. As
the cumulative capacity of wind power projects has grown, foreign and domestic turbine andcomponent manufacturers have localized and expanded operations in the United States. In fact,
despite the near-term demand uncertainty, a larger number of new turbine and component
manufacturing facilities (16) opened in 2011 than in 2010 (13). Figure 9 presents a nonexhaustive list of the 16 wind turbine and component manufacturing and assembly facilities that
opened in 2011, the 10 new manufacturing facilities announced (but not yet built) in 2011, andthe more than 165 existing manufacturing facilities that were open prior to 2011. 16

Figure 9. Location of Existing and New Turbine and Component Manufacturing Facilities
16

The data on existing, new, and announced manufacturing facilities presented here differ somewhat from thosepresented in AWEA (2012a) due, in part, to methodological differences. In addition, AWEA (2012a) has access todata on smaller component suppliers that are not included here.

16
2011 Wind Technologies Market ReportOf the new or announced facilities captured in Figure 9, two are owned by major international
wind turbine original equipment manufacturers (OEMs): Vestas (blades in Brighton, Colorado)and Alstom (turbines in Amarillo, Texas). In addition, GE opened a new logistics center for
renewable energy components in Mississippi (logistics and research centers are not included in
Figure 9). 17
Eight of the ten OEMs with the largest share of the U.S. market in 2011 (Alstom, Clipper,
Gamesa, GE, Nordex, Siemens, Suzlon, and Vestas) had one or more operational manufacturing
facilities in the United States in 2011 (Suzlon, however, announced the closure of its facility in2012). Companies with multiple facilities include Gamesa, GE, Siemens, and Vestas. Other
active domestic and foreign OEMs that have sold larger turbines in the U.S. market and that haveestablished U.S. manufacturing facilities include Acciona, DeWind, Northern Power Systems,
and Aeronautica, while still other companies have announced their interest in manufacturing but
have not yet installed any utility-scale turbines in the United States. In contrast to the multiple
OEMs operating in 2011, there was only one active utility-scale wind energy OEM assembling
nacelles in the United States as late as 2004 (GE). 18
The growth in U.S. wind turbine manufacturing capability and the drop in wind power plantinstallations since 2009 led to an estimated over-capacity of U.S. turbine nacelle assembly
capability of more than 5 GW in 2011, in comparison to 4 GW of under-capacity in 2009
(Figure 10). Over-capacity is defined here as maximum turbine nacelle assembly capacity in
the U.S. exceeding total turbine demand in the U.S. Because maximum factory utilization is
uncommon, some level of over-capacity should not be considered problematic. On the other
hand, actual over-capacity at U.S. nacelle assembly facilities likely exceeded these estimates
because U.S. demand for wind turbines is also partially met with imports from other countries(see next section), leading to U.S. nacelle assembly facilities operating at well below theirmaximum capability in 2011. 19 With maximum domestic turbine nacelle assembly capacity
predicted by Bloomberg NEF (2012a) to stabilize at approximately 13 GW in the near term,
over-capacity relative to U.S. turbine demand (not considering imports or exports of turbines)
is anticipated to be severe in 2013 and 2014 when wind power capacity additions are expected
to decline (see Section 8, “Future Outlook”).

17

Vestas, however, announced the cancellation of its planned R&D facility in Massachusetts in early 2012.
Nacelle assembly is defined here as the process of combining the multitude of components included in a turbine
nacelle to produce a complete turbine nacelle unit.
19
Exports of wind turbines from U.S. nacelle assembly facilities to other countries have the ability to reduce theestimated over-capacity, but as shown in the next section, U.S. exports have been relatively modest to date.
18

172011 Wind Technologies Market ReportWind Turbine Nacelle Assembly Capacity in the
U.S. (and Wind Turbine Installations) (GW)

14
12

Other

10

Nordex

8

GamesaSiemens6

Vestas4GE
2
0

U.S. Turbine
Installations
2006

2007

2008

2009

2010

2011

2012e

2013e

2014e

Source: Bloomberg New Energy Finance

Figure 10. Domestic Wind Turbine Nacelle Assembly Capacity and Demand

Beyond nacelle assembly, Figure 9 shows a good number of new component manufacturing
facilities announced or opened in 2011. Figure 11 segments the manufacturing facilities
operating in the U.S. by major component, including those that opened prior to and in 2011 (thefigure excludes announced but not yet opened facilities).

Number of Manufacturing Facilities

100

Opened in 201190

Open before 2011

80
70
60
50
40
30
20
10
0
Other

NacelleComponents

TowersBlades

Turbines

Note: Manufacturing facilities that produce multiple components are included in multiple bars.
Source: National Renewable Energy Laboratory

Figure 11. Number of Operating Wind Turbine and Component Manufacturing Facilities
on U.S. Soil18
2011 Wind Technologies Market ReportThough new and announced turbine and component manufacturing facilities are spread acrossthe country, a number of component manufacturers are choosing to locate in markets with
substantial wind power capacity or near already established large-scale OEMs. For example, in
2011, four component suppliers opened or announced facilities in Texas, a state with bothsubstantial historical wind power additions and a strong wind turbine and component
manufacturing base. Two new component manufacturing facilities were opened or announced
in both Colorado and Michigan; both states are strategically positioned geographically nearlarge wind power markets, therefore allowing for reduced transportation challenges and costs.
Even states that are relatively far-removed from major wind power markets – including several
states in the Southeast – have seen new wind turbine and component manufacturing facilities
come online in recent years. Workforce considerations, transportation costs, and state and local
incentives are among the factors that typically drive location decisions.
AWEA (2012a) estimates that the wind energy industry directly and indirectly employed
75,000 full-time 20 workers in the United States at the end of 2011 – equal to the jobs reported
in 2010 but fewer than in 2008 and 2009. The 75,000 jobs include manufacturing (which
accounts for 30,000 jobs), project development, construction and turbine installation,
operations and maintenance, transportation and logistics, and financial, legal, and consulting
services.
Notwithstanding these developments, policy uncertainty and unfavorable market conditions (e.g.,
low wholesale power prices and competition amount turbine and component suppliers) arestraining the wind industry's manufacturing supply chain, as margins drop and concerns about
manufacturing overcapacity deepen, potentially setting the stage for significant layoffs. As noted
earlier, maximum nacelle assembly capacity in the U.S. (as well as component manufacturing insome cases) substantially exceeds post-2012 near-term expected demand for wind in the U.S.,
yielding relatively lower utilization of the production capacity of existing facilities, downward
pressure on component and turbine pricing, and compressed manufacturer profit margins.
Reportedly in part as a result, Mitsubishi – the OEM with the 5th-largest amount of U.S.
installations in 2011 – announced in early 2012 that it would indefinitely delay the opening of its
Fort Smith, Arkansas manufacturing facility. UTC, meanwhile, announced that it was seeking tosell Clipper, while a wide range of OEMs – including GE, Vestas, Siemens, Nordex, Gamesa,
Goldwind, and Sinovel – have recently announced weakened financial results. Consequently,
Vestas has indicated that it will lay off 182 people in the U.S. and is prepared to make further
and more-substantial cuts if the PTC is not extended. Gamesa, NRG, Clipper, Iberdrola, EDP
Renewables North America, and others have also recently announced cuts to their U.S.
workforce, demonstrating that elements of the entire supply chain, from OEMs to developers, areat risk.

20

Jobs are reported as full-time equivalents. For example, two people working full-time for six months are equal to
one full-time job in that year.

19
2011 Wind Technologies Market ReportA Growing Percentage of the Equipment Used in U.S. Wind Power Projects
Has Been Sourced Domestically in Recent Years
As a result of the aforementioned developments in U.S.-based wind turbine and component
manufacturing, the share of domestically manufactured wind turbines and components has grown
in recent years, while the import share has witnessed a corresponding drop. These trends aresupported by an analysis of data from the U.S. Department of Commerce. 21
Figure 12 presents calendar-year data on estimated U.S. imports of wind-related equipment from2005 through 2011. 22 Specifically, the figure shows imports of wind-powered generating sets
(i.e., nacelles and, when imported with the nacelle, other turbine components) as well as importsof turbine components that are shipped separately from the generating sets. 23 The separate
importation of selected wind turbine components includes towers as well as other wind turbine
components (specifically, generators, blades and other components, and gearboxes). Estimatesprovided for these component-level imports in Figure 12 should be viewed with caution because
the underlying data used to produce the figure are based on trade categories that are not exclusive
to wind energy (e.g., they could include generators for non-wind applications). The componentlevel import estimates shown in Figure 12 therefore required assumptions about the fraction oflarger trade categories likely to be represented by wind turbine components. The error bars
included in Figure 12, meanwhile, account for uncertainty in these assumed fractions. 24

21

The Department of Commerce trade data are accessed through the U.S. International Trade Commission’s(USITC) DataWeb, which compiles statistics from the Department of Commerce on imports and exports. The
statistics can be queried online at: http://dataweb.usitc.gov/. The analysis presented here relies on the ‘customs
value’ of imports as opposed to the ‘landed value.’ For more information on these data and their application to windenergy, see David (2009, 2010, 2011).
22“Wind-powered generating sets” are in Harmonized Tariff Schedule (HTS) 8502.31.0000. This HTS provision
includes both utility-scale and small wind turbines. Estimating separate wind turbine component imports iscomplicated by the fact that the HTS does not contain provisions that are exclusive to wind turbine components.
Included in the analysis presented here are: HTS 7308.20.0000 – “towers and lattice masts” (available for years
2005-2010); HTS 7308.20.0020 – “towers and lattice masts - tubular” (available for 2011 only); HTS 8501.64.0020– “AC generators (alternators) from 750 to 10,000 kVA”; HTS 8412.90.9080 – “other parts of engines and motors”;
HTS 8503.00.9545 – “parts of generators (other than commutators, stators, and rotors)”; HTS 8483.40.5010 – “fixedratio speed changers”; and HTS 8483.40.5050 – “multiple and variable ratio speed changers.”
23
Wind turbine components such as blades, towers, generators, and gearboxes are included in the data on windpowered generating sets if shipped with the nacelle. Otherwise, these component imports are reported separately.
24
Given the split of the "towers and lattice masts" HTS classification into “tubular” and “other” in 2011, we
calculated the 2011 ratio of “tubular” tower imports (all of which are assumed to be wind-related) to the sum of“tubular” and “other” tower and lattice mast imports. Using this ratio and considering overall U.S. import levels ofwind-related equipment, it is assumed that the proportion of towers and lattice masts imports from 2005-2010 thatare related to towers used in U.S. wind power plants increases from 80% in 2005 to 90% in 2008, before decreasing
to 80% in 2010. Based on a review of the countries of origin for the imports, personal communications with USITC
and AWEA staff, David (2010), and Wyden (2010), the proportion of wind-related equipment in the five otherrelevant HTS provisions (i.e., wind turbine components other than towers) is assumed to increase from 40% in 2005
to 55% in 2008, before dropping back to 40% in 2010, and staying at 40% in 2011. These trends are intended toreflect, in part, the rapidly increasing imports of wind equipment from 2005-2008, and the subsequent decline inimports from 2008-2010, before steadying in 2011. To reflect uncertainty in these proportions, a ±15% variation isapplied to the trade categories that include wind turbine components other than towers, and a ±5% variation isapplied to the category that includes wind turbine towers.

20
2011 Wind Technologies Market Report

7

Estimated US Imports:

Exports of Wind-Powered
Generating Sets

Other Wind Turbine Components
6

TowersWind-Powered Generating Sets

Billion US $2011

5
4
3
2
1
0

2005
2375 MW

20062454 MW20075249 MW

20088361 MW2009
10000 MW2010
5214 MW

2011
6816 MW

Source: Berkeley Lab analysis of data from USITC DataWeb: http://dataweb.usitc.gov

Figure 12. Estimated Imports of Wind-Powered Generating Sets, Towers, and Other Wind
Turbine Components, as Well as Exports of Wind-Powered Generating Sets

As shown, estimated imports of wind-related equipment into the United States substantially
increased from 2005-2008, before falling dramatically through 2010 and then increasing
somewhat in 2011. These overall trends are driven primarily by changes in the share ofdomestically manufactured wind turbines and components (versus imports) as well as changes in
the annual rate of wind power capacity installations and wind turbine prices.
Figure 12 also shows that exports of wind-powered generating sets from the United States haveincreased, rising from $15 million in 2007 to $147 million in 2010, and staying relatively
constant at $149 million in 2011. The largest destination markets for these exports over theentire 2005-2011 timeframe have included Canada (54%), Brazil (19%), Mexico (10%), China(6%), and Honduras (4%), while 2011 exports were dominated by Brazil (67%), Honduras(16%), Mexico (8%), and Canada (8%). Wind turbine component exports (towers, blades,
gearboxes, generators) are not shown in the figure because such exports are likely a small and/or
uncertain fraction of the broader trade category totals. 25 Despite some long-term growth inexports, it is clear from these data that the U.S. remained a sizable net importer of wind turbine
equipment over the entire 2005 to 2011 timeframe.

25

U.S. exports of ‘towers and lattice masts’ in 2011 totaled $102 million, however, with the largest destination
markets being Canada (42%), Costa Rica (14%), and Mexico (11%). The U.S. ITC data for tower exports do notdifferentiate between tubular towers (used in wind power applications) and other types of towers, unlike the importclassification for 2011. Though it is likely that most of these tower exports are wind-related, the exact proportion is
not known and hence the $102 million figure should be viewed with some caution.

21
2011 Wind Technologies Market Report

Looking behind the import data presented in Figure 12 in more regional detail, Figure 13 showsa number of trends in the origin of the U.S. imports of wind-powered generating sets andtowers. 26 The primary source markets for wind-powered generating sets during the 2005-2011
period have been the home countries of the major international turbine manufacturers: Denmark,Spain, Japan, India, and Germany. The obvious exception is Italy, which is not “home” to amajor wind turbine manufacturer, though Vestas, at least, has blade and nacelle manufacturing
facilities there. Offsetting the recent increase in Italy's share (as well as the lesser increase in
Denmark's contribution from 2009-2011) has been a notable recent decline in the share ofimports from Japan, Spain, and the India. 27 The countries of origin for tower imports are only
reported for the year 2011, as the proportion of tower imports that were wind-related for eachcountry is not known for years 2005-2010, before the HTS classification that contains towers
was split into a tubular and “other” category. In 2011, the share of imports of tubular towers
from Asia was over 80%, with a sizable proportion of the imports from China, Vietnam, andKorea, as well as from Canada and Mexico; unlike for wind-powered generating sets, the shareof tower imports from Europe is minor. Responding to a case brought by a number of U.S. tower
manufacturers, in May 2012 the U.S. Commerce Department issued a preliminary ruling that will
impose additional duties on Chinese towers imported into the United States. Once finalized, thistrade case may impact the magnitude and source countries of tower imports to the U.S. in years
to come.
Wind-Powered Generating Sets
100%

Asia

Other

Towers - 2011

Asia

3%

China
Vietnam

80%
8%

15

60%

Europe
40%

Korea

9%

5%

44%

14%

Canada18%

EuropeOther
Asia

Mexico20%
All Europe0%2005 2006 2007 2008 2009 2010 2011

Source: Berkeley Lab analysis of data from USITC DataWeb: http://dataweb.usitc.gov

Figure 13. Origins of Imports of Wind-Powered Generating Sets and Towers

26

Only the origin of imports for “wind-powered generating” sets and “towers” are presented in Figure 13 because
the other five trade categories that sum to “other wind turbine components” in Figure 12 are assumed to havesmaller proportions of wind-related equipment.
27
Over the entire 2005-2011 timeframe, the largest source countries for wind-powered generating sets were:
Denmark (42%), Spain (16%), Japan (13%), India (10%), and Germany (8%) (in 2011, the top three countries were
Denmark (55%), Italy (24%), and Germany (8%)).

22
2011 Wind Technologies Market ReportThough Figures 12 and 13 depict a U.S. market that remains reliant on imports of wind power
equipment, that reliance has declined over time as growth in installed wind power capacity has
outpaced wind turbine and component imports. To estimate the percentage share of imports anddomestic manufacturing over time, one must account for the fact that turbines, towers, and othercomponents imported at the end of one year may not be installed until the following year. As
such, in Figure 14 the combined imports of wind-powered generating sets and selected turbine
components are determined by using a 4-month lag (i.e., monthly import data from September ofthe previous year to August of the current year are used to estimate the value of imports in windturbine installations in the current year). Those import figures are then compared to total windturbine equipment-related costs on a calendar-year basis. 28 Data from 2005-2010 are averaged
over two-year periods to further avoid “noise” in the resulting estimates. The error bars
correspond to those in Figure 12, and represent the uncertainty in the proportion of wind-related
equipment imports in certain larger trade categories.

Billion US$2011

12

70%
60%

10

50%

8

40%

6

30%

4

20%

2

10%

Imports as Fraction of Turbine Cost

Average Annual Turbine Equipment Cost
(Calendar Year)
Value of Selected Imports(Customs value, 4 month lag, Sept - Aug)
Estimated Import Fraction

14

0%

0

2005-2006

2007-20082009-20102011

Figure 14. Estimated Wind Power Equipment Imports as a Fraction of Total Turbine Cost

Ultimately, when presented as a fraction of total equipment-related turbine costs in this fashion,
the overall import fraction is found to have declined considerably, from 65% in 2005-2006 to
33% in 2011 (conversely, domestic content has increased from 35% in 2005-2006 to 67% in2011). Reporting these figures as a proportion of total wind project installed costs (not just windturbine equipment-related costs) is also of interest, but is complicated by the fact that non-turbinebalance-of-plant costs may also involve some level of imports. Nonetheless, if one simply
assumes that 80% of non-turbine-equipment balance-of-plant costs derive from domestic sources
with the remaining 20% from imports, then the import fraction for total wind project installed
28

Total wind turbine costs ($/kW) are assumed to equal approximately 75% of the average project-level costs
reported later in this report in Figure 20, while wind turbine equipment-related costs are assumed to equal 85% of
total wind turbine costs (with the remaining 15% consisting of transportation, project management, and other soft
costs). To calculate total calendar-year wind turbine equipment-related costs, this wind turbine equipment-related
cost figure in $/kW is multiplied by annual wind power capacity installations.

23
2011 Wind Technologies Market Reportcosts would equal 48% in 2005-2006 and 28% in 2011 (i.e., domestic content would equal 52%
in 2005-2006 and 72% in 2011).
These figures should be considered rough approximations for the reasons stated earlier, and mayunderstate the wind power industry’s reliance on turbine and component imports because it ispossible that imports of wind power equipment are occurring under other trade categories thatare not captured here. Nonetheless, these figures demonstrate that a growing amount of theequipment used in wind power projects has been sourced domestically in recent years. Whether
that trend continues in the future may depend on the size and stability of the U.S. wind power
market as well as the manufacturing strategies of emerging turbine manufacturers from Asia andelsewhere.

The Average Nameplate Capacity, Hub Height, and Rotor Diameter ofInstalled Wind Turbines Increased
The average nameplate capacity of wind turbines that were newly installed in the United Statesin 2011 increased to roughly 1.97 MW (Figure 15), up from 1.80 MW in 2010. This was thelargest single-year increase in more than six years. Since 1998-99, average turbine nameplate
capacity has increased by 174%. 29

Average Turbine Size (MW)

2.25

1.97 MW

2.00
1.75

1.46 MW

1.50

0.75

1.65 MW

1.67 MW

1.74 MW

1.23 MW

1.25
1.00

1.60 MW1.80 MW0.89 MW0.72 MW

0.50
0.25
0.00
COD:1998-99

2000-01

2002-03

2004-05

2006

2007

2008

2009

2010

2011

Turbines: 1,431

1,974

1,687

1,900

1,530

3,190

5,014

5,736

2,902

3,464

MW: 1,029

1,751

2,080

2,769

2,453

5,249

8,360

9,997

5,210

6,816

Source: AWEA project database

Figure 15. Average Turbine Nameplate Capacity Installed During Period (only turbines >100 kW)

29

Figure 15 (as well as a number of the other figures and tables included in this report) combines data into both oneor two-year periods in order to avoid distortions related to small sample size in the PTC lapse years of 2000, 2002,
and 2004; though not a PTC lapse year, 1998 is grouped with 1999 due to the small sample of 1998 projects.

242011 Wind Technologies Market ReportTable 4 shows how the distribution of turbine nameplate capacity has shifted over time: nearly
42% of all turbines installed in 2011 had a nameplate capacity larger than 2.0 MW, up
significantly from 28% in 2010, 24% in 2009, 20% in 2008, 16% in both 2007 and 2006, and just
0.1% or less in years prior to 2006. GE’s 1.5/1.6 MW wind turbine remained the nation’s mostpopular turbine in 2011, with 1,170 units installed (709 of the 1.5 MW version, and 461 of the
1.6 MW version), equating to 26% of all wind power capacity installed in 2011. 30
Table 4. Size Distribution of Number of Turbines over Time (only turbines > 100 kW)

Turbine Size
Range (MW)Years: 1998-99 2000-01 2002-03 2004-05 2006
1,751
2,080
2,769 2,453# MW: 1,029
1,974
1,687
1,900 1,530# turbines: 1,431
0.2%
0.2%
0.1%
0.3%
>0.1≤0.5 0.5%
99%
74%
42%
19%
11%
>0.5≤1.0
26%
45%
56%
54%
>1.0≤1.5 0.0%
1%
0.4%
13%
24%
18%
>1.5≤2.0
0.0%
0.0%
0.1%
16%
>2.0≤2.5 0.0%
0.0%
0.1%
0.0%
0.0%
>2.5≤3.0 0.0%

2007
5,249
3,190
0.0%
11%
49%
23%
15%
1%

2008
8,360
5,014
0.0%
11%
54%
16%
17%
2%

2009
9,997
5,736
0.2%
5%
49%
21%
23%
1%

2010
5,210
2,902
0.1%
0.2%
52%
20%
25%
2%

2011
6,816
3,464
0.2%
0.2%
21%
37%
35%
7%

Source: AWEA project database

In addition to nameplate capacity ratings, average hub heights and rotor diameters have also
scaled with time. The average hub height of wind turbines installed in the United States in 2011
was 81 meters (Figure 16), up from 79.8 meters in 2010 and 78.9 meters in 2009. Since 199899, the average turbine hub height has increased by 45% (or 25.3 meters), though growth has
slowed in the more recent years. At the upper extreme, 128 turbines installed in 2011 (totaling
239 MW) had hub heights of 100 meters, up from 17 turbines (38.5 MW) in 2010. Not
surprisingly, most of these taller towers have been installed in areas with less-energetic windregimes, such as the East and Great Lakes regions (see Figure 30, later, for regional definitions).
Average rotor diameters have increased at a more rapid pace, especially in the last two years: theaverage rotor diameter of wind turbines installed in the United States in 2011 was 89 meters(Figure 16), up from 84.3 meters in 2010 and 81.6 meters in 2009. Since 1998-99, the average
rotor diameter has increased by 86% (or 41.2 meters). At the upper extreme, 810 turbines
installed in 2011 (totaling 1,803 MW) featured rotor diameters of 100 meters or larger, up from222 turbines (512 MW) in 2010.
These trends in hub height and rotor scaling are one of several factors impacting the project-level
capacity factors highlighted later in this report. Moreover, industry expectations as well as new
turbine announcements (especially to serve lower-wind-speed sites) suggest that significant
further scaling, especially in average rotor diameter, is anticipated in the near term.

30

A number of pre-existing GE 1.5 MW turbines installed in earlier years have been upgraded to 1.6 MW, but dataon how many or which turbines have been upgraded are not publicly available, and so this change in nameplate
capacity is not reflected in the data presented in this report.

25
2011 Wind Technologies Market ReportAverage Rotor Diameter and Hub Height (m)

90
80
70
60
50

Rotor Diameter40

Hub Height

30
20
10

0
COD: 1998-99
Turbines: 1,403
MW: 1,001

2000-01
1,974
1,751

2002-03
1,683
2,074

2004-05
1,918
2,734

2006
1,477
2,402

2007
3,190
5,249

2008
5,004
8,349

2009
5,733
9,993

2010
2,901
5,208

2011
3,464
6,816

Source: Berkeley Lab

Figure 16. Average Rotor Diameter and Hub Height Installed During Period

Apart from (but related to) turbine size, turbine configuration is also changing somewhat. In
particular, there were 17 direct drive (as opposed to geared) turbines installed in the U.S. in 2011
(totaling 35.3 MW), up from no more than three (totaling no more than 4.5 MW) in any of theprevious three years. 31 Five turbine manufacturers supplied direct drive units in 2011, up from
two in previous years, with the new entrant Siemens accounting for the largest share (7 turbines
totaling 21 MW). 32 The number of direct drive turbines installed in the U.S. is expected to growfurther in 2012, as Goldwind has acquired a number of projects (totaling more than 100 MW) toshowcase its 1.5 MW (and 2.5 MW) direct drive turbine, while Siemens will install more than
200 MW of its 3 MW direct drive units at the Bison II and III projects in North Dakota alone.

Project Finance Was a Mixed Bag in 2011, as Debt Terms Deteriorated
While Tax Equity Held Steady
After steady improvement in both the debt and tax equity markets throughout 2010, progress
faltered somewhat in 2011 on the debt side, as the latest Greek/European debt crisis drove a newround of retrenchment.
AWEA (2012a) reports that roughly 4,000 MW of new wind capacity raised $5.9 billion in debt
in 2011 – down 30% from the $8.4 billion of debt raised by nearly 5,600 MW in 2010. Though31

Direct drive technology has been relatively slow to enter the U.S. market – e.g., BTM (2012) reports that as muchas 21% of global wind installations in 2011 featured direct drive turbines – in part because Enercon, a German
leader in direct drive technology, has not entered the U.S. market, while Chinese sales of direct-drive turbines into
the U.S. has been limited.
32
Other manufacturers supplying direct drive turbines to the U.S. in 2011 include Vensys (4 x 1.5 MW), Goldwind(3 x 1.5 MW), Northern Power Systems (1 x 2.3 MW), and Unison (2 x 750 kW).

26
2011 Wind Technologies Market ReportAWEA attributes this decline to several rather innocuous factors, 33 it is also the case that debt
terms – and in particular bank loan tenors – deteriorated in the latter part of 2011, in response to
the unfolding Greek drama and some of the new banking regulations taking hold (e.g., Basel III).
Though 2010 was characterized by a steady lengthening of loan tenors throughout the year –with 7- to 10-year “mini-perms” stretching to longer maturities (e.g., 10-12 years) and eventuallyeven to 15- to 18-year fully amortizing deals – by the end of 2011, 10- to 12-year mini-perms
were once again the norm (AWEA 2012d). 34 In addition, a number of European banks – which
historically have been familiar lenders to U.S. wind projects – dropped out of the market in
response to the financial turmoil emanating from Greece. As a result, bank loan pricing
ratcheted up a bit, with spreads over the London Interbank Offered Rate (LIBOR) reportedly
starting at around 275 basis points (+/- 50 basis points depending on the particulars of the deal)
with a 25 basis point step-up every 3-4 years (AWEA 2012d). With LIBOR trading at around
0.5%, however, and 10-year interest rate swaps priced at roughly 2.25% in 4Q11, all-in interest
rates starting below 6% were, and still are, achievable.
While banks have pulled back somewhat, institutional lenders (e.g., insurance companies)
continue to offer long-term products – e.g., as long as 20 years with full amortization, and also at
all-in interest rates of 6% or less. Some wind project developers have split up their debt
financing in response to this divergence – using banks for their shorter-term borrowing needs(e.g., construction and cash grant bridge financing) and institutional lenders (or even the bondmarket) for long-term permanent debt financing.
In contrast to the weakened debt market, the market for tax equity improved somewhat in 2011.
The total amount of tax equity committed to both wind and solar projects in 2011 increased to $6
billion (up 20% from $5 billion in 2010), but virtually all of this growth came from solar
investments – perhaps a harbinger of the growing competition for tax equity that the wind sector
will increasingly face – while wind investments held steady at around $3.5 billion (Eber 2012).
There were reportedly 19 wind tax equity deals done in 2011: 18 partnership flip structures (fivewith project-level debt) and one sale-leaseback (Chadbourne & Parke 2012). Tax equity pricing
has remained fairly stable since late 2009, with yields on “best-in-market” deals reportedly
hovering around 8% on an after-tax, unleveraged basis (Chadbourne & Parke 2012). The pool ofactive tax equity investors increased to as many as twenty-two in 2011 (up from around 16 in2010), but this swelling of the ranks was comprised mostly of returning investors who had
temporarily dropped out of the market, rather than of entirely new investors (Chadbourne &Parke 2012, Eber 2012). Moreover, one high-profile investor – Google – that had entered themarket in 2010 and made several tax equity investments in wind projects in 2010 and 2011 hasreportedly shifted its investment focus away from tax equity and towards private equity, where it
33

These factors include a growing preference for the PTC over the Section 1603 cash grant (PTC deals are mostly
financed with tax equity rather than debt), lower PPA prices (which cannot support as much leverage), and two verylarge debt-financed projects (including the 845 MW Shepherds Flat project, which closed on a partial DOE
guarantee of $1.3 billion in debt in December 2010) that happened to fall in 2010 rather than 2011 (AWEA 2012a).
34
A “mini-perm” is a relatively short-term (e.g., 7-10 years) loan that is sized based on a much longer tenor (e.g.,
15-17 years), and therefore requires a balloon payment of the outstanding loan balance upon maturity. In practice,
this balloon payment is often paid from the proceeds of refinancing the loan at that time. Thus, a 10-year mini-perm
might provide the same amount of leverage as a 17-year fully amortizing loan, but with refinancing risk at the end of
10 years. In contrast, a 17-year fully amortizing loan would be repaid entirely through periodic principal andinterest payments over the full tenor of the loan (i.e., no balloon payment required, and no refinancing risk).

27
2011 Wind Technologies Market Reportcan earn higher returns and also feel more like a sponsor than a passive investor (Eber 2012). As
the number of grandfathered Section 1603 grant deals begins to taper off, further attrition of tax
equity investors is possible, as some have indicated that they are not interested in deals thatinvolve the PTC.
Looking ahead to the remainder of 2012, the looming end-of-year expiration of both the PTC andthe Section 1603 cash grant (for those wind projects that met the end-of-2011 construction start
deadline) dominate the picture. As developers rush to complete projects in advance of thesepolicy deadlines, the competition for financing will likely increase, as will the cost of capital.
Demand for tax equity could increase disproportionately (relative to debt) as projects
increasingly choose the PTC over the Section 1603 cash grant. 35 Meanwhile, the ongoing
implementation of more stringent capital adequacy and leverage requirements under the Basel III
Accord likely means that shorter bank loan tenors are here to stay – this could have a particularly
detrimental impact on wind project finance beyond 2012 if the PTC is ultimately not extended or
renewed, which would then make term debt financing more the norm.

IPPs Remain the Dominant Owners of Wind Projects, But Utility Ownership
Increased Significantly in 2011, Largely On the Back of One Utility
Independent power producers (IPPs) continued to dominate the ownership of wind power
projects, owning 73% (4,965 MW) of all new capacity additions in 2011 (Figure 17). On theback of nearly 600 MW of new capacity built by MidAmerican Energy, however, utility
ownership jumped to nearly 25% – up from roughly 15% in the two previous years – withinvestor-owned utilities (IOUs) owning 1,492 MW and publicly owned utilities (POUs) owning
another 204 MW. The remaining 2% (155 MW) of new 2011 wind capacity is owned by “other”
entities that are neither IPPs nor utilities (e.g., towns, schools, commercial customers, farmers). 36
Of the cumulative installed wind power capacity at the end of 2011, IPPs owned 82% (38,407
MW) and utilities owned 17% (6,357 MW for IOUs and 1,424 MW for POUs), with theremaining 2% (904 MW) falling into the “other” category.

35

Some 2012 projects might not have met the end-of-2011 construction start milestone for the grant, and so have no
choice but to take the PTC. More likely, though, most wind projects will willingly choose the PTC because recent
trends in installed project costs and capacity factors have made the PTC more valuable than the grant, at least interms of face value. This is likely why AWEA (2012a) finds that 56% of tax equity raised in 2011 went to PTC
deals, compared to just 22% in 2010. This preference for the PTC could further exacerbate any shortage of tax
equity in 2012, as some tax equity investors are only interested in cash grant deals.
36
Most of these “other” projects, along with some IPP- and POU-owned projects, might also be considered“community wind” projects that are owned by or benefit one or more members of the local community to a greater
extent than typically occurs with a commercial wind project. One example of a 2011 project that is classified in
Figure 17 as IPP-owned, yet might also be considered a community wind project, is the 40.5 MW Petersburg projectin Nebraska – a C-BED (Community-Based Energy Development) project that is owned by Gestamp (a Spanish
IPP). According to AWEA (2012a), 6.7% of 2011 capacity additions qualified as community wind projects.

282011 Wind Technologies Market Report

100%

90%

90%

80%

80%

70%

70%

60%

60%

50%

50%

% of Cumulative Installed Capacity

100%

40%
30%

2011 Capacity by
Owner Type

IPP: 4,965 MW
(73%)

40%

Other
Publicly Owned Utility (POU)

30%

20%

Investor-Owned Utility (IOU)

20%

10%

Independent Power Producer (IPP)

10%

0%
0%
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

IOU:
1,492 MW
(22%)
POU:
204 MW (3%)

Other:
155 MW (2%)

Source: Berkeley Lab estimates based on AWEA project database

Figure 17. Cumulative and 2011 Wind Power Capacity Categorized by Owner TypeThe dominance of IPP ownership, and the trend towards increasing utility ownership since themid 2000s, has been driven by several factors. When wind energy was a small part of thegeneration mix, some utilities felt that buying wind power from IPPs was less risky than owning
wind power projects themselves. As utilities have gained comfort with wind power over theyears, however, their interest in ownership has increased for several reasons: IOUs are typicallyallowed to earn a regulated return on project ownership (i.e., by adding it to their rate base) but
not on power purchases; some credit rating agencies consider long-term power purchaseagreements to be debt-like instruments, thereby potentially negatively impacting a utility's credit
rating; and ownership places the utility in a position of greater control over project development,
operations, and eventually repowering. More recently, as the tax equity market dried up in thewake of the financial crisis of 2008/2009, IOUs were left as one of the few natural wind project
investors with a steady and sizable tax liability 37 – some of the utility-owned wind projects built
in 2011 were conceived at that time. With most of these drivers still in place, utility ownershipmay continue to increase in the coming years.

Long-Term Contracted Sales to Utilities Remained the Most Common OffTake Arrangement, but Scarcity of Power Purchase Agreements andLooming PTC Expiration Drove Continued Merchant Development
Electric utilities continued to be the dominant off-takers of wind power in 2011 (Figure 18),
either owning (25%) or buying (51%) power from 76% of the new capacity installed last year(with the 76% split between 63% IOU and 13% POU). On a cumulative basis, utilities own

37

Earlier, in 2005, the internal revenue service (IRS) clarified that a utility’s customers are “unrelated” for the
purposes of satisfying the requirement in Section 45 of the tax code that power must be sold to an unrelated party inorder to qualify for the PTC. As such, utilities that own wind projects and sell the wind generation to theirratepayers (rather than on the wholesale power market) are entitled to claim the PTC on that wind generation.

29
2011 Wind Technologies Market Report(17%) or buy (50%) power from 66% of all wind power capacity installed in the United States(with the 66% split between 46% IOU and 20% POU), a slight increase over the past two years.
100%

90%

90%

80%

80%

70%

70%

60%

60%

50%

50%

% of Cumulative Installed Capacity

100%

40%
30%
20%
10%

40%

On-SiteMerchant/Quasi-MerchantPower Marketer

30%

2011 Capacity by
Off-Take Category

IOU:
4,302 MW
(63%)

Merchant:
1,434 MW
(21%)

20%

POU

POU:
899 MW
(13%)

10%

IOU

0%
0%
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

On-Site:35 MW (0.5%)

Marketer:
147 MW (2%)

Source: Berkeley Lab estimates based on AWEA project database

Figure 18. Cumulative and 2011 Wind Power Capacity Categorized by Power Off-Take
Arrangement

The role of power marketers – defined here as corporate intermediaries that purchase power
under contract and then re-sell that power to others, sometimes taking some merchant risk 38 – inthe wind power market has waned somewhat in recent years. In 2011, power marketerspurchased the output of just 2% of the new wind power capacity, with 10% of the cumulative
wind power capacity being sold to these entities.
Merchant/quasi-merchant projects were less prevalent in 2011 than they have been in recent
years, accounting for 21% of all new capacity (compared to 23% in 2010 and 36%-38% in 2009
and 2008) and 24% of cumulative capacity. Merchant/quasi-merchant projects are those whose
electricity sales revenue is tied to short-term contracted and/or wholesale spot electricity market
prices (with the resulting price risk commonly hedged over a 5- to 10-year period 39) rather thanbeing locked in through a long-term PPA. With PPAs in relatively short supply compared towind developer interest, wholesale power prices at low levels, and a scheduled PTC expiration
looming, it is likely that many of the merchant/quasi-merchant projects built in 2011 aremerchant by necessity rather than by desire. In other words, in the absence of a PPA, building a
38

Power marketers are defined here to include not only traditional marketers such as PPM Energy (now part of
Iberdrola), but also the wholesale power marketing affiliates of large investor-owned utilities (e.g., PPL Energy Plusor FirstEnergy Solutions), which may buy wind power on behalf of their load-serving affiliates. Direct sales to end
users (e.g., the University of Maryland buys wind power from both the Pinnacle project in West Virginia and theRoth Rock project in Maryland) are also included in this category, because in these few limited cases the end-user iseffectively acting as a power marketer.
39
Hedges are often structured as a “fixed-for-floating” power price swap – a purely financial arrangement whereby
the wind power project swaps the “floating” revenue stream that it earns from spot power sales for a “fixed” revenue
stream based on an agreed-upon strike price. For some projects (especially where natural gas is virtually always themarginal supply unit), the hedge is structured in the natural gas market rather than the power market, in order to takeadvantage of the greater liquidity and longer terms available in the forward gas market.

30
2011 Wind Technologies Market Reportproject on a merchant basis may, in some cases, simply have been the most expedient way toensure the deployment of committed turbines (perhaps ordered several years ago underframework agreements) in advance of the scheduled expiration of important federal incentives
like the Section 1603 Treasury cash grant and the PTC. Given relatively low wholesale power
prices, and despite improvements in the cost, performance, and price of wind energy, some ofthese projects are likely still seeking long-term PPAs, and may therefore not remain merchant for
long.
Finally, roughly 35 MW of the wind power additions in 2011 that used turbines over 100 kW insize were interconnected on the customer side of the utility meter, with the power being
consumed on site rather than sold.

31
2011 Wind Technologies Market Report

4. Cost Trends
This section presents empirical data on both the upfront and operating costs of wind projects in
the United States. It begins with a review of wind turbine prices, followed by total installed
project costs, and then finally operation and maintenance (O&M) costs. Later sections present
data on wind project performance, and then the price at which wind energy is being sold.

With Increased Competition among Manufacturers, Wind Turbine Prices
Continued to Decline in 2011
Wind turbine prices have dropped substantially in recent years, despite continued technologicaladvancements that have yielded increases in hub heights and especially rotor diameters.
Berkeley Lab has gathered price data for 96 U.S. wind turbine transactions totaling 26,600 MW
announced from 1997 through 2011, including 12 transactions summing to 2,630 MW
announced in 2011. Sources of turbine price data vary, but many derive from press releases andnews reports. Wind turbine transactions differ in the services included (e.g., whether towers andinstallation are provided, the length of the service agreement, etc.), turbine characteristics (andtherefore performance), and on the timing of future turbine delivery, driving some of theobserved intra-year variability in transaction prices. Nonetheless, most of the transactions
included in the Berkeley Lab dataset likely include turbines, towers, delivery, and limited
warranty and service agreements. 40 Unfortunately, collecting data on wind turbine transaction
prices is a challenge – e.g., the sample of turbine transactions announced in 2011 for which pricedata were identified represents just 30% of the 8,750 MW of new turbine orders reported by
AWEA (2012a). In part as a result, Figure 19 – which depicts these wind turbine transaction
prices – also presents a range of 2012 wind turbine price quotes, as reported by Bloomberg NEF(2012a).
After hitting a low of roughly $700/kW from 2000 to 2002, average wind turbine prices
increased by approximately $800/kW (>100%) through 2008, rising to an average of more than
$1,500/kW. The increase in turbine prices over this period was caused by several factors,
including: a decline in the value of the U.S. dollar relative to the Euro; increased materials,
energy and labor input prices; a general increase in turbine manufacturer profitability due in partto strong demand growth and turbine and component supply shortages; increased costs forturbine warranty provisions; and an up-scaling of turbine size, including hub height and rotor
diameter (Bolinger and Wiser 2011).

40

Because of data limitations, the precise content of many of the individual transactions is not known.

32
2011 Wind Technologies Market ReportOrders <5 MW
Orders from 5 - 100 MW
Orders >100 MW

Jan-12

Jan-11

Jan-10

Jan-09

Jan-08Jan-07

Jan-06

Jan-05Jan-04Jan-03Jan-02Jan-01

Jan-00Jan-99Jan-98

Recentreported
turbineprice
quotesJan-97

Turbine Transaction Price (2011$/kW)

2,200
2,000
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0

Announcement Date
Source: Berkeley Lab

Figure 19. Reported U.S. Wind Turbine Transaction Prices over Time

Since 2008, wind turbine prices have declined substantially, reflecting a reversal of some of thepreviously mentioned underlying trends that had earlier pushed prices higher, as well as
increased competition among manufacturers and a shift to a buyer’s market (Bloomberg NEF
2012b). As shown in Figure 19, a number of turbine transactions announced in 2011 had pricing
in the $1,150-$1,350/kW range, while typical turbine prices in the U.S. in the first half of 2012were reported by Bloomberg NEF (2012a) to be in the range of $900-$1,270/kW depending on
the technology. These figures suggest price declines of as much as 33% or more since late 2008,
with an average decline closer to perhaps 20% for orders announced in 2011. Moreover, thesedeclines have been coupled with: (1) improved turbine technology (e.g., witness the recent andcontinued growth in average hub heights and rotor diameters shown earlier in Figure 16), and (2)more-favorable terms for turbine purchasers (e.g., reduced turbine delivery lead times and lessneed for large frame-agreement orders, longer initial operations and maintenance (O&M)
contract durations, improved warranty terms, and more-stringent performance guarantees).
These price reductions and improved terms would be expected, over time, to exert downward
pressure on total project costs and wind power prices, whereas increased rotor diameters and hub
heights would be expected to improve capacity factors and further reduce wind power prices.

Though Slow to Reflect Declining Wind Turbine Prices, Reported Installed
Project Costs Finally Turned the Corner in 2011
Berkeley Lab compiles data on the installed cost of wind power projects in the United States,
including data on 90 projects completed in 2011 totaling 6,402 MW, or 94% of the wind power
capacity installed in that year. In aggregate, the dataset (through 2011) includes 564 completed
wind power projects in the continental United States totaling 40,022 MW, and equaling roughly
85% of all wind power capacity installed in the United States at the end of 2011. Also reported
33
2011 Wind Technologies Market Reporthere are data on a small sample of projects already installed or soon to be installed in 2012 (20projects totaling 2,592 MW). In general, reported project costs reflect turbine purchase andinstallation, balance of plant, and any substation and/or interconnection expenses. Data sources
are diverse, however, and are not all of equal credibility, so emphasis should be placed on overall
trends in the data, rather than on individual project-level estimates.

Installed Project Cost (2011 $/kW)

As shown in Figure 20, the average installed costs of wind power projects declined dramaticallyfrom the beginning of the U.S. wind industry in California in the 1980s through the early 2000s,
before following turbine prices higher through the latter part of the last decade. Whereas turbine
prices peaked in 2008/2009, however, installed costs only started to turn the corner in 2011,
suggesting 2009/2010 as a likely peak. That average installed project costs would lag averageturbine prices is not surprising, and reflects the normal passage of time between when a turbine
supply agreement is signed (the time stamp for Figure 19) and when those turbines are actually
installed and commissioned (the time stamp for Figure 20). 41
5,000
4,500

Individual Project Cost (584 projects totaling 42,614 MW)
Capacity-Weighted Average Project Cost

4,000
3,500
3,000
2,500
2,000
1,500
1,000
500

1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012

0

Note: 2012 data represent preliminary cost estimates for a sample of 20 projects totaling 2.6 GW that have either already been or
will be built in 2012, and for which substantive cost estimates were available.
Source: Berkeley Lab (some data points suppressed to protect confidentiality)

Figure 20. Installed Wind Power Project Costs over Time (including preliminary sample
of 2012 project costs)

In 2011, the capacity-weighted average installed project cost stood at nearly $2,100/kW, down
almost $100/kW from the reported average cost in both 2009 and 2010. Moreover, a preliminary
estimate of the average installed cost among a relatively small sample of 20 projects totaling 2.6

41

On the other hand, since 2009, Figure 20 partly reflects installed cost estimates derived from publicly available
data from the Section 1603 cash grant program. In some cases (though exactly which is unknown), the Section 1603
grant data likely reflect the fair market value rather than the installed cost of wind power projects; in such cases theinstalled cost estimates shown in Figure 20 will be artificially inflated.

34
2011 Wind Technologies Market ReportGW of capacity that either have been or will be built in 2012 suggests that average installed costs
may decline further in 2012, continuing to follow lower turbine prices. 42

Installed Costs Differ By Project Size, Turbine Size, and Region
Average installed wind power project costs exhibit weak economies of scale, at least at the low
end of the project size range. Figure 21 shows that – among the sample of projects installedfrom 2009 through 2011 – there is a steady drop in per-kW average installed costs when movingfrom projects of 5 MW or less to projects in the 20-50 MW range. As project size increases
beyond 50 MW, however, these data do not show strong evidence of continued economies ofscale.

Installed Project Cost (2011 $/kW)

5,000
4,500

Capacity-Weighted Average Project Cost

4,000

Individual Project Cost

3,500
3,000
2,500
2,000
1,500
1,000
500
0

Sample includes projects built from 2009-2011≤5 MW

5-20 MW

20-50 MW50-100 MW

100-200 MW>200 MW

100 MW

430 MW

1,404 MW4,372 MW

9,605 MW5,284 MW52 projects

34 projects

39 projects

56 projects

72 projects

22 projects

Source: Berkeley Lab

Figure 21. Installed Wind Power Project Costs by Project Size: 2009-2011 Projects

Another way to look for economies of scale is by turbine size (rather than by project size), on thetheory that a given amount of wind power capacity may be built less expensively using fewer
larger turbines as opposed to a larger number of smaller turbines. Figure 22 explores thisrelationship, breaking down turbine size into 0.75 MW bins. Here too some economies of scale
are evident as turbine size increases, at least at the lower end of the turbine size range. 43
42

Learning curves have been used extensively to understand past cost trends and to forecast future cost reductions
for a variety of energy technologies, including wind energy. Learning curves start with the premise that increases in
the cumulative production or installation of a given technology leads to a reduction in its costs. The principal
parameter calculated by learning curve studies is the learning rate: for every doubling of cumulative
production/installation, the learning rate specifies the associated percentage reduction in costs. Based on the
installed cost data presented in Figure 20 and global cumulative wind power installations, learning rates can becalculated as follows: 7.5% (using data from 1982 through 2011) or 14.4% (using data only during the period of
cost reduction, 1982-2004).
43
It should be noted that there is likely some correlation between turbine size and project size, at least at the low endof the range of each. In other words, projects of 5 MW or less are more likely than larger projects to use individual

35
2011 Wind Technologies Market Report5,000Capacity-Weighted Average Project Cost

Installed Project Cost (2011 $/kW)

4,500

Individual Project Cost

4,000
3,500
3,000
2,500
2,000
1,500
1,000

Sample includes projects built from 2009-2011

500
0>0.1 & <1 MW≥1 & <1.75 MW≥1.75 & <2.5 MW≥2.5 & <3.25 MW

20 MW

9,448 MW

9,637 MW2,090 MW

15 projects

142 projects

92 projects

26 projects

Source: Berkeley Lab

Figure 22. Installed Wind Power Project Costs by Turbine Size: 2009-2011 Projects

Regional differences in average project costs are also apparent, and may occur due to variations
in development costs, transportation costs, siting and permitting requirements and timeframes,
and other balance-of-plant and construction expenditures. Considering only projects in thesample that were installed from 2009 through 2011, Figure 23 shows that the capacity-weighted
average cost equaled $2,160/kW nationwide over this period. Texas was the lowest-cost region,
while California and New England were the highest-cost regions; all other regions came in close
to the nationwide average (see Figure 30, later, for regional definitions). 44

turbines of less than 1 MW. As such, Figures 21 and 22 – both of which show scale economies at small project or
turbine sizes, but diminishing as project or turbine size increases – could both be reflecting the same influence,
making it difficult to tease out the unique influences of turbine size from project size.
44
Permitting and regulatory compliance costs presumably play a role at both ends of the spectrum: Texas is reputed
to be one of the easiest locations in which to develop and build a wind power project, while California and New
England are two of the hardest. Graphical presentation of the data in this way, however, should be viewed withsome caution, as numerous other factors also influence project costs, and those are not controlled for in Figure 23.

362011 Wind Technologies Market ReportInstalled Project Cost (2011 $/kW)

5,000

Capacity-Weighted Average Project Cost

4,500

Individual Project Cost

4,000

Capacity-Weighted Average Cost, Total U.S.

3,500
3,000
2,500
2,000
1,500
1,000
Sample includes projects built from 2009-2011

500
0

Texas

Heartland

Great Lakes

MountainNorthwest

East

California

New England

30 projects

81 projects

34 projects

20 projects

48 projects

20 projects

19 projects

23 projects

3,256 MW5,902 MW3,328 MW

2,091 MW3,308 MW

1,383 MW

1,502 MW423 MW

Source: Berkeley Lab

Figure 23. Installed Wind Power Project Costs by Region: 2009-2011 Projects

Newer Projects Appear to Show Improvements in Operations andMaintenance Costs
Operations and maintenance (O&M) costs are a significant component of the overall cost ofwind energy, but can vary substantially among projects, and market data on actual project-level
O&M costs are not readily available. Even where data are available, care must be taken in
extrapolating historical O&M costs given the dramatic changes in wind turbine technology thathave occurred over the last two decades, not least of which has been the up-scaling of turbine
size (see Figures 15 and 16, earlier). Anecdotal evidence suggests that O&M costs andpremature component failures continue to be key challenges for the wind power industry.
Berkeley Lab has compiled O&M cost data for 133 installed wind power projects in the UnitedStates, totaling 7,965 MW of capacity, with commercial operation dates of 1982 through 2010.
These data cover facilities owned by both independent power producers and utilities, though data
since 2004 are exclusively from utility-owned projects. A full time series of O&M cost data, byyear, is available for only a small number of projects; in all other cases, O&M cost data are
available for just a subset of years of project operations. Although the data sources do not all
clearly define what items are included in O&M costs, in most cases the reported values include
the costs of wages and materials associated with operating and maintaining the facility, as well as
rent. 45 Other ongoing expenses, including general and administrative expenses, taxes, property
insurance, depreciation, and workers’ compensation insurance, are generally not included. As
such, the following figures are not representative of total operating expenses for wind power
projects; the final paragraph in this section cites data from the financial reports of two public
45

The vast majority of the recent data derive from FERC Form 1, which uses Uniform System of Accounts
definitions.

37
2011 Wind Technologies Market Reportcompanies with U.S wind assets suggesting higher total operating expenses. Given the scarcity,
limited content, and varying quality of the data, the results that follow therefore may not fully
depict the industry’s challenges with O&M issues and expenditures; instead, these results should
only be taken as illustrative of overall trends. Note finally that the available data are presented in$/MWh terms, as if O&M represents a variable cost; in fact, O&M costs are in part variable andin part fixed. Although not presented here, expressing O&M costs in units of $/kW-year yields
qualitatively similar results to those presented in this section.
Figure 24 shows project-level O&M costs according to the commercial operation date. 46 Here,each project’s O&M costs are depicted in terms of its average annual O&M costs from 2000
through 2011, based on however many years of data are available for that time period. For
example, for projects that reached commercial operations in 2010, only year 2011 data are
available, and that is what is shown in the figure. 47 Many other projects only have data for asubset of years during the 2000-11 timeframe, either because they were installed after 2000 or
because a full time series is not available, so each data point in the chart may represent a
different averaging period over 2000-11. The chart highlights the 47 projects, totaling 4,339
MW, for which 2011 O&M cost data were available; those projects have either been updated or
added to the chart since the previous edition of this report.
Projects with no 2011 O&M data

60

Projects with 2011 O&M data
Polynomial Trend Line (all projects)

50
40
30
20

2010

2009

2008

2007

2006

2005

2004

2003

2002

2001

2000

1999

1998

1997

1996

1995

1994

1993

1992

1991

1990

1989

1988

1987

1986

1985

1984

0

1983

10

1982

Average Annual O&M Cost 2000-2011(2011 $/MWh)70

Commercial Operation Date
Source: Berkeley Lab; seven data points suppressed to protect confidentiality

Figure 24. Average O&M Costs for Available Data Years from 2000-2011, by Commercial
Operation Date

The data exhibit considerable spread, demonstrating that O&M costs are far from uniform acrossprojects. However, Figure 24 suggests that projects installed more recently have, on average,
incurred lower O&M costs. Specifically, capacity-weighted average 2000-11 O&M costs for the46

For projects installed in multiple phases, the commercial operation date of the largest phase is used; for repowered projects, the date at which re-powering was completed is used.
47
Projects installed in 2011 are not shown because only data from the first full year of project operations (andafterwards) are used, which in the case of projects installed in 2011 would be year 2012 (for which data are not yet
available).

38
2011 Wind Technologies Market Report

24 projects in the sample constructed in the 1980s equal $33/MWh, dropping to $23/MWh forthe 37 projects installed in the 1990s, and to $10/MWh for the 69 projects installed since 2000. 48
This drop in O&M costs may be due to a combination of at least two factors: (1) O&M costs
generally increase as turbines age, component failures become more common, and manufacturer
warranties expire 49; and (2) projects installed more recently, with larger turbines and moresophisticated designs, may experience lower overall O&M costs on a per-MWh basis.
Limitations in the underlying data, however, do not permit the influence of these two factors to
be unambiguously distinguished.
To help illustrate the possible influence of these two factors, however, Figure 25 shows medianannual O&M costs over time, based on project age (i.e., the number of years since thecommercial operation date), and segmented into two project-vintage groupings. Data for
projects under 5 MW in size are excluded, to help control for the confounding influence ofeconomies of scale. Note that, at each project age increment and for each of the two projectvintage groups, the number of projects used to compute median annual O&M costs is limited andvaries substantially (from 3 to 31 data points per project-year for projects installed from 1998
through 2004 and from 2 to 36 data points per project-year for projects installed from 2005
through 2010). With this limitation in mind, the figure shows that projects installed more
recently (2005-2010) have had, in general, lower O&M costs than those installed in earlier years(1998-2004), at least for the first six years of operation. In addition, projects show an upward
trend in project-level O&M costs as they age, though the sample size after year four is limited.

25

Commercial Operation Date:
1998-2004
2005-2010

20
15

1

2

3

4

5

6

7

8

n=3

n=3

n=3

n=3

n=2

n=5

n=6

n=8

n=11

n=20

n=25

n=23

n=34

0

n=36

5

n=31

10

n=18

Median Annual O&M Cost
(2011 $/MWh)

30

9

10

Project Age (Number of Years Since Commercial Operation Date)
Source: Berkeley Lab; medians shown only for groups of two or more projects, and only projects >5 MW are included

Figure 25. Median Annual O&M Costs by Project Age and Commercial Operation Date48

If expressed instead in terms of $/kW-yr, capacity-weighted average 2000-2011 O&M costs were $65/kW-yr for
projects in the sample constructed in the 1980s, dropping to $54/kW-yr for projects constructed in the 1990s, and to$28/kW-yr for projects constructed since 2000. Somewhat consistent with these observed O&M costs, Bloomberg
New Energy Finance (2011) reports the cost of 5-year full-service O&M contracts at $30-$48/kW-yr.
49
Many of the projects installed more-recently may still be within their turbine manufacturer warranty period.

39
2011 Wind Technologies Market ReportAs indicated previously, the data presented in Figures 24 and 25 are derived from a variety ofsources, and in most cases include only a subset of total operating expenses. In comparison, thefinancial statements of public companies with sizable U.S. wind project assets indicate markedly
higher total operating costs. Specifically, two companies – Infigen and EDP Renováveis(EDPR), which together represent approximately 4,511 MW of installed capacity, nearly all ofwhich has been installed since 2000 – report total operating expenses of $21.5/MWh and$22.1/MWh, respectively, for their U.S. wind project portfolios in 2011 (EDPR 2012; Infigen
2011, 2012). These operating expenses are more than twice the $10/MWh reported above, forthe 69 projects in the Berkeley Lab data sample installed since 2000. These differences arelikely due, in large measure, to the scope of expenses included, as the company financial reports
include items such as general and administrative expenses, local taxes, property insurance, andworkers’ compensation insurance, which are generally not included within the data comprising
the Berkeley Lab sample.

40
2011 Wind Technologies Market Report5. Performance Trends
This section presents data from a Berkeley Lab compilation of project-level capacity factors.
The full data sample consists of 397 wind power projects built between 1983 and 2010, andtotaling 37,606 MW (94% of nationwide installed wind power capacity at the end of 2010). 50
The followed discussion of performance trends is broken up into three sub-sections: the first
analyzes trends in sample-wide capacity factor over time; the second looks at variations incapacity factor by project vintage; and the third focuses on regional variations in capacity factor.

Sample-Wide Wind Project Capacity Factors Have Generally Improved OverTime
Focusing on a progressively larger cumulative sample of projects in each calendar year, 51 theblue bars in Figure 26 demonstrate that average sample-wide wind power project capacity factors
have, in general, gradually increased over time, from 25% in 1999 (for projects installed through1998) to a high of nearly 34% in 2008 (for projects installed through 2007). In 2009 and 2010,
however, sample-wide capacity factors dropped to around 30%, before 2011 brought a
resurgence back to 33% (for projects installed through 2010).
35%30%

Capacity Factor

25%
20%
Based on Estimated Generation (if no curtailment in subset of regions)15%

Based on Actual Generation (with curtailment)
10%

4-Year Moving Average (based on estimated generation)

5%0%
Year: 1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

5

12

41

84

97

119

143

168

210

254

354

466

397

MW: 544

1,000

1,531

3,271

3,811

5,211

5,880

8,712

10,695

15,67024,36834,21337,606

Projects:

Source: Berkeley Lab

Figure 26. Average Cumulative Sample-Wide Capacity Factor by Calendar Year50

Though some performance data for wind power projects installed in 2011 are available, those data do not span an
entire year of operations. As such, for the purpose of this section, the focus is on projects with commercial
operation dates in 2010 and earlier.
51
There are fewer individual projects – though more capacity – in the cumulative sample for 2011 than there are for2010. This is due to the sampling method used by the EIA, which focuses on a subset of larger projects throughout
the year, before eventually capturing the entire sample some months after the year has ended. As a result, it might
be late 2012 before the EIA reports 2011 performance data for all of the wind power projects that it tracks, and in
the mean time, this report is left with a smaller sample consisting mostly of the larger projects in each state.

41
2011 Wind Technologies Market Report

The relatively steady improvement in average sample-wide capacity factors through 2008 can be
attributed largely to the substantial increase in average hub height and rotor diameter(particularly in relation to rated capacity) shown earlier in Figure 16. The drop in 2009 and2010, however, followed by a rebound in 2011, warrants further investigation. At least two
factors likely played a role in this more recent volatility in average project performance: annual
wind resource variation and wind power curtailment.
Annual Wind Resource Variation: The strength of the wind resource varies from year to year,
in part in response to significant persistent weather patterns such as El Niño/La Niña. In 2011,
the U.S. reportedly enjoyed above-average wind speeds throughout much of the nation, and inparticular across much of the country’s interior – where most installed wind power capacity
resides (AWS Truepower 2012, 3TIER 2012). An above-normal 2011 follows what wereconsidered to be lackluster wind years in 2010 and 2009, preceded by a strong wind year in2008. This same pattern is evident in the average sample-wide capacity factors shown in Figure26, highlighting the influence of natural yearly variations in average wind resource conditions on
sample-wide average wind power capacity factors.
Wind Power Curtailment: Curtailment of wind project output due to transmission inadequacy
and/or minimum generation limits (and, as a consequence, low or negative wholesale electricity
prices) has become common, principally in Texas, but also to a lesser degree in other markets.
For example, Table 5 (which focuses on forced, rather than economic, curtailment) shows that
8.5% of potential wind energy generation within ERCOT was curtailed in 2011 – up slightly
from 7.7% in 2010, but down sharply from 17% in 2009. 52 Outside of Texas, forced curtailment
increased significantly on the Bonneville Power Administration’s (BPA) system in 2011, due tounusually heavy spring runoff that resulted in above-normal hydropower generation. 53 In
aggregate, assuming a 33% average capacity factor, the total amount of wind generation
curtailed in 2011 within just the six utility/ISO/RTO service territories shown in Table 5 equates
to the annual output of roughly 1,220 MW of wind power capacity.
Looked at another way, wind power curtailment has reduced sample-wide average capacity
factors in recent years, and particularly in 2009. While the blue bars in Figure 26 reflect actual
capacity factors – i.e., including the negative impact of curtailment events – the orange bars add
back in the estimated amount of wind generation that has been forced to curtail in recent years
within the six territories shown in Table 5, to estimate what the sample-wide capacity factors
would have been absent this forced curtailment. As shown, sample-wide capacity factors would
have been on the order of 1-2 percentage points higher nationwide from 2008 through 2011absent curtailment in just this subset of regions. Estimated capacity factors would have beeneven higher if comprehensive forced and economic curtailment data were available for all
regions.
52

The significant reduction in ERCOT curtailment since 2009 is, in part, attributable to a private 229-miletransmission line built by NextEra Energy in late 2009 to move power from its 735.5 MW Horse Hollow project outof the congested West zone and into the uncongested South zone. As a result, Horse Hollow’s capacity factor
increased from just 20% in 2009 to 29% in both 2010 and 2011. Several transmission line upgrades related to the
Texas competitive renewable energy zone (CREZ) effort have also helped reduce curtailment in ERCOT (see later
section on transmission).
53
BPA again curtailed some wind generation for similar reasons in the spring of 2012, but the magnitude andduration was nowhere near that seen in 2011.

42
2011 Wind Technologies Market ReportTable 5. Estimated Wind Curtailment in Various Areas, in GWh(and as a % of potential wind generation)
2007
2008
2009
Electric Reliability Council of Texas
109
1,417
3,872
(ERCOT)(1.2%)(8.4%)(17.1%)Southwestern Public Service Company
0
0
N/A
(SPS)
(0.0%)(0.0%)
Public Service Company of Colorado
2.5
19.0
N/A
(PSCo)(0.1%)(0.6%)
Northern States Power Company
25.4
42.4
N/A
(NSP)
(0.8%)(1.2%)
Midwest Independent System Operator
250
N/A
N/A
(MISO), less NSP(2.2%)
Bonneville Power Administration
N/A
N/A
N/A
(BPA)
109
1,445
4,183
Total Across These Six Areas:(1.2%)(5.6%)(9.6%)

2010
2,067(7.7%)
0.9(0.0%)
81.5(2.2%)
42.6(1.2%)
781(4.4%)
4.6*(0.1%)
2,978(4.8%)

2011
2,622(8.5%)
0.5(0.0%)
63.9(1.4%)
54.4(1.2%)
657(3.0%)
128.7*(1.4%)
3,526(4.8%)*A portion of BPA’s curtailment is estimated assuming that each curtailment event lasts for half of the maximum possible hourfor each event.
Source: ERCOT, Xcel Energy, MISO, BPA

Some Stagnation in Wind Project Capacity Factor Improvement Is Evident
Among Projects Built from 2006 through 2010, Due in Part to a Build Out ofProjects in Progressively Weaker Wind Resource Areas
One way to control for the time-varying influences described in the previous section (e.g., annual
wind resource variations and a particularly bad curtailment year in 2009) is to focus exclusively
on capacity factors in 2011. 54 As such, whereas Figure 26 presents capacity factors in eachcalendar year, Figure 27 instead shows only capacity factors in 2011, broken out by projectvintage. In general, Figure 27 indicates that projects built more recently generated higher
capacity factors in 2011 – this is particularly true among those projects built up through 2005.
Average 2011 capacity factors for projects built from 2006 through 2010, however, were largely
stagnant, ranging from 33%-35% on a weighted-average basis (on the other hand, the maximum
capacity factor attained by any individual project in 2011 increased noticeably among thoseprojects built in 2009 and 2010).

54

Although focusing just on 2011 does control (at least loosely) for some of these known time-varying impacts, italso means that the absolute capacity factors shown in Figure 27 may not be representative over longer terms if 2011
was not a representative year in terms of the strength of the wind resource or wind power curtailment. As noted
earlier, 2011 was generally an above-average wind year in much of the U.S., suggesting that the capacity factors
shown in Figure 27 may be biased upwards to some degree due to this factor.

43
2011 Wind Technologies Market Report2011 Capacity Factor (by project vintage)

60%
Sample includes 397 projects totaling 37.6 GW
50%
40%
30%
20%
10%
0%

Capacity-Weighted Average (by project vintage)
Individual Project (by project vintage)
Pre-1998

1998-99

2000-01

2002-03

2004-05

2006

2007

2008

2009

2010

5 projects 24 projects 25 projects 38 projects 29 projects 22 projects 36 projects 72 projects 96 projects 50 projects
475 MW

777 MW

1,617 MW 2,061 MW 3,578 MW 1,755 MW 5,071 MW 8,008 MW 9,276 MW 4,989 MW

Source: Berkeley Lab

Figure 27. 2011 Project Capacity Factors by Commercial Operation Date

This pattern of improving performance by project vintage through 2005 followed by relative
stagnation for projects built from 2006-2010 is broadly consistent with trends over this same
period in both average hub height (shown earlier in Figure 16) and average swept rotor area
relative to turbine nameplate capacity – i.e., the inverse of “specific power” (shown below in
Figure 28). 55 Specifically, scaling in both hub height and the inverse of “specific power” wasmost pronounced among turbines installed from 1998 through 2006, which roughly coincides
with the vintages that show the largest increases in 2011 capacity factor in Figure 27. Since
2006, however, average hub height has increased by only a few meters (see Figure 16), which inpart explains the stagnation in average capacity factors among more recently built wind power
projects. Swept area relative to rated capacity also held steady from 2006 through 2009, before
increasing again in 2010 and 2011 – this recent increase is perhaps reflected in the higher
maximum capacity factors achieved by 2010 vintage projects in Figure 27. The fact that rotor
scaling (relative to nameplate capacity) continued for projects built in 2011 (and now 2012)suggests that further increases in capacity factors are likely in the coming years, all else equal.

55

A wind turbine’s “specific power” is a measure of its rated capacity relative to its swept rotor area (W/m2). As
rotor diameter (and therefore swept area) increases relative to nameplate capacity – e.g., as with low wind speed
turbine designs – more of the wind’s energy is captured, resulting in greater utilization of the generator’s rated
capacity, and therefore a higher overall capacity factor. Thus, all else equal, as specific power declines, capacity
factor should increase. Figure 28 plots the inverse of specific power (m2/kW) in order to better portray its influenceon capacity factor.

44
2011 Wind Technologies Market Report

3.2
3.1

95

3.0
2.9

90

2.8
2.7

85

2.6
2.5

80

Average 80m Wind Resource Quality Among Built Projects (left scale)

2.3

Swept Area divided by Nameplate Capacity (right scale)75

1998-99 2000-01 2002-03 2004-05

2006

2007

2008

2009

2.4

2010

2011

Inverse of Specific Power (m^2 / kW)

Index of Wind Resource Quality at 80m (1998-99=100)

100

2.2

Figure 28. Index of Wind Resource Quality at 80 Meters vs. Inverse of Specific Power

Though trends in hub height and “specific power” explain a portion of the results presented in
Figure 27, another large influence relates to the quality of the wind resource in which projects
are located. In particular, as depicted in Figure 28, the average estimated quality of the windresource at 80 meters among those projects built in each period has declined over time, and thatdecline is particularly sizable since 2008. 56 Specifically, wind power projects built in 2008 were,on average, located in estimated 80-meter wind resource conditions that are 4.7% worse thanthose projects build in 1998-99. Projects built in 2011, meanwhile, were – on average – locatedin estimated 80-meter wind resource conditions that are 16.1% worse than those projects built in
1998-99. Moreover, the sharp decline in average estimated wind resource quality at 80 meters
for projects built since 2008 has not – unlike in earlier periods – been offset by significant
growth in average hub heights (though swept area relative to rated capacity has increased overthis period). This decline in the average estimated wind resource quality of recently built wind
power projects is therefore also a key contributor to the recent stagnation in average capacity
factors and, without this decline, project-level average capacity factors would likely havecontinued their improvement from 2006 through 2010.
This apparent trend of building wind power projects in lower quality wind resource areas inrecent years may come as a surprise, given that the United States still has an abundance of
undeveloped high-quality wind resource areas. Several different factors could be driving thistrend:•

Technology Change: The increased availability of low-wind speed turbines that feature
higher hub heights and a lower “specific power” (i.e., a larger rotor diameter relative to rated
capacity) may have enabled the economical build out of lower wind speed sites.

56

The procedures used for estimating the quality of the wind resource in which wind projects are located, over time,is described in the Appendix.

45
2011 Wind Technologies Market Report••Siting Impacts: Developers may have reacted to increasing transmission constraints (orother siting constraints, or even just regionally differentiated wholesale electricity prices) by
focusing on those projects in their pipeline that may not be located in the best wind resourceareas, but that do have access to transmission (or higher-priced markets, or readily available
sites without long permitting times).
Policy Influence: Projects built in the four-year period from 2009 through 2012 have beenable to access a 30% ITC or cash grant in lieu of the PTC. Because the dollar amount of the
ITC or grant is not dependent on how much electricity a project generates, it is possible thatdevelopers have seized this limited opportunity to build out the less-energetic sites in theirdevelopment pipelines. Additionally, state RPS requirements sometimes require or motivate
in-state or in-region wind development in lower wind resource regimes.

Regional Variations in Capacity Factor Reflect the Strength of the Wind
Resource
The project-level spread in capacity factors shown earlier in Figure 27 is enormous, with 2011
capacity factors ranging from 18% to 53% among just those projects built in 2010. Some of thisspread is attributable to regional variations in average wind resource quality.

2011 Capacity Factor

60%

Capacity-Weighted Average (by region)
Individual Project (by region)
Capacity-Weighted Average (total U.S.)

50%
40%
30%
20%
10%
0%

Sample includes 305 projects built from 2004-2010 and totaling 32.8 GW
East

New England

California

Great Lakes

Northwest

Texas

MountainHeartland

26 projects

10 projects

14 projects

29 projects

51 projects

48 projects

29 projects

98 projects

2,282 MW291 MW

1,127 MW3,898 MW4,445 MW8,256 MW3,026 MW9,468 MW

Source: Berkeley Lab

Figure 29. 2011 Project Capacity Factors by Region: 2004-2010 Projects Only

Figure 29 shows the regional variation in 2011 capacity factors (using the regional definitions
shown in Figure 30), based on a sub-sample of wind power projects built from 2004 through2010 (i.e., a period of relative stability in 2011 capacity factors, per Figure 27). For this sample
of projects, capacity-weighted average capacity factors are the highest in the Heartland (37%)
and Mountain (36%) regions, and lowest in the East (25%) and New England (28%) regions.

46
2011 Wind Technologies Market ReportNot surprisingly, these regional rankings are roughly consistent with relative average wind speed
within each region, as shown in Figure 30. 57

Average wind speed at 80 meters
New
England

Northwest
Great
Lakes
California

EastHeartland
Mountain

Texas

Southeast

Source: AWS Truepower, NREL

Figure 30. Average Wind Speed at 80 Meters (with regional boundaries)

57

Given the relatively small sample size in some regions, as well as the possibility that certain regions may haveexperienced a particularly good or bad wind resource year or different levels of wind energy curtailment in 2011,care should be taken in extrapolating these results. For example, the average 2011 capacity factor in Texas of 34.4%
was depressed by the forced curtailment of wind generation, and would have been closer to 38% – an absoluteincrease of 3.3% – had there been no curtailment.

47
2011 Wind Technologies Market Report

6. Wind Power Price Trends
Earlier sections documented trends in wind turbine prices, installed project costs, O&M costs,
and capacity factors – all of which are determinants of the wind power sales prices presented inthis section. In general, higher cost and/or lower capacity factor projects will require higher
wind power prices, while lower cost and/or higher capacity factor projects can get by with lower
wind power prices.
Berkeley Lab collects data on wind power sales prices from the sources listed in the Appendix,
resulting in a dataset that consists of historical price data for 271 wind power projects installed
between 1998 and the end of 2011. These projects total 20,189 MW, or 44% of the wind power
capacity brought on line in the United States over the 1998-2011 timeframe. 58 The dataset
excludes merchant plants and projects that sell renewable energy certificates (RECs) separately.
The prices in the dataset therefore reflect the bundled price of electricity and RECs as sold by aproject owner under a power purchase agreement (PPA). Because these prices are suppressed by
the receipt of available state and federal incentives (e.g., the prices reported here would be atleast $20/MWh higher without the PTC / ITC / Treasury Grant), and are also influenced byvarious local policies and market characteristics, they do not represent wind energy generation
costs.
This section summarizes wind power sales prices in a number of different ways: by calendar
year, by project vintage, by PPA execution date, by region, and compared to wholesale power
prices both nationwide and regionally. In addition, REC prices are presented in a text box onpage 53.

Unlike Turbine Prices and Installed Project Costs, Cumulative, SampleWide Wind Power Prices Continued to Move Higher in 2011
Figure 31 shows the cumulative capacity-weighted average wind power price (along with therange of individual project prices falling between the 25th and 75th percentiles) in each calendar
year from 1999 through 2011. Based on the limited sample of 11 projects built in 1998 or 1999
and totaling 588 MW, the weighted-average price of wind energy in 1999 was roughly$62/MWh (expressed in 2011 dollars). This weighted-average price progressively declined insubsequent years until reaching a low of $37/MWh in 2005 (among a sample of 80 projects
totaling 4,056 MW). Since then, sample-wide average prices have risen steadily, such that in2011, the cumulative sample of projects built from 1998 through 2011 had grown to 271 projects
totaling 20,189 MW, with an average price of $54/MWh (with 50% of individual project prices

58

Three primary factors significantly restrict the size of this sample: (1) projects located within ERCOT (in Texas)
fall outside of FERC’s jurisdiction, and are therefore not required to report prices (reduces sample by roughly 9,600
MW); (2) the increasing number of utility-owned projects are not included, since these projects do not sell theirpower at an observable price (reduces sample by about 6,400 MW); and (3) the increasing number of merchant (orquasi-merchant) projects that sell power and RECs separately are not included in the sample, because the power
price reported by these projects only represents a portion of total revenue received (reduces sample by roughly
another 6,000 MW). In addition, certain “qualifying facilities” are not required to report their power sales to FERC.

48
2011 Wind Technologies Market Reportfalling between $36/MWh and $63/MWh). 59 This general temporal trend of falling and thenrising prices is consistent with the turbine price and installed project cost trends shown in earlier
sections, though the cumulative nature of Figure 31 results in a smoother, less-responsive curvethat lags the directional changes in turbine and project cost trends. 60
70

Wind Power Price (2011 $/MWh)

Sample includes projects built from 1998-2011
60
50
40
30
20
10

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

0
Year: 1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

Projects: 11

12

22

33

47

64

80

97

120

150

184

233

271

MW: 588

600

741

1,444

2,294

3,103

4,056

4,987

7,980

10,535

13,701

17,19020,189Source: Berkeley Lab

Figure 31. Cumulative Capacity-Weighted Average Wind Power Prices over TimeBinning Wind Power Sales Prices by Project Vintage Also Fails to Show a
Price Reversal
To better illustrate changes in the price of power from newly built wind power projects, Figure
32 shows average wind power sales prices in 2011, grouped by project vintage (i.e., by eachproject’s initial commercial operation date, COD). 61 Although the limited project sample andthe considerable variability in prices across projects installed in a given time period complicate
analysis of national price trends (with averages subject to regional and other factors), the generaltrend exhibited by the capacity-weighted-average prices (i.e., the blue columns) neverthelessshows that prices bottomed out for projects built from 2002 through 2005, and have since risen

59

All wind power pricing data presented in this report exclude the few projects located in Hawaii. Those projects
are considered outliers in that they are significantly more expensive to build than projects in the continental UnitedStates, and have received power sales prices that are significantly higher-than-normal, in part because those prices
have historically been linked to the price of oil.
60
For example, Figure 31 shows wind power sales prices bottoming in 2005 – i.e., several years after turbine prices
and installed project costs bottomed – and potentially not yet peaking in 2011, even though turbine prices peaked in
2008/2009 and installed costs peaked in 2009/2010.
61
Prices from two individual projects – one built during the 2000-2001 period, and the other built in 2008 – are notshown in Figure 32 (due to the scale of the y-axis), but are included in the capacity-weighted averages for those
periods. The omitted prices are roughly $150/MWh and $126/MWh, respectively.

49
2011 Wind Technologies Market Report2011 Wind Power Price (2011 $/MWh)significantly. 62 Specifically, the capacity-weighted average 2011 sales price, based on projects
in the sample built in 2011, was roughly $74/MWh. This price is essentially unchanged from theaverage among projects built in 2010 (the spread of individual project prices is also similar
among projects built in 2010 and 2011), and is more than twice the average of $32/MWh among
projects built during the low point in 2002 and 2003.
120
100

Capacity-Weighted Average (by project vintage)
Individual Project (by project vintage)

80
60
40
20
0

1998-99

2000-01

2002-03

2004-05

2006

2007

2008

2009

2010

2011

14 projects 21 projects 33 projects 21 projects 14 projects 24 projects 31 projects 53 projects 27 projects 33 projects
650 MW

854 MW

1,648 MW 1,269 MW

742 MW

3,190 MW 2,669 MW 3,987 MW 2,386 MW 2,793 MW

Source: Berkeley Lab database

Figure 32. 2011 Wind Power Prices by Project Commercial Operation Date

Although the similarity in pricing among 2010 and 2011 projects shown in Figure 32 may
actually portend a peak (with lower prices likely among 2012 projects), the fact that neither
Figure 31 nor (especially) Figure 32 show any sort of price reversal is nevertheless surprising,particularly given the degree to which turbine prices have dropped since 2008, along withgrowing anecdotal evidence of aggressive pricing in wind PPAs. The next section parses thedata in a different way, by PPA execution date, to try and understand these findings.

62

Although it may seem counterintuitive, the weighted-average price in 1999 for projects built in 1998 and 1999
(shown in Figure 31 to be about $62/MWh) is significantly higher than the weighted-average price in 2011 forprojects built in 1998 and 1999 (shown in Figure 32 to be about $34/MWh) for three reasons: (1) the sample size islarger in Figure 32, due to the fact that 2011 prices are presented, rather than 1999 prices as in Figure 31 (i.e., earlyyear pricing for some of the projects built in 1998-1999 were unavailable); (2) two of the larger projects built in1998 and 1999 (for which both 1999 and 2011 prices are available, meaning that these projects are represented
within both figures) have nominal PPA prices that actually decline, rather than remaining flat or escalating, overtime; and (3) inflating all prices to constant 2011 dollar terms impacts older (i.e., 1999) prices more than it does
more-recent (i.e., 2011) prices.

50
2011 Wind Technologies Market ReportBinning Wind Power Sales Prices by PPA Execution Date Shows Steeply
Falling Prices
Figure 33 shows essentially the very same data as Figure 32, but this time binned by PPA
execution date rather than commercial operation date. 63 Viewed this way, 2011 and 2010 wind
power prices tell a very different story – one of falling prices since 2009. The green individual
project markers in Figure 33 represent those wind power projects built in 2011, and demonstratethat only two such projects (within our sample) actually signed PPAs in 2011. All other 2011
projects in our sample signed PPAs in 2010, 2009, or even back as far as 2008 – i.e., at theheight of the market for turbines – thereby locking in prices that ended up being above market in2011. Overall, the weighted-average PPA execution date among all 2011 projects in our sample
was December 2009 – more than a full year before the start of 2011. This lag is considerable –particularly in a fast-moving market – and is roughly a year longer than the average lag seen inprevious years (i.e., prior to 2011, the average PPA execution date for projects built in a given
year most often fell somewhere in the fourth quarter of the immediately preceding year).

2011 Wind Power Price (2011 $/MWh)

120
100

Capacity-Weighted Average (by PPA vintage)
Individual Projects (by PPA vintage)
Individual Projects Built in 2011 (by PPA vintage)

80
60
40
20
0

1998-99

2000-01

2002-03

2004-05

2006

2007

2008

2009

2010

2011

10 projects 13 projects 21 projects 24 projects 25 projects 12 projects 33 projects 41 projects 23 projects 2 projects
577 MW

939 MW

1,583 MW 2,402 MW 2,451 MW 1,638 MW 3,483 MW 4,320 MW 2,184 MW

150 MW

Figure 33. 2011 Wind Power Prices by PPA Execution Date

Figure 34 also breaks out wind power pricing by PPA execution date, but this time among aslightly smaller sample of projects for which we have full-term (rather than just historical) PPA
price data. 64 Having full-term price data (i.e., pricing data for the full duration of each PPA, notjust historical PPA prices) enables us to present these PPA prices on a levelized basis (levelized
over the full contract term), which provides a more complete picture of wind power pricing (e.g.,
by capturing any escalation over the duration of the contract). Consistent with Figure 33, Figure
34 shows a clear downward trend in wind power prices since 2009, particularly among those63

The sample in Figure 33 is slightly smaller than in Figure 32 (19,727 MW vs. 20,189 MW, respectively) because
we were not able to ascertain PPA execution dates for all projects included in Figure 32.
64
Many of the recent levelized PPA prices shown in Figure 34 are from projects that will be built in 2012; theseprojects do not show up in Figure 33, because they were not operational in 2011.

51
2011 Wind Technologies Market Reportprojects located within the mid-continent “wind belt.” 65 Prices are generally higher in the rest of
the U.S., where the wind resource is not as strong (the dashed “best fit” curve almost perfectly
divides the “wind belt” from the rest of the U.S.), and have been particularly high in California inrecent years. 66$120

California (2,127 MW, 19 contracts)
Rest of US (4,033 MW, 66 contracts)
Wind Belt (10,882 MW, 131 contracts)$100

150 MW

$80
$60
$40
$20

Jan-12

Jan-11

Jan-10

Jan-09

Jan-08Jan-07

Jan-06

Jan-05Jan-04Jan-03Jan-02Jan-01

Jan-00Jan-99Jan-98Jan-97$0

Jan-96

Levelized PPA Price (2011 $/MWh)Among the full sample of wind power projects with PPAs signed in 2011 depicted in Figure 34,
the capacity-weighted average levelized PPA price is $35/MWh, down from $59/MWh for PPAs
signed in 2010 and $72/MWh for PPAs signed in 2009. For just the “wind belt,” thecorresponding levelized PPA prices are $32/MWh, $44/MWh, and $53/MWh respectively.
Either way, it is apparent that wind pricing – when parsed by PPA execution date – has comedown significantly in recent years, and is currently more competitive than what is implied by
Figures 31 and 32, earlier. In fact, levelized PPA prices in the $30-$40/MWh range – currently
achievable (at least with the PTC) in many parts of the interior U.S. – are fully competitive withthe range of wholesale power prices seen in 2011, as shown later in Figure 36.

PPA Execution Date
Note: Size of “bubble” is proportional to project nameplate capacity.

Figure 34. Levelized Wind PPA Prices by PPA Execution Date

65

The “wind belt” is defined here to consist of 13 states located within the interior U.S. where the wind resource isgenerally the strongest (see Figure 30, earlier). Wind belt states include Colorado, Iowa, Kansas, Minnesota,
Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, and Wyoming.
66
Recent high prices in California may be due, in part, to aggressive renewable energy policies (along with certain
elements of policy design) that give developers a strong negotiating position. Relatively stringent permitting andregulatory requirements may also make California a particularly expensive state in which to build wind power
projects, as suggested by the installed cost data presented earlier in this report.

52
2011 Wind Technologies Market ReportWind Power PPA Prices Vary Widely By Region
As suggested by Figure 34, regional factors can influence wind power pricing. Regional
differences, for example, can affect not only project capacity factors (depending on the strengthof the wind resource in a given region), but also development and installation costs (depending
on a region’s physical geography, population density, labor rates, or even regulatory processes).
It is also possible that regions with higher wholesale electricity prices or with greater demand forrenewable energy will, in general, yield higher wind energy contract prices due to market factors.
Figure 35 shows individual project and average 2011 wind power prices by region for just thosewind power projects installed in 2010 and 2011 (which, at least per Figure 32, was a period ofstable pricing), with regions as defined earlier in Figure 30. Although sample size is quite small
and therefore problematic in several regions, 67 Texas, the Heartland, and the Mountain regions
appear to be among the lowest price areas, on average, while California is, by far, the highest
price region.

2011 Wind Power Price (2011 $/MWh)120
Sample includes projects built in 2010 and 2011
100
80
60
40
Capacity-Weighted Average (by region)

20

Individual Project (by region)
Capacity-Weighted Average (total U.S.)

0

Texas

Heartland

Mountain

New England

Great Lakes

East

Northwest

California

1 project

23 projects

6 projects

3 projects

5 projects

5 projects

7 projects

10 projects

78 MW

1,395 MW868 MW

113 MW

600 MW

314 MW

724 MW

1,088 MW

Source: Berkeley Lab

Figure 35. 2011 Wind Power Prices by Region: 2010-2011 Projects Only

Abnormally high pricing in California, coupled with an unusually high proportion of California
projects in the 2011 project sample, is another reason why Figure 32 fails to show a pricereversal. Specifically, California accounts for nearly one quarter of the 2011 project sample,
thereby disproportionately inflating the capacity-weighted average price among all 2011 projects(as it also did in 2010, when it made up almost 20% of the 2010 project sample).

67

Average prices in Texas and New England, in particular, may not be representative as those averages include justone and three projects, respectively. Once again, sample size in Texas is severely limited (despite the enormous
growth of wind power capacity in that state) because generators located within ERCOT are not required to file
pricing information with FERC. As such, the pricing information for Texas provided in this report comes primarily
from projects located in the Texas panhandle, which is within the SPP rather than ERCOT.

53
2011 Wind Technologies Market ReportREC Prices Rise in the Northeast, Remain Depressed Elsewhere
The wind power sales prices presented in this report reflect only the bundled sale of both electricity and RECs;
excluded are projects that sell RECs separately from electricity, thereby generating two sources of revenue. REC
markets are fragmented in the United States, but consist of two distinct segments: compliance markets in which
RECs are purchased to meet state RPS obligations, and green power markets in which RECs are purchased on a
voluntary basis.
The figures below present indicative monthly data of spot-market REC prices in both compliance and voluntary
markets, grouped into High-Price and Low-Price markets; data for compliance markets focus on the “Class I” or“Main Tier” of the RPS policies. Clearly, spot REC prices have varied substantially, both across states and overtime within individual states, though prices across states within common regions (New England and PJM) arelinked to varying degrees. Over the course of 2011, REC spot-market prices rose substantially among
Northeastern markets, after having steadily declined over several preceding years, and ended the year above$35/MWh in Connecticut, Massachusetts, New Hampshire, and Rhode Island. Elsewhere, however, REC prices
for compliance markets fell (e.g., for Ohio's in-state RPS requirements) or remained below $5/MWh, due to acontinued surplus of eligible renewable energy supply relative to RPS-driven demand. Prices for RECs offered in
the national voluntary market remained below $1/MWh, while voluntary wind RECs in the West declined to
below $5/MWh over the course of the year.
High-Price REC Markets

Low-Price REC Markets

Jan-12

Jul-11

Jul-10Jan-11

Jul-09DE Class I
MD Tier 1
OH Out-of -State
TX
Voluntary Wind (West)

Jan-09Jul-08

Jul-07Jan-12

Jul-11

Jan-11

Jul-10Jan-10Jul-09

Jan-09$0

Jul-08$0

Jan-08$10

Jul-07$20

Jan-07$20

Jul-06$40

Jul-05$30

Jan-06$60

Jan-08OH In-State

Jul-06RI New

Jan-07NH Class I

DC Tier 1
IL WindNJ Class I
PA Tier 1
Voluntary Wind (National)

Jan-06

ME New

Jul-05MA Class I

Jan-05CT Class I

Jan-10$40

Jan-052011 $/MWh$80

Sources: Evolution Markets (through 2007) and Spectron (2008 onward). Plotted values are the last monthly trade (if available) or
the mid-point of monthly Bid and Offer prices, for the earliest compliance year traded in each month (compliance markets) or forthe current or nearest year traded in each month (voluntary markets).

Low Wholesale Electricity Prices Continued to Challenge the Relative
Economics of Wind Power
Figure 36 shows the range (minimum and maximum) of average annual wholesale electricity
prices for a flat block of power 68 going back to 2003 at twenty-three different pricing nodes
located throughout the country (refer to the Appendix for the names and approximate locations
68

A flat block of power is defined as a constant amount of electricity generated and sold over a specified time
period. Though wind power projects do not provide a flat block of power, as a common point of comparison, a flat
block is not an unreasonable starting point. In other words, the time-variability of wind energy is often such that its
wholesale market value is somewhat lower than, but not too dissimilar from, that of a flat block of (non-firm) power.

54
2011 Wind Technologies Market Report

of the twenty-three pricing nodes represented by the blue-shaded area). The red dots show the
cumulative capacity-weighted average price received by wind power projects in each year among
those projects in the sample with commercial operation dates of 1998 through 2011 (consistent
with the data first presented in Figure 31).
At least on a cumulative basis within the sample of projects reported here, average wind power
prices compared favorably to wholesale electricity prices from 2003 through 2008. Starting in
2009, however, increasing wind power prices, combined with a sharp drop in wholesale
electricity prices (driven by lower natural gas prices), pushed average wind energy prices to the
top of (and in 2011 above) the wholesale power price range. Although low natural gas prices
are, in part, attributable to a slow economic recovery, gas prices may not ultimately rebound toearlier levels as the economy recovers, due to the ongoing development of significant shale gas
deposits. Reduced expectations for natural gas price levels going forward puts the near-term
comparative economic position of wind energy at some risk, absent further reductions in theprice of wind power (and absent supportive policies for wind energy). That said, as shown
earlier in Figures 33 and 34, pricing among recently signed wind PPAs – in some cases for
projects that will be built in 2012 – is already largely competitive with the wholesale power pricerange for 2011 shown in Figure 36.
90Wind project sample includes
projects built from 1998-2011

80

2011 $/MWh

70
60
50
40
30
20

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

10

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

0

2003

2004

2005

2006

47 projects

64 projects

80 projects

97 projects

120 projects 150 projects 184 projects 233 projects 271 projects

2007

2008

2,294 MW3,103 MW

4,056 MW4,987 MW7,980 MW

10,535 MW

2009
13,701 MW

2010
17,190 MW

2011
20,189 MW

Source: Berkeley Lab, FERC, Ventyx, ICE

Figure 36. Average Cumulative Wind and Wholesale Electricity Prices over TimeThough Figure 36 portrays a national comparison, there are clearly regional differences inwholesale electricity prices and in the average price of wind power. Figure 37 focuses on 2011
wind and wholesale electricity prices in the same regions as shown earlier, based only on thesample of wind power projects installed in 2010 and 2011. 69 Although there is quite a bit ofvariability within some regions, and several regions again have limited sample size, the spread
between average wind power and wholesale electricity prices (i.e., the wind power premium) in
69

As discussed in footnote 67, the average wind power prices presented here for Texas and New England inparticular should be viewed with caution.

55
2011 Wind Technologies Market Reporteach region in 2011 is fairly consistent across much of the United States. Again, though,recently signed wind PPAs – particularly in Texas, and the Heartland and Mountain regions (e.g.,
see the “wind belt” in Figure 34) – are more competitive than shown in Figure 37.
120

Average 2011 Wholesale Power Price Range
2011 Capacity-Weighted Average Wind Power Price2011 $/MWh

100

Individual Project 2011 Wind Power Price

80
60
40
20

Wind project sample includes projects built in 2010 and 2011
0

Texas

Heartland

Mountain

East

Northwest

California

Total US1 project

23 projects

6 projects

New England Great Lakes
3 projects

5 projects

5 projects

7 projects

10 projects

60 projects

78 MW

1,395 MW868 MW

113 MW

600 MW

314 MW

724 MW

1,088 MW5,180 MW

Source: Berkeley Lab, Ventyx, ICE

Figure 37. Wind and Wholesale Electricity Prices by Region: 2010-2011 Projects Only

Important Note: Notwithstanding the comparisons made in Figures 36 and 37, it should berecognized that neither the wind nor wholesale electricity prices presented in this section reflect
the full social costs of power generation and delivery. Specifically, the wind power prices aresuppressed by virtue of federal and, in some cases, state tax and financial incentives.
Furthermore, these prices do not fully reflect integration, resource adequacy, or transmission
costs. At the same time, wholesale electricity prices do not fully reflect transmission costs, may
not fully reflect capital and fixed operating costs, and are suppressed by virtue of any financial
incentives provided to fossil-fueled generation and by not fully accounting for the environmental
and social costs of that generation. In addition, wind power prices – once established – aretypically fixed and known (because wind energy is often sold through long-term, fixed-pricepower purchase agreements), whereas wholesale electricity prices are short-term and therefore
subject to change over time. Moreover, as discussed earlier, the historical wind power prices
presented here are not necessarily representative of PPAs being negotiated today based on thelower turbine pricing environment that now prevails. Finally, the location of the wholesale
electricity nodes and the assumption of a flat-block of power are not perfectly consistent with thelocation and output profile of the sample of wind power projects.
In short, comparing wind and wholesale electricity prices in this manner is not appropriate
if one’s goal is to fully account for the costs and benefits of wind energy relative to its
competition. Another way to think of Figures 36 and 37, however, is as loosely representing thedecision facing wholesale electricity purchasers that are otherwise under no obligation topurchase additional amounts of wind energy – i.e., whether to contract long-term for wind poweror to buy a flat block of (non-firm) spot power on the wholesale electricity market. In this sense,
the costs represented in Figures 36 and 37 are reasonably comparable, in that they represent (tosome degree, at least) what the power purchaser would actually pay.
56
2011 Wind Technologies Market Report7. Policy and Market Drivers
Uncertainty Reigns in Federal Incentives for Wind Energy Beyond 2012
A variety of policy drivers at both the federal and state levels have been important to the
expansion of the wind power market in the United States. At the federal level, the mostimportant policy incentives in recent years have been the PTC, accelerated tax depreciation, and
two Recovery Act provisions that enabled wind power projects to elect, for a limited time only,
either a 30% investment tax credit (ITC) or a 30% cash grant in lieu of the PTC. Also of morelimited import to wind development has been the Department of Energy's loan guarantee
program.
•

•

•

•

First established by the Energy Policy Act of 1992, the PTC provides a 10-year, inflationadjusted credit that stood at 2.2¢/kWh in 2011. The historical importance of the PTC to the
U.S. wind power industry is illustrated by the pronounced lulls in wind power capacity
additions in the three years (2000, 2002, and 2004) in which the PTC lapsed, as well as theincreased development activity often seen during the year in which the PTC is otherwise
scheduled to expire (see Figure 1). Wind power projects are currently eligible for the PTC ifthey achieve commercial operations by the end of 2012.
Accelerated tax depreciation enables wind project owners to depreciate the vast majority of
their investments over a five- to six-year period for tax purposes. An even-more-attractive
50% first-year “bonus depreciation” schedule was in place during 2008-2010. The Tax
Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 that was
signed into law in mid-December 2010 increased first-year bonus depreciation to 100% for
those projects placed in service between September 8, 2010 and the end of 2011, after which
the first-year bonus reverted to 50% for projects placed in service during 2012.
The Recovery Act enabled wind power projects placed in service prior to the end of 2012 toelect a 30% ITC in lieu of the PTC. More importantly, given the relative scarcity of tax
equity in the wake of the financial crisis, Section 1603 of the Recovery Act also enabledwind power projects to elect a 30% cash grant from the Treasury in lieu of either the ITC or
the PTC. More than 60% of the new wind capacity installed in 2011 elected the Section
1603 grant. In order to qualify for the grant, wind power projects must have been underconstruction by the end of 2011, must apply for a grant by October 1, 2012, and must beplaced in service by the end of 2012.
Another Recovery Act program, the Section 1705 loan guarantee program for commercial
projects, has also wound down, as projects had to be under construction by September 30,
2011 in order to qualify. In total, this program closed on four loan guarantees to wind power
projects totaling 1,024 MW of capacity, 285 MW of which were online by the end of 2011.

With the PTC, 30% ITC, 30% cash grant, and bonus depreciation all currently scheduled to
expire at the end of 2012 for new wind projects, 70 the wind energy sector is currently
experiencing serious federal policy uncertainty, and therefore rushing to complete projects by the70

Although eligibility for the Treasury grant does hinge on construction having begun by the end of 2011,
complying with this interim start-of-construction deadline is unlikely to have been particularly onerous for mostwind power projects, based on safe harbor guidance published by the Treasury.

57
2011 Wind Technologies Market Reportend of the year. Moreover, 2011 saw another year pass without any concrete Congressional
action on what are seemingly the wind power industry’s two highest priorities – a longer-term
extension of federal tax (or cash) incentives and passage of a federal renewable or clean energy
portfolio standard.
Though the lack of long-term federal incentives for wind energy has been a drag on the industry,
new and accelerated federal activity in wind project siting and permitting has been viewed as a
net positive. In March 2012, for example, the Department of Interior released voluntary
guidelines designed to help wind power projects avoid and minimize impacts to wildlife,
reducing the perceived risk and uncertainty that preceded the release. Progress also continued tobe made on streamlining the process of developing wind power projects on public lands.

State Policies Play a Role in Directing the Location and Amount of Wind
Power Development, but Current Policies Cannot Support Continued
Growth at the Levels Seen in the Recent Past
From 1999 through 2011, 65% of the wind power capacity built in the United States was locatedin states with RPS policies; in 2011, this proportion was 78%. 71 As of July 2012, mandatory
RPS programs existed in 29 states and Washington D.C. (Figure 38). Although no new state
RPS policies were passed in 2011, a number of states strengthened previously established RPS
programs. 72 In aggregate, existing state RPS policies are estimated to require roughly 100 GWof new renewable capacity by 2035, beyond what was already installed in each RPS state at thetime that its RPS policy was established. 73 This required additional renewable capacity isequivalent to roughly 7% of total projected U.S. retail electricity sales in 2035 and 34% ofprojected load growth between 2000 and 2035.
Given the size of the RPS targets and the amount of new renewable energy capacity alreadybuilt, existing state RPS programs are projected to drive average annual renewable energy
additions of roughly 4-5 GW/year (not all of which will be wind) between 2012 and 2020. 74
This is well below the amount of wind power capacity added in 2011, and even further below the
9 GW of total renewable capacity added in 2011 (which included roughly 2 GW of solar
capacity), demonstrating the limitations of relying exclusively on state RPS programs to drive
future wind power development.

71

Such statistics provide only a rough indication of the impact of RPS policies on wind power development, andcould either overstate or understate the actual policy effect to-date.
72
Attempts to weaken RPS programs have also been initiated in some states, though those efforts have not thus far
led to meaningful changes in RPS design.
73
Berkeley Lab’s projections of new renewable capacity required to meet each state’s RPS requirements assume
different combinations of renewable resource types for each RPS state, though they do not assume any biomass cofiring at existing thermal plants. To the extent that RPS requirements are met with a larger proportion of highcapacity-factor resources than assumed in this analysis or with biomass co-firing at existing thermal plants, therequired new renewable capacity would be lower than the projected amount presented here.
74
Again, varying combinations of renewable resource types for each RPS state were assumed in estimating the 4-5
GW/year of average annual renewable capacity additions required to meet RPS obligations through 2020.

582011 Wind Technologies Market ReportWA: 15% by 2020

MT: 15% by 2015

MN: 25% by 2025
Xcel: 30% by 2020

ND: 10% by 2015
OR: 25% by 2025 (large utilities)
5-10% by 2025 (smaller utilities)
NV: 25% by 2025

MI: 10% by 2015

VT: 20% by 2017

NY: 30% by 2015
SD: 10% by 2015 WI: 10% by 2015
PA: 8.5% by 2020
IA: 105 MW by 1999

UT: 20% by 2025 KS: 20% of peakdemand by 2020
CA: 33% by 2020

ME: 40% by 2017

NJ: 22.5% by 2020

IL: 25% by 2025

OH: 12.5% by 2024

MO: 15% by 2021
CO: 30% by 2020 (IOUs)
10% by 2020 (co-ops and munis)

MD: 20% by 2022

OK: 15% by 2015
AZ: 15% by 2025
AK: 50% by 2025

NM: 20% by 2020 (IOUs)
10% by 2020 (co-ops)
TX: 5,880 MW by 2015

HI: 40% by 2030

NH: 23.8% by 2025
MA: 11.1% by 2009 +1%/yr
RI: 16% by 2019
CT: 23% by 2020

DE: 25% by 2025
DC: 20% by 2020
VA: 15% by 2025
NC: 12.5% by 2021 (IOUs)
10% by 2018 (co-ops and munis)

Mandatory RPS
Non-Binding Goal

Source: Berkeley Lab
Note: The figure does not include West Virginia's mandatory “alternative and renewable energy portfolio standard” or Indiana's
voluntary "clean energy standard." Under these two states' policies, both renewable and non-renewable energy resources may
qualify, but neither state specifies any minimum contribution from renewable energy. Thus, for the purposes of the present report,these two states are not considered to have enacted mandatory RPS policies or non-binding renewable energy goals.

Figure 38. State RPS Policies and Non-Binding Renewable Energy Goals (as of July2012)

In addition to state RPS policies, utility resource planning requirements, principally in Westernand Midwestern states, have also helped spur wind power additions in recent years, as has
voluntary customer demand for “green” power. State renewable energy funds provide support
for wind power projects (both financial and technical) in some jurisdictions, as do a variety ofstate tax incentives. Finally, concerns about the possible impacts of global climate change
continue to fuel interest in some states and regions to implement and enforce carbon reduction
policies. The Northeast’s Regional Greenhouse Gas Initiative (RGGI) cap-and-trade policy, forexample, has been operational for several years, and California’s greenhouse gas cap-and-trade
program commenced operation in 2012, though carbon pricing seen to date under RGGI has
been too low to drive significant wind energy growth. At the same time, other states haveexpressed growing skepticism of these efforts, and a number of states have withdrawn, or
undertaken steps toward withdrawal, from regional greenhouse gas reduction initiatives,
including RGGI and the Western Climate Initiative.

Despite Progress on Overcoming Transmission Barriers, Constraints
RemainTransmission development has continued to gain traction during recent years. The North
American Electric Reliability Corporation (NERC), for example, reported that about 2,300
circuit miles of new transmission additions were under construction in the United States near theend of 2011, with an additional 17,800 circuit miles planned through 2015 (NERC 2011). The
Brattle Group, meanwhile, has estimated that planned and proposed transmission projects
represent around $60-80 billion in potential investments from 2011 through 2015 (Pfeifenberger
59
2011 Wind Technologies Market Report2012). Finally, AWEA has identified near-term transmission projects that – if all werecompleted – could carry almost 45 GW of wind power capacity (AWEA 2012a).
Lack of transmission can be a barrier to new wind power development, and insufficienttransmission capacity in areas where wind projects are already built can lead to curtailment, as
illustrated by the data on wind energy curtailment reported earlier. New transmission isparticularly important for wind energy because wind power projects are constrained to areas withadequate wind speeds, which are often located at a distance from load centers. There is also amismatch between the relatively short timeframe often needed to develop a wind power projectcompared to the longer timeframe typically required to build new transmission. Uncertainty overtransmission siting and cost allocation, particularly for multi-state transmission lines, further
complicates transmission development.
In July 2011, FERC issued Order No. 1000, which requires public utility transmission providers
to improve transmission planning processes and to determine a cost allocation methodology for
new transmission facilities. The transmission planning requirements established in the new rule
include development of regional transmission plans, mandatory participation in regionaltransmission planning, consideration of transmission needs driven by public policy requirements
established by state and federal regulations (such as RPS programs), and coordination between
neighboring transmission planning regions. In addition, each public utility transmission provider
is now required to develop a common regional methodology for allocating the costs for new
transmission facilities consistent with six principles for both intra-regional and inter-regional
facilities. The methodology can include different cost allocation schemes for projects driven bydifferent needs, i.e., reliability, economic, and public policy (FERC 2011a). Initial compliancefilings under Order No. 1000 are due in October 2012.
States, grid operators, utilities, regional organizations, and DOE continue to take proactive steps
to encourage transmission investment and improve access to renewable resources. A nonexhaustive list of these initiatives is presented below:••

Bonneville Power Administration (BPA): As a result of the Network Open Season
initiative, BPA processed 263 transmission service requests from 2008-2010, including 7,105
MW associated with wind power. However, due to uncertainty regarding proposed windprojects and that the success of the Network Open Season was more than BPA anticipated,
plans for future Network Open Seasons have been put on hold until BPA conducts a reviewof transmission planning and wind energy integration issues. In February 2012, BPA
completed the 79-mile 500-kV McNary-John Day transmission project, which can support up
to 575 MW of wind power capacity. The Network Open Season initiative also prompted thedevelopment of the 28-mile Big Eddy-Knight transmission project; completion is expected in
2013. Separately, in January 2012, BPA signed a Memorandum of Understanding with
NorthWestern Energy to explore the possibility of participating in the development of theMountain States Transmission Intertie that would extend from Montana to Idaho.
Southwest Power Pool (SPP): In October 2011, FERC denied requests for rehearing, andthereby upheld, its 2010 order accepting SPP’s “Highway/Byway” transmission costallocation methodology (FERC 2011b). In early 2012, the SPP Board of Directors approveda near-term transmission expansion plan that will result in the construction of $251 million in
new transmission projects over the next five years. SPP’s board also approved a 10-year60
2011 Wind Technologies Market Report

•

•

•

•

transmission expansion plan, with projects representing an additional $1.5 billion intransmission investment.
Midwest Independent Transmission System Operator (MISO): In late October 2011,
FERC upheld its December 2010 acceptance of MISO’s regional cost allocation
methodology for multi-value projects (MVP), subject to a FERC requirement that MISO
monitor the cumulative costs and benefits of all approved MVP projects (FERC 2011c). In
December 2011, the MISO Board of Directors approved the MISO Transmission Expansion
Plan, which includes 215 projects, representing 3,665 circuit-miles of new or upgradedtransmission lines, and requires about $6.5 billion in potential transmission investment overthe next 5 to 7 years. The plan includes 17 MVPs, representing about $5.1 billion. Together
with the previously approved MVPs, the 17 MVPs could connect as much as 14,000 MW ofwind power capacity (AWEA 2012a). Also in MISO, the CapX2020 Monticello to St. Cloud
345-kV transmission line in Minnesota was energized in late December 2011, the first
CapX2020 project to be completed and placed in service.
Texas Competitive Renewable Energy Zones (CREZ): The 2,300 circuit-miles of Texas
CREZ lines are largely on track to be completed by the end of 2013, and are expected toaccommodate a total of 18,500 MW of wind power capacity. Since 2008, the initial costestimate of about $4.9 billion has increased by over 40%, to almost $7 billion (PUCT 2012).
It is also now estimated that it may take several years or more for developers to build enoughwind power capacity to fully utilize the CREZ lines planned for West Texas and the Texas
Panhandle area because of lower natural gas prices, slower load growth, and the difficulty of
securing project financing for wind power development. Nevertheless, the potential for windenergy development along the Texas Gulf Coast has spurred recent discussions regarding asecond phase of CREZ.
Western Area Power Administration (WAPA): WAPA received $3.25 billion inborrowing authority under the Recovery Act for developing new transmission. In September
2011, WAPA and TransWest Express (TWE) agreed to fund the development phase of theTransWest Express transmission project, a proposed 725-mile, 600-kV transmission line that
could deliver up to 3,000 MW of renewable energy from Wyoming to the Marketplace Hub,near Las Vegas. If WAPA continues its participation in the project into the construction
phase – a decision that will be made when the environmental analysis is completed –additional borrowing authority would be used to help fund the project. Meanwhile, a DOE
Inspector General report released in November 2011 criticized WAPA for failing to
implement safeguards for protecting the $161 million WAPA has committed towards theconstruction of the Montana-Alberta Transmission Line, a controversial project that iscurrently facing legal challenges. Should it be completed, the 214-mile, 230-kV line would
deliver up to 300 MW in either direction.
California ISO (CAISO): According to the CAISO’s 2011-2012 Transmission Plan,enough transmission capacity to meet California’s 33% RPS goal by 2020 is either underdevelopment or in planning. Of the $7.1 billion in transmission projects included in the plan,a number of them have already been approved and permitted, including: the Sunrise
Powerlink, the Tehachapi Transmission project, the Colorado River-Valley line, theEldorado-Ivanpah line, and the Carrizo-Midway reconductoring (CAISO 2012b). The
Sunrise Powerlink transmission line was completed in June 2012, and will be capable oftransmitting up to 1,000 MW of renewable energy. SDG&E, the developer of the Sunrise
Powerlink, recently signed long-term PPAs with Pattern Wind Energy and Manzana Wind
61
2011 Wind Technologies Market Reportfor 315 MW and an additional 100 MW of wind energy to flow across the line. The
Tehachapi Transmission project, which is being developed by Southern California Edison(SCE), is expected to accommodate up to 4,500 MW of new generation, much of it
potentially wind, once completed in 2015. In late 2011, however, the California Public
Utilities Commission ordered SCE to stop construction on a segment of the project that runs
through Chino Hill, California. The City of Chino Hills and SCE have yet to come to amutual agreement on an alternative route, which may push back the in-service date of the
project.
Three RTOs are also in various stages of reforming their interconnection queue processes. In
early 2012, FERC accepted a set of revisions to CAISO’s generator interconnection procedures
that: allow power plants to request partial deliverability status, which could reduce the cost of
network upgrades; provide for reimbursement of network upgrades for projects built in phases;
divide the cost of financial security for network upgrades into separate components to align withconstruction phases; and allow customers to cut generation capacity by up to 5% for any reason
between the effective date of an interconnection agreement and the commercial operation date.
In May 2012, CAISO proposed further revisions to its interconnection queue process, which are
currently being evaluated at FERC. In February 2012, PJM Interconnection filed a petition to
FERC to make three modifications to its Open Access Transmission Tariff: a six-month queue
cycle to replace the current three-month planning cycle; allowing a project to decrease in size
during the study process; and establishing an alternate queue for projects smaller than 20 MWthat connect to distribution level facilities and do not cause the need for upgrades to the PJM
transmission system. Finally, in March 2012, FERC conditionally approved a proposal fromMISO that addresses backlogs and late-stage terminations of generation interconnection
agreements. In addition to revised timelines and new study procedures, the reforms requireinterconnection customers to put more money at risk earlier in the process with the justification
being that the projects that remain in the queue are those that are more likely to reachcommercial operations.
Progress was also reported under interconnection-wide planning supported by previous grants
from the DOE. In December 2011, the Eastern Interconnection Planning Collaborative
submitted its phase one report to DOE, which focused on the integration of regional plans andlong-term macroeconomic analysis. Phase two of the project will focus on conducting
transmission studies based on three scenarios, which will include reliability studies as well as
various options for transmission expansion plans. In the Western Interconnection, the WesternElectricity Coordinating Council completed its first 10-Year Regional Transmission Plan in
September 2011. Also in 2011, the Texas Interconnection’s Long-Term Study Task Forcesubmitted to DOE its interim status report for the ERCOT Long-Term Transmission Analysis.
ERCOT’s Task Force will submit its final report to DOE by June 2013. In addition, the Obama
Administration is attempting to expedite the construction of seven backbone transmission
projects with the formation of the Rapid Response Team for Transmission which seeks tostreamline federal permitting and improve cooperation among federal, state, and tribal
governments. The proposed projects include over 3,100 miles of new transmission lines spread
across 12 states.
Finally, numerous transmission projects have been planned, in part, to accommodate the growthof wind energy throughout the country. Examples of some of these projects are described below.
62
2011 Wind Technologies Market Report

•
•

•

Construction began on the first segment of the Michigan Thumb Loop Transmission Projectin early 2012. Once completed in 2015, the 140-mile transmission project will transport
wind energy to load centers in Michigan.
Duke-American Transmission Company, a joint venture between Duke Energy andAmerican Transmission Company, announced plans to invest about $4 billion in seventransmission projects in five Midwestern states. Also, in late 2011, DATC acquired the 500kV Zephyr transmission line project, which could transmit 3,000 MW of renewable energy
between Wyoming and southern Nevada if completed in 2020, four years later than theoriginal planned in-service date.
Los Angeles Department of Water and Power’s proposed Barren Ridge Renewable
Transmission Project is expected to provide 1,100 MW of transmission capacity to transport
wind and solar resources from the Tehachapi Mountains and Mojave Desert to the San
Fernando Valley. The draft environmental analysis documents were released for public
review in August 2011. Assuming the project proceeds, construction will begin in 2013,
with a target in-service date of 2016.

Though a number of transmission projects have progressed, others have been delayed or scaled
back. Due to a lowered demand forecast, for example, Xcel Energy dropped a transmission
project that would have allowed up to 1,500 MW of renewable energy to be transported from the
San Luis Valley to the Denver metropolitan area. In 2012, PacifiCorp announced plans to scaleback the Energy Gateway Transmission Project.

Integrating Wind Energy into Power Systems Is Manageable, but Not Freeof Costs, and System Operators Are Implementing Methods to
Accommodate Increased Penetration
There has been a considerable amount of attention paid to the potential impacts of wind energy
on power systems in recent years. Concerns about, and solutions to, these issues have affected,
and continue to impact, the pace of wind power deployment in the United States. Experience inoperating power systems with wind energy is also increasing worldwide (Jones 2011).
Figure 39 provides a selective listing of estimated wind integration costs 75 and Figure 40
summarizes the estimated increase in balancing reserves 76 associated with increased wind energy
from integration studies completed from 2003 through 2011 at various levels of wind power75

The integration costs considered in these studies typically refer to the costs associated with accommodating thevariability and uncertainty associated with wind energy. Generally, these costs are associated with three different
time frames: regulation – from seconds to a few minutes; load-following – tens of minutes to a few hours; and unit
commitment – out to the next day or two. Studies often, but not always, estimate these costs as the difference inoverall electric system production costs between a scenario that captures the variability and unpredictability of windenergy and a scenario with an energy-equivalent block of power having no variability or uncertainty.
76
In general, these balancing reserves reflect the resources required to maintain system balance between schedules.
Often studies have balancing reserve requirements that change depending on the level of wind electricity generationor the time of day (Ela et al. 2011). The balancing reserves in the figure represent either the average reserves or the
maximum increase in reserves depending on which statistics are reported by the study authors.

632011 Wind Technologies Market Reportcapacity penetration. 77,78 System operators use reserves to balance variability and uncertainty
between scheduling periods, and scheduling periods vary, so Figure 40 separates balancing
reserves by the duration of the scheduling period assumed in the study. Regions with fast energy
markets, for example, change the schedule of dispatchable generators over 5-minute periods
while other regions often use hourly schedules. 79 Because methods vary and a consistent set ofoperational impacts has not been included in each study, results from the different analyses ofintegration costs (Figure 39) and balancing reserves (Figure 40) are not fully comparable. Notealso that the rigor with which the various studies have been conducted varies, as does the degreeof peer review. Finally, there has been some recent literature questioning the methods used toestimate wind integration costs and the ability to explicitly disentangle those costs, while also
highlighting potential integration costs associated with other generation options (Milligan et al.,2011).

[a] Costs in $/MWh assume 31% capacity factor.
[b] Costs represent 3-year average.
[c] Highest over 3-year evaluation period.
[d] Higher cost line adds the coal cycling costs found in Xcel Energy (2011).
Sources: Acker (2007) [APS (2007)]; EnerNex Corp. (2007) [Avista (2007)]; BPA (2009); BPA (2011c); Shiu et al. (2006) [CA RPS(2006)]; EnerNex Corp (2010) [EWITS (2010)]; EnerNex Corp. and Idaho Power Co. (2007) [Idaho Power (2007)]; EnerNex Corp.
and WindLogics Inc. (2006) [MN-MISO (2006)]; EnerNex et al. (2010) [Nebraska (2010)]; PacifiCorp (2005); PacifiCorp (2007);
PacifiCorp (2010); PGE and EnerNex Corp.(2011) [Portland GE (2011)]; Puget Sound Energy (2007); EPRI (2011) [SPP-SERC(2011)]; Electrotek Concepts, Inc. (2003) [We Energies (2003)]; EnerNex Corp. and WindLogics, Inc. (2004) [Xcel-MNDOC (2004)];
EnerNex Corp. (2006) [Xcel-PSCo (2006)]; EnerNex Corp. (2008) [Xcel-PSCo (2008)]; Xcel Energy and EnerNex Corp. (2011)[Xcel-PSCo (2011)]; Brooks et al. (2003) [Xcel-UWIG (2003)]

Figure 39. Integration Costs at Various Levels of Wind Power Capacity Penetration

77

Wind power penetration on a capacity basis (defined as nameplate wind power capacity serving a region divided
by that region’s peak electricity demand) was frequently used in earlier integration studies. For a given amount ofwind power capacity, penetration on a capacity basis is typically higher than the comparable wind penetration inenergy terms (because, over the course of a year, wind power projects generally operate at a lower percentage of
their rated capacity, on average, than does aggregate load).
78
Some studies address capacity valuation for resource adequacy purposes; those results are not presented here.
79
Over half the load in the U.S. is now in regions with 5-minute scheduling: PJM, MISO, ERCOT, NYISO, ISONE, and CAISO.

64
2011 Wind Technologies Market Report

[a] Includes some solar energy in addition to wind energy.
[b] 3-year average.
[c] Small, isolated island system.
Sources: See Figure 39; GE (2007) [CA IAP (2007)] ; CAISO (2007); CAISO (2010); GE (2008) [ERCOT (2008)]; GE (2010a) [ISONE (2010)]; GE (2005) [New York (2005)]; NYISO (2010); Shoucri (2011) [Northwestern (2011)]; GE (2011a) [Oahu (2011)];
Charles River Associates (2010) [SPP(2010)]; GE (2010b) [WWSIS (2010)]

Figure 40. Incremental Balancing Reserves at Various Levels of Wind Power Capacity
Penetration

In addition to balancing reserve requirements and wind integration costs, these and other studies
have also focused on identifying the required changes to existing practices in power system
operations, the role of forecasting, and the capability of thermal and hydropower generators toprovide the needed flexibility to integrate wind power. A sizable portion of these studies havebeen conducted by or commissioned by RTOs and ISOs (e.g. CAISO, ERCOT, SPP, New York
Independent System Operator (NYISO), and Independent System Operator – New England(ISO-NE); PJM is currently conducting an integration study that is expected to be complete in2013). Key conclusions that continue to emerge from the growing body of integration literatureinclude the following:•

Wind integration costs estimated by all studies reviewed are below $12/MWh – and often
below $5/MWh – for wind power capacity penetrations of up to and even exceeding 40% of
the peak load of the system in which the wind power is delivered. 80 Variations in estimatedcosts across studies are due, in part, to differences in methodologies, definitions of

80

These integration cost estimates compare to levelized wind PPA prices that ranged from $25/MWh to $60/MWhamong contracts signed in 2011 (as shown earlier in Figure 34). The relatively low integration cost estimates in the2006 Minnesota study and the 2010 Nebraska study, despite aggressive levels of wind power penetration, are partly
a result of relying on the broader regional electricity market to accommodate certain elements of integrating windenergy into system operations. Conversely, the higher integration costs found by Avista, Idaho Power, andPacifiCorp, and Portland General Electric are, in part, caused by the relatively smaller markets in which the windenergy is being absorbed and by those utilities’ operating practices. Specifically, the Northwest currently uses
hourly scheduling intervals rather than the sub-hourly markets common in ISOs and RTOs. A sensitivity case in theAvista Utilities study demonstrates that the use of a 10-minute transaction scheduling interval would decrease thecost of integrating wind energy by 40-60%.

65
2011 Wind Technologies Market Report

•
•

•

•

integration costs, power system and market characteristics, wind energy penetration levels,
fuel price assumptions, and the degree to which thermal power plant cycling costs areincluded.
Larger balancing areas, such as those found in RTOs and ISOs, make it possible to integrate
wind energy more easily and at lower cost than is the case in smaller balancing areas.
Coordination among smaller balancing areas can reduce the cost of wind integration.
The successful use of wind power forecasts by system operators can significantly reduce
integration challenges and costs. Intra-hour transmission scheduling and generator dispatch(e.g., 5-minute scheduling and dispatch) provides access to flexibility in conventional power
plants that, among other benefits, lowers the costs of integrating wind energy.
Thermal plant cycling costs are increasingly being highlighted and may contribute to thecosts and challenges associated with integrating wind. Among other studies of cycling costs,
the Western Wind and Solar Integration Study Phase II and the PJM wind integration study,
both due to be completed within the next year, will include an assessment of cycling costs.
Strategies for mitigating thermal plant damages associated with cycling should be
investigated further.
The increase in balancing reserves with increased wind power penetration is projected to be
typically less than 15% of the nameplate capacity of wind power and often considerably lessthan this figure, particularly in studies that use intra-hour scheduling. The high balancing
reserve finding in the NorthWestern study (Shoucri 2011) reflects the issues with hourlyscheduling and small balancing areas. A number of studies indicate that the amount ofbalancing reserves needed at any particular time changes with different wind and loadconditions. Setting dynamic balancing reserve requirements that respond to these changes in
conditions can lower integration costs.

ISOs and utilities are continuing to take important steps to mitigate the challenges faced withintegrating larger quantities of wind energy.
•••

Centralized wind energy forecasting systems are currently in place in all ISO/RTOs except
ISO-NE where it is scheduled to become operational by the start of 2013. A large number ofelectric utilities are also now using centralized wind forecasting in their operations (Rogers
and Porter, 2011; Porter and Rogers, 2012). Wind forecasting was identified to be a key
prerequisite to successful integration of wind into power system operations in a worldwide
survey of grid operators that together currently manage over 141 GW of wind (Jones 2011).
In 2011, FERC conditionally approved a Midwest ISO proposal to implement Look Ahead
Commitment that every 15-minutes automatically evaluates the need to commit additional
quick-start power plants over the next few hours based on current conditions and near-term
forecasts of load, wind, and scheduled interchanges (FERC 2012a).
CAISO also sought FERC approval to include a Flexible Ramp Constraint in its tariff and isfurther developing a Flexible Ramping Product (FERC 2011d). CAISO is proposing tocommit a certain amount of additional generation capability during early stages of themarket, based on estimates of potential short-term variability and uncertainty, to then be used
to balance the system in later stages of the market. For example, some additional generation
capability will be committed in the day-ahead market so that the additional generation
capability will be available for balancing in the real-time market. Similarly, the CAISO will
set aside generation in one real-time dispatch interval in order to ensure that adequate
66
2011 Wind Technologies Market Report••resources will be available to be dispatched in subsequent dispatch intervals. The ramping
product differs from standard reserves in that the additional generation that is set aside in one
energy market interval is then released to be dispatched in a later energy market interval,
whereas reserves are not generally meant to be dispatched as part of the energy market(CAISO 2012a).
Intra-hour scheduling pilots began for several balancing authorities in the West, and intrahour scheduling changes (primarily half-hour changes) are increasingly being used, thoughpractices are not yet fully standardized among balancing areas. A platform to enable fasterbilateral transactions, the Intra-hour Transaction Accelerator Platform (I-TAP), also launchedin 2011. Inter-regional interchange scheduling on a sub-hourly basis between different
organized markets is similarly under investigation within the Eastern Interconnection.
An energy imbalance market for the Western Interconnection, with many similarities to the
SPP imbalance market, was proposed and, if developed, would provide a sub-hourly, realtime energy imbalance market providing centralized, automated, interconnection-wide
generation dispatch within the Western Interconnection (WECC 2010). Studies show
benefits – due in part to a reduction in balancing reserves – and costs that depend on the waythat the energy imbalance market is implemented (WECC 2011). Two low-cost options
would leverage the existing structure and expertise of either SPP or the CAISO to implement
and operate parts of the energy imbalance market.

Some utilities are now directly charging wind power projects for balancing services. 81 BPA, forexample, includes a wind energy balancing charge in its transmission tariff equivalent to about$5.40/MWh. The charge for wind energy that participates in BPA's Committed Intra-hour
Scheduling Pilot program in which wind generators submit schedules every half-hour rather thanevery hour is reduced to about $3.60/MWh. More frequent scheduling by wind resources in thepilot program allows BPA to reduce its balancing reserve requirement and the savings are passedon as a decreased wind balancing rate (BPA 2011). FERC has also approved a higher generator
regulation and frequency response services charge for wind energy in the Westar Energybalancing area, equivalent to about $0.7/MWh; this interim tariff will be in place until it isrendered unnecessary through the anticipated implementation of an ancillary services market andbalancing authority area consolidation in SPP (FERC 2010). 82 Puget Sound Energy (PSE)
proposed an increase in Regulation and Frequency Response Service that charges a higher rate
for wind energy exporting from the PSE balancing area: the resulting charge would be about$9.5/MWh and is based on an hourly scheduling assumption. The general changes to the rateschedule were conditionally accepted by FERC, although the methodology and resulting charge
are still being sorted out through a settlement hearing at FERC (FERC 2011f).
Similar charges to recover costs associated with regulation will continue to be evaluated on acase-by-case basis by FERC according to the decision on integrating variable energy resources inOrder 764 (FERC 2012b). The decision does require that scheduling at 15-min intervals be
81

In addition, Idaho Power, Avista, and PacifiCorp all discount their published avoided cost payments for qualifying
wind power projects in Idaho by an integration rate that ranges from 7-9% of the avoided cost rate, up to$6.50/MWh (IPUC 2010). In early 2011, however, the Idaho PUC reduced the maximum size of a qualifying wind
power facility from 10 MW to 100 kW. Projects larger than 100 kW will need to directly negotiate individual
project PPA prices rather than obtaining the published avoided cost rate.
82
The rate was revised from about $0.8/MWh in 2010 to $0.7/MWh in 2011 based on an error in the methodology
Westar used in its 2010 estimate of the cost of providing the service (FERC 2011e).

67
2011 Wind Technologies Market Reportoffered to transmission customers and that variable energy resources provide data to be used in
production forecasting to the transmission provider. FERC therefore provided guidance that thedesign of any generator regulation charges should account for the use of intra-hour schedulingand production forecasts when determining quantities of regulation service. Furthermore, any
regulation charge that differs across customer classes must take into account any diversity
benefits from aggregating several customer classes with different variability patterns. The
transmission provider must demonstrate that any difference in regulating reserve responsibilities
across customer classes is due to differences in their operating characteristics.
Finally, a study of the frequency response implications of high renewable penetrations in the
California ISO was completed in 2011 (GE 2011b), following an earlier broad assessment of
frequency response issues for FERC (Eto et al. 2010). The CAISO study found that as long as
adequate secondary reserves (regulation and load following) were available to balance wind andsolar, then even in situations with high instantaneous penetrations of variable generation (50% ofload in California and 25% in the rest of WECC), none of the credible conditions examined leadto stability problems. The results of the CAISO study were generally in agreement with theearlier frequency response study for FERC.

68
2011 Wind Technologies Market Report

8. Future Outlook
Wind power capacity additions in 2011 – at 6,816 MW – fell within the range of market
forecasts (4,450-8,000 MW) presented in last year’s edition of the Wind Technologies Market
Report. Key factors driving growth in 2011 included: continued state and federal incentives forwind energy, recent improvements in the cost and performance of wind power technology, andthe need to meet an end-of-year construction start deadline in order to qualify for the Section
1603 Treasury grant program.
With the Section 1603 grant and federal tax incentives for wind energy currently scheduled to
expire at the end of the year, 2012 is widely expected to be a strong year for new capacity
growth, as wind energy purchasers take advantage of this potentially “limited time only” buying
opportunity that combines federal incentive availability with lower PPA prices (from lower
turbine costs and improved performance), and as developers rush to commission projects before
the expiration of incentives. As a result, with the exception of the EIA (2012) “no sunset”
projection, the remaining forecasts presented in Table 6 predict 2012 additions to range from7,280 MW to 12,000 MW – i.e., in excess of 2011 additions, and perhaps even surpassing theprevious record set back in 2009. With AWEA (2012c) reporting 1,695 MW installed in the firstquarter of 2012, and another 8,900 MW under construction as of the end of the first quarter, theindustry appears to be on track to fall within that forecast range.
Table 6. Forecasts for Annual U.S. Wind Capacity Additions (MW)
2012

2013

2014

EIA (2012)
Bloomberg NEF (2012a)
Navigant (2011)

Assumed Status ofFederal Tax
Incentives After 2012
ExpiredExpiredExpired

7,280
11,200
8,500

1,430
1,000
2,400

600
3,000
2,400

Cumulative
Additions
2012-2014
9,310
15,20013,300EIA (2012)
BTM (2012)
Bloomberg NEF (2012a)*
IHS EER (2012)
MAKE (2012)
Navigant (2011)

Extended Indefinitely
Presumably Extended
Extended – 3 year
Extended – 3+ year
Extended – details n/a
Extended – 4 year

3,230
8,250
11,20012,00010,700
8,500

3,320
7,500
3,100
1,200
3,800
7,500

580
9,000
5,500
6,050
4,600
8,000

7,130
24,75019,80019,25019,10024,000Source*Assumes extension occurs in Q1 2013

Projections for 2013 and beyond are much less certain, but generally show lower wind power
capacity additions. Besides the possible expiration of federal incentives at the end of 2012, otherchallenges include: continued low natural gas and wholesale electricity prices; inadequatetransmission infrastructure in some areas; modest electricity demand growth; existing statepolicies that are insufficient to support future wind power capacity additions at the levels

69
2011 Wind Technologies Market Reportwitnessed in recent years; 83 and growing competition from solar energy in certain regions of thecountry. Industry hopes for a federal renewable or clean energy standard, or climate legislation,
have also dimmed in the near term.
Given this challenging, but also uncertain, outlook, it is not surprising that forecasts for 2013 andbeyond – as shown in Table 6 – span a particularly wide range, depending in large measure on
assumptions about the possible extension of federal incentives. In a scenario with no PTC
extension, for example, Bloomberg NEF (2012a) predicts a precipitous drop in wind power
installations, with perhaps only 1,000 MW installed in 2013. BTM (2012), on the other hand,presumably assumes an extension of federal support, leading to relatively stable wind power
additions from 2012 to 2014. Even with a PTC extension, however, most predictions are formore-modest wind power additions in the near term as the development pipeline takes time torecharge and considering the other challenges impacting the wind industry; this may beespecially true if a longer term extension is achieved, as industry participants will then not needto rush to meet yet-another near-term expiration threat.
Regardless of future uncertainties, wind power capacity additions over the past several years, aswell as the additions predicted for 2012, have put the United States on a trajectory that may leadto 20% of the nation’s electricity demand coming from wind energy by 2030 (see Figure 41). In
May 2008, the U.S. Department of Energy, in collaboration with its national laboratories, thewind power industry, and others, published a report that analyzed the technical and economic
feasibility of achieving 20% wind energy penetration by 2030 (DOE 2008). In addition tofinding no insurmountable barriers to reaching 20% wind energy penetration, the report also laidout a potential wind power deployment path that started at 3.3 GW/year in 2007, increasing to
4.2 GW/year by 2009, 6.4 GW/year by 2011, 9.6 GW/year by 2013, 13.4 GW/year by 2015, androughly 16 GW/year by 2017 and thereafter, yielding cumulative wind power capacity of 305
GW by 2030. Historical growth over the last six years puts the United States on a trajectory
exceeding this deployment path, a trend that is anticipated to continue in 2012. Nonetheless, allof the projections for annual capacity additions in 2013 and 2014 – even those that assume PTC
extension (as denoted by the green, rather than red, circles in Figure 41) – fall short of the annual
growth envisioned in the 20% wind energy report for those years, suggesting that there is a veryreal risk that the market will not grow rapidly enough to maintain a long-term trajectory
consistent with a 20% wind energy penetration level by 2030.

83

Utilities have signed numerous PPAs with projects expecting 2012 online dates – in some cases for more windenergy than is strictly needed to comply with near-term RPS targets – while PPA availability for projects to be built
in 2013 and later has all but dried up as purchasers await federal tax clarity (Bloomberg NEF 2012c).

70
2011 Wind Technologies Market Report

16

280

14

245

12

210

10

175

8

140

6

105

4

Deployment Path in 20% Wind Report (annual)2

Deployment Path in 20% Wind Report (cumulative)

2030

2029

2028

2027

2026

2025

2024

2023

2022

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

2009

2008

Actual Wind Installations (cumulative)

2007

0

70

Actual Wind Installations (annual)

2006

Annual Capacity (GW)

315

range of annual projections(green = PTC extension, red = no extension)

Cumulative Capacity (GW)

18

35
0

Source: DOE (20% wind scenario); AWEA (historical additions): Table 6 (projected additions)Figure 41. Wind Power Capacity Growth: 20% Wind Report, Actual Installations,
Projected Growth

Ramping up to the annual installation rate of roughly 16 GW per year needed for wind power tocontribute 20% of the nation’s electricity by 2030, and maintaining that rate for a decade, would
be a challenging task. This rate of deployment has not yet been witnessed in the U.S. market,
and is not expected to be achieved in the near term, due to uncertainty in federal policy towards
wind energy after 2012, market expectations for continued low natural gas prices, slow growth inelectricity demand, and uncertainty surrounding future environmental regulations to limit carbon
emissions.
In addition to stable long-term promotional policies, the DOE (2008) report suggests four otherareas where supportive actions may be needed in order to reach such annual installation rates.
First, the nation will need to invest in significant amounts of new transmission infrastructure
designed to access remote wind resources. Second, to more-effectively integrate wind power
into electricity markets, larger power control regions, better wind forecasting, and increased
investment in fast-responding generating plants will be required. Third, siting and permitting
procedures will need to be designed to allow wind power developers to identify appropriate
project locations and move from wind resource prospecting to construction quickly. Finally,enhanced research and development efforts in both the public and private sector will be required
to lower the cost of offshore wind power, and incrementally improve conventional land-based
wind energy technology.

71
2011 Wind Technologies Market ReportAppendix: Sources of Data Presented in this Report
Installation Trends
Data on wind power additions in the United States come from AWEA, though methodologicaldifferences noted throughout this report result in some discrepancies in the data presented here
relative to AWEA (2012a). Annual wind power capital investment estimates derive frommultiplying these wind power capacity data by weighted-average capital cost data, provided
elsewhere in the report. Data on non-wind electric capacity additions come primarily from EIA(for years prior to 2011) and Ventyx’s Velocity database (for 2011), except that solar data comefrom the Interstate Renewable Energy Council (IREC) and SEIA/GTM (Solar Energy Industries
Association / GTM Research). Information on offshore wind power development activity in the
United States was compiled by Navigant.
Global cumulative (and 2011 annual) wind power capacity data come from BTM (2012), but arerevised to include the U.S. wind power capacity used in the present report. Wind energy as apercentage of country-specific electricity consumption is based on year-end wind power capacity
data and country-specific assumed capacity factors that come primarily from BTM (2012), as
revised based on a review of EIA country-specific wind power data. For the United States, theperformance data presented in this report are used to estimate wind energy production. Countryspecific projected wind generation is then divided by country-specific electricity consumption:
the latter is estimated based on actual consumption in 2009 and earlier, escalated at a countryspecific growth rate (assumed to be the same as the rate of growth from 2007 through 2009) toestimate 2010-2012 consumption (these data come from EIA).
The wind power project installation map was created by NREL, based in part on AWEA’s
database of projects and in part on data from Ventyx’s Velocity database on the location ofindividual projects. Estimated wind energy as a percentage contribution to statewide electricity
generation is based on AWEA installed capacity data for the end of 2011 and the underlying
wind power project performance data presented in this report. Where necessary, judgment wasused to estimate state-specific capacity factors. The resulting state wind generation is thendivided by in-state total electricity generation in 2011, based on EIA data. Actual state-level
wind energy penetration figures for 2011 are derived from EIA data.
Data on wind power capacity in various interconnection queues come from a review of publicly
available data provided by each ISO, RTO, or utility. Only projects that were active in the queueat the end of 2011, but that had not yet been built, are included. Suspended projects are notincluded in these listings. Data on projects that are in the nearer-term development pipeline
come from Ventyx (2012) and other sources.
Industry Trends
Turbine manufacturer market share and average turbine size are derived from the AWEA wind
power project database, with some processing by Berkeley Lab. Information on turbine hubheights and rotor diameters were compiled by Berkeley Lab based on information provided byturbine manufacturers, standard turbine specifications, Federal Aviation Administration data,
web searches, and other sources.
72
2011 Wind Technologies Market Report

Information on wind turbine and component manufacturing come from NREL, AWEA, andBerkeley Lab, based on a review of press reports, personal communications, and other sources.
Data on U.S. nacelle assembly capacity came from Bloomberg NEF (2012a). The listings ofmanufacturing and supply chain facilities are not intended to be exhaustive. Data on aggregate
U.S. imports and exports of wind power equipment come primarily from the U.S. International
Trade Commission (USITC), and can be obtained from the USITC’s DataWeb(http://dataweb.usitc.gov/).
Information on wind power financing trends was compiled by Berkeley Lab. Wind project
ownership and power purchaser trends are based on a Berkeley Lab analysis of the AWEA
project database.
Cost, Performance and Pricing Trends
Wind turbine transaction prices were compiled by Berkeley Lab. Sources of transaction pricedata vary, but most derive from press releases, press reports, and Securities and Exchange
Commission filings. In part because wind turbine transactions vary in the services offered, agood deal of intra-year variability in the cost data is apparent.
Berkeley Lab used a variety of public and some private sources of data to compile capital cost
data for a large number of U.S. wind power projects. Data sources range from pre-installation
corporate press releases to verified post-construction cost data. Specific sources of data include:
EIA Form 412, FERC Form 1, various Securities and Exchange Commission filings, various
filings with state public utilities commissions, Windpower Monthly magazine, AWEA’s Wind
Energy Weekly, DOE/EPRI’s Turbine Verification Program, Project Finance magazine, various
analytic case studies, and general web searches for news stories, presentations, or informationfrom project developers. For 2009-2011 projects, data from the Section 1603 Treasury Grant
program were used extensively. Some data points are suppressed in the figures to protect data
confidentiality. Because the data sources are not equally credible, little emphasis should beplaced on individual project-level data; instead, it is the trends in those underlying data that offer
insight. Only wind power cost data from the contiguous lower-48 states are included.
Wind project operations and maintenance costs come primarily from two sources: EIA Form
412 data from 2001-2003 for private power projects and projects owned by POUs, and FERC
Form 1 data for IOU-owned projects. Some data points are suppressed in the figures to protect
data confidentiality.
Wind power project performance data are compiled overwhelmingly from two main sources:
FERC’s Electronic Quarterly Reports and EIA Form 923. Additional data come from FERC
Form 1 filings and, in several instances, other sources. Where discrepancies exist among thedata sources, those discrepancies are handled based on the judgment of Berkeley Lab staff. Dataon curtailment are from ERCOT (for Texas), MISO (for the Midwest), Xcel Energy (for its
Northern States Power, Public Service Company of Colorado, and Southwestern Public Service
Company subsidiaries), and from BPA (for the Northwest).
The following procedure was used to estimate the quality of the wind resource in which windprojects are located. First, the location of individual wind turbines and the year in which those73
2011 Wind Technologies Market Reportturbines were installed were identified using FAA Digital Obstacle (i.e., obstruction) files(accessed via Ventyx’ Intelligent Map) and LBNL data on individual wind projects. Second,
NREL used data from AWS Truepower – specifically, gross capacity factor estimates with a
200-meter resolution – to estimate the quality of the local wind resource at an 80 meter hub
height for each of those turbines. These gross capacity factors are derived from average mappedwind speed estimates, wind speed distribution estimates, and site elevation data, all of which are
run through a standard wind turbine power curve (common to all sites). Third, using theresultant average wind resource quality (i.e., gross capacity factor) estimate for turbines installedin the 1998-99 period as the benchmark, and assigning that period an index value of 100 percent,comparative percentage changes in average wind resource quality for turbines installed after
1998-99 are calculated. Not all turbines could be mapped by LBNL for this purpose: the final
sample included 25,413 turbines totaling 41,230 MW of capacity installed from 1998 through2011, or 90% of all wind power capacity installed in the continental United States over that
period.
Wind power price data are based on multiple sources, including prices reported in FERC’s
Electronic Quarterly Reports, FERC Form 1, avoided cost data filed by utilities, pre-offeringresearch conducted by bond rating agencies, and a Berkeley Lab collection of power purchaseagreements. Wholesale electricity price data were compiled by Berkeley Lab from theIntercontinentalExchange (ICE) as well as Ventyx’s Velocity database (which itself derives
wholesale price data from the ICE and the various ISOs). Earlier years’ wholesale electricity
price data come from FERC (2007, 2005). Pricing hubs included in the analysis, and within eachregion, are identified in the map below. REC price data were compiled by Berkeley Lab basedon information provided by Evolution Markets and Spectron.

Maine Zone

Mid-C

•

°

COB

•
•

Mead

• •

Four Corners

SP-15

•

•

•

Mass Hub•NYISO•A ••°Zone • Cinergy Hub •PJM West
Iowa•
Illinois Hub •
DOM°
Zone
°Zone
Missouri

WAUE Interface

NP-15

°

Minnesota Hub

NI HubMichigan Hub

NYISO G

Palo Verde• ERCOT•Entergy

Northwest
California
Mountain
Texas
Heartland
Great Lakes
East
New EnglandSoutheast

Note: The pricing nodes represented by an open, rather than closed, bullet do not have complete pricing history back through 2003.

Map of Regions and Wholesale Electricity Price Hubs Used in Analysis
74
2011 Wind Technologies Market ReportPolicy and Market Drivers
The wind energy integration, transmission, and policy sections were written by staff at Berkeley
Lab and Exeter Associates, based on publicly available information.
Future Outlook
This section was written by staff at Berkeley Lab, based largely on publicly available
information.

75
2011 Wind Technologies Market ReportReferences
3TIER. 2012. 3TIER Releases 2011 Wind Performance Map. Press Release, January 18, 2012.
Acker, T. 2007. Arizona Public Service Wind Integration Cost Impact Study. Prepared for
Arizona Public Service Company. Flagstaff, Arizona: Northern Arizona University.
American Wind Energy Association (AWEA). 2012a. AWEA U.S. Wind Industry Annual Market
Report: Year Ending 2011. Washington, D.C.: American Wind Energy Association.
American Wind Energy Association (AWEA). 2012b. 2011 U.S. Small Wind Turbine Market
Report. Washington, D.C.: American Wind Energy Association.
American Wind Energy Association (AWEA). 2012c. AWEA U.S. Wind Industry First Quarter2012 Market Report. Washington, D.C.: American Wind Energy Association.
American Wind Energy Association (AWEA). 2012d. Panel remarks at AWEA Wind Financeand Investment Seminar. New York City, April 12-13, 2012.
AWS Truepower. 2012. Wind Trends Bulletin: North America 2011 Q4. March 8, 2012.
Bloomberg New Energy Finance (Bloomberg NEF). 2012a. Q2 2012 North America Wind
Market Outlook. June 8, 2012.
Bloomberg New Energy Finance (Bloomberg NEF). 2012b. Wind Turbine Price Index, Issue VI:
Margins at Risk. February 8, 2012.
Bloomberg New Energy Finance (Bloomberg NEF). 2012c. H1 2012 US PPA Market Outlook.
March 14, 2012.
Bolinger, M. and R. Wiser. 2011. Understanding Trends in Wind Turbine Prices Over the Past
Decade. LBNL-5119E. Berkeley, Calif.: Lawrence Berkeley National Laboratory.
Bonneville Power Administration (BPA). 2011. 2012 Wholesale Power and Transmission Rate
Adjustment Proceeding: Administrator’s Final Record of Decision. Portland, OR:
Bonneville Power Administration.
Bonneville Power Administration (BPA). 2009. 2010 Wholesale Power and Transmission Rate
Adjustment Proceeding (BPA-10) Administrators Final Record of Decision. Portland, OR:
Bonneville Power Administration.
Brooks, D., E. Lo, R. Zavadil, S. Santoso and J. Smith. 2003. Characterizing the Impact ofSignificant Wind Generation Facilities on Bulk Power System Operations Planning: Xcel
Energy – North Case Study. Prepared for the Utility Wind Integration Group. Arlington,
Virginia: Electrotek Concepts.
BTM Consult – a part of Navigant (BTM). 2012. International Wind Energy Development:
World Market Update 2011. Chicago, Illinois: BTM Consult ApS.
California Independent System Operator (CAISO). 2012a. Flexible Ramping Products Draft
Final Proposal. Folsom, CA: California Independent System Operator.
California Independent System Operator (CAISO). 2012b. 2011-2012 Transmission Plan (Draft
Version). January 31, 2012. Folsom, CA: California Independent System Operator.
California Independent System Operator (CAISO). 2010. Integration of Renewable Resources at
20% RPS. Folsom, California: California Independent System Operator.
76
2011 Wind Technologies Market ReportCalifornia Independent System Operator (CAISO). 2007. Integration of Renewable Resources.
Folsom, California: California Independent System Operator.
Chadbourne & Parke. 2012. “State of the Tax Equity Market.” Project Finance Newswire. May
2012. pp. 28-37.
Charles River Associates. 2010. SPP WITF Wind Integration Study. Little Rock, Arkansas:
Southwest Power Pool.
David, A. 2011. U.S. Wind Turbine Trade in a Changing Environment. WINDPOWER 2011.
Poster Presentation. Anaheim, California. May 23-25, 2011.
David, A. 2010. Impact of Wind Energy Installations on Domestic Manufacturing and Trade.
ID-25. Washington, D.C.: U.S. International Trade Commission.
David, A. 2009. Wind Turbines: Industry and Trade Summary. ITX-02. Washington, D.C.: U.S.
International Trade Commission.
Department of Energy (DOE). 2008. 20% Wind Energy by 2030: Increasing Wind Energy’s
Contribution to U.S. Electricity Supply. DOE/GO-102008-2567. Washington, D.C.: U.S.
Department of Energy.
Eber, J. 2012. Remarks of John Eber (JPMorgan Capital Corporation) during the “Market
Trends” session of the AWEA Wind Finance & Investment Seminar, April 13, 2012.
EDPR. 2012. EDP Renováveis, FY2011 Results. 29 February.
Ela, E., M. Milligan, and B. Kirby. 2011. Operating Reserves and Variable Generation.
NREL/TP-5500-51978. Golden, CO: National Renewable Energy Laboratory.
Electric Power Research Institute (EPRI). 2011. DOE: Integrating Midwest Wind Energy into
Southeast Electricity Markets. Knoxville, TN: Electric Power Research Institute.
Electrotek Concepts, Inc. 2003. Systems Operations Impacts of Wind Generation Integration
Study. Prepared for We Energies. Knoxville, Tennessee: Electrotek Concepts.
Energy Information Administration (EIA). 2012. Annual Energy Outlook 2012. DOE/EIA0383(2012). Washington D.C.: Energy Information Administration.
EnerNex Corp. 2010. Eastern Wind Integration and Transmission Study. NREL/SR-550-47078.
Golden, Colorado: National Renewable Energy Laboratory.
EnerNex Corp. 2008. Wind Integration Study for Public Service of Colorado, Addendum,
Detailed Analysis of 20% Wind Penetration. Prepared for Xcel Energy. Denver, Colorado:
Xcel Energy.
EnerNex Corp. 2007. Final Report Avista Corporation Wind Integration Study. Knoxville,
Tennessee: EnerNex Corporation.
EnerNex Corp. 2006. Wind Integration Study for Public Service Company of Colorado. Prepared
for Xcel Energy. Denver, Colorado: Xcel Energy.
EnerNex Corp. and Idaho Power Co. 2007. Operational Impacts of Integrating Wind Generation
into Idaho Power's Existing Resource Portfolio: Report Addendum. Boise, Idaho: Idaho
Power Company.

77
2011 Wind Technologies Market ReportEnerNex Corp., Ventyx, and Nebraska Power Association. 2010. Nebraska Statewide Wind
Integration Study. NREL/ SR-550-47519. Golden, Colorado: National Renewable Energy
Laboratory.
EnerNex Corp. and WindLogics Inc. 2006. Final Report – 2006 Minnesota Wind Integration
Study, Volume I. Prepared for the Minnesota Public Utilities Commission. Knoxville,
Tennessee: EnerNex Corporation.
EnerNex Corp. and WindLogics Inc. 2004. Wind Integration Study—Final Report. Prepared for
Xcel Energy and Minnesota Department of Commerce. Knoxville, Tennessee: EnerNex
Corporation.
Eto, J., J. Undrill, P. Mackin, R. Daschmans, B. Williams, B. Haney, R. Hunt, et al. 2010. Use of
Frequency Response Metrics to Assess the Planning and Operating Requirements for
Reliable Integration of Variable Renewable Generation. LBNL-4142E. Berkeley,
California: Lawrence Berkeley National Laboratory.
Federal Energy Regulatory Commission (FERC). 2012a. Order Conditionally Accepting Tariff
Filing Re Midwest Independent Transmission System Operator, Inc. Under ER12-923. 138
FERC ¶ 61,227. Docket No. ER12-923. March 29, 2012. Washington D.C.: Federal Energy
Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2012b. Integration of Variable Energy
Resources. 139 FERC ¶ 61,246. Docket No. RM10-11; Order No.764. June 22, 2012.
Washington D.C.: Federal Energy Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2011a. Transmission Planning and Cost
Allocation by Transmission Owning and Operating Public Utilities. 136 FERC ¶ 61,051.
Docket No. RM10-23; Order No.1000. July 21, 2011. Washington D.C.: Federal Energy
Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2011b. Order on Rehearing. 137 FERC ¶61,075. Docket No. ER10-1069. October 20, 2011. Washington D.C.: Federal Energy
Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2011c. Order Denying in Part and Granting inPart Rehearing, Conditionally Accepting Compliance Filing, and Directing Further
Compliance Filings. 137 FERC ¶ 61,074. Docket No. ER10-1791. October 21, 2011.
Washington D.C.: Federal Energy Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2011d. Order Accepting and Suspending
Proposed Tariff Changes and Establishing Hearings and Settlement Judge Procedures.
137 FERC ¶ 61,191. Docket No. ER12-50. December 12, 2011. Washington D.C.: Federal
Energy Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2011e. Order Granting Rehearing in Part,
Denying Rehearing in Part, Instituting Section 206, and Establishing Refund Effective Date
Re Westar Energy, Inc Under ER09-1273. 137 FERC ¶ 61,142. Docket No. EL12-4.
November 17, 2011. Washington D.C.: Federal Energy Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2011f. Order Accepting and Suspending
Proposed Tariff Revisions, Subject to Refund, and Establishing Hearing and Settlement
Judge Procedures Re Puget Sound Energy, Inc Under ER11-3735. 137 FERC ¶ 61,063.
78
2011 Wind Technologies Market ReportDocket No. ER11-3735. October 20, 2011. Washington D.C.: Federal Energy Regulatory
Commission.
Federal Energy Regulatory Commission (FERC). 2010. Order Conditionally Accepting
Proposed Tariff Revisions RE Westar Energy, Inc. under ER09-1273. 130FERC ¶ 61,215.
Washington D.C.: Federal Energy Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2007. 2006 State of the Markets Report.
Washington, D.C.: Federal Energy Regulatory Commission.
Federal Energy Regulatory Commission (FERC). 2005. 2004 State of the Markets Report.
Washington, D.C.: Federal Energy Regulatory Commission.
GE Energy. 2011a. Oahu Wind Integration Study Final Report. Honolulu, Hawaii: University of
Hawaii.
GE Energy. 2011b. California ISO Frequency Response Study. Schenectady, NY: General
Electric International, Inc.
GE Energy. 2010a. New England Wind Integration Study. Holyoke, Massachusetts: ISO New
England Inc.
GE Energy. 2010b. Western Wind and Solar Integration Study. NREL/SR-550-47434. Golden,
Colorado: National Renewable Energy Laboratory.
GE Energy. 2008. Analysis of Wind Generation Impact on ERCOT Ancillary Services
Requirements. Prepared for the Electricity Reliability Council of Texas. Schenectady, New
York: GE Energy.
GE Energy. 2007. Intermittency Analysis Project Appendix B: Impact of Intermittent Generation
on Operation of California Power Grid. Sacramento, California: California Energy
Commission, PIER Research Development & Demonstration Program.
GE Energy. 2005. The Effects of Integrating Wind Power on Transmission System Planning,
Reliability, and Operations: Report on Phase 2. Prepared for the New York State Energy
Research & Development Authority. Schenectady, New York: GE Energy.
Idaho Public Utilities Commission (IPUC). 2010. In the Matter of the Petition of Pacificorp dba
Rocky Mountain Power for an Order Revising the Wind Integration Rate for Wind Powered
Small Power Generation Qualifying Facilities. PAC-E-09-07 Order No. 31021. March 12,
2010.
IHS Emerging Energy Research (IHS EER). 2012. Personal communication with Matthew
Kaplan.
Infigen. 2012. Infigen Energy, Interim Result: 6 months ended 31 December 2011. 28 February.
Infigen. 2011. Infigen Energy, Full Year Result: 12 months ended 30 June 2011. 30 August.
Jones, L. E. 2011. Strategies and Decision Support Systems for Integrating Variable Energy
Resources in Control Centers for Reliable Grid Operations. Washington, D.C.: Alstom
Grid.
MAKE Consulting. 2012. Capitalizing on Turbine Technology Trends: Innovation Opportunities
for US Suppliers. Presentation to WINDPOWER 2012. 4 June. Atlanta, Georgia.

79
2011 Wind Technologies Market ReportMilligan, M., E. Ela, B.M. Hodge, B. Kirby, D. Lew, C. Clark, J. DeCesaro, and K. Lynn. 2011.
“Integration of Variable Generation, Cost-Causation, and Integration Costs.” The
Electricity Journal 24 (9): 51–63.
Navigant. 2011. Impact of the Production Tax Credit on the U.S. Wind Market. Prepared for theAmerican Wind Energy Association. December 12, 2011.
New York Independent System Operator (NYISO). 2010. Growing Wind: Final Report of the
NYISO 2010 Wind Generation Study. Rensselaer, New York: New York Independent
System Operator.
North American Electric Reliability Corporation (NERC). 2011. 2011 Long-Term Reliability
Assessment. November 2011
PacifiCorp. 2010. 2010 Wind Integration Study. Portland, Oregon: PacifiCorp.
PacifiCorp. 2007. Technical Appendix for the 2007 Integrated Resource Plan. Portland, Oregon:
Pacificorp.
PacifiCorp. 2005. Technical Appendix for the 2004 Integrated Resource Plan. Portland, Oregon:
PacifiCorp.
Pfeifenberger, J. 2012. Modernizing America’s Grid: How can better planning deliver the grid
we need? January 23, 2012. Presentation to the New England Clean Energy Transmission
Summit, Boston.
Porter, K., and J. Rogers. 2012. Survey of Variable Generation Forecasting in the West: August
2011 - June 2012. NREL SR-5500-54457. Golden, CO: National Renewable Energy
Laboratory.
Portland General Electric and EnerNex Corp. 2011. PGE Wind Integration Study Phase II.
Portland, OR: Portland General Electric.
Public Utility Commission of Texas (PUCT). 2012. CREZ Progress Report No. 6 (January
Update). January 2012. Prepared by RS&H.
Puget Sound Energy. 2007. 2007 Integrated Resource Plan, Appendix G-Wind Integration
Studies. Bellevue, Washington: Puget Sound Energy.
Rogers, J., and K. Porter. 2011. Wind Power and Electricity Markets. Reston, VA: Utility Wind
Integration Group.
Shiu, H., M. Milligan, B. Kirby and K. Jackson. 2006. California Renewables Portfolio Standard
Renewable Generation Cost Analysis: Multi-Year Analysis Results and Recommendations.
Consultant report prepared by the California Wind Energy Collaborative. Sacramento,
California: California Energy Commission.
Shoucri, A. 2011. NorthWestern Energy Montana Wind Integration Study. Calgary, AB:
GENIVAR.
Southwest Power Pool (SPP). 2010a. Submission of Tariff Revisions to Modify Transmission
Cost Allocation Methodology. Docket No. ER10-1069-000.
Southwest Power Pool (SPP). 2010b. SPP Approves Construction of New Electric Transmission
Infrastructure To Bring $3.7 Billion in Regional Benefits. April 27, 2010.
United States Department of Energy, Office of Inspector General, Office of Audits andInspections. 2011. Management Alert: Western Area Power Administration’s Control and80
2011 Wind Technologies Market ReportAdministration of American Recovery and Reinvestment Act Borrowing Authority.
November 2011.
Ventyx. 2012. Velocity Suite Data Product. Accessed June 2012.
Western Electricity Coordinating Council (WECC). 2011. WECC Efficient Dispatch Toolkit
Cost-Benefit Analysis. Salt Lake City, UT: Western Electricity Coordinating Council.
Western Electricity Coordinating Council (WECC). 2010. Scope of the Efficient Dispatch
Toolkit Cost-Benefit Analysis. Salt Lake City, Utah: Western Electricity Coordinating
Council.
Wyden, R. 2010. U.S. Trade in Environmental Goods: Follow-Up Report to ‘Major
Opportunities and Challenges to U.S. Exports of Environmental Goods.’ Washington,
D.C.: United States Senate.
Xcel Energy. 2011. Wind Induced Coal Plant Cycling Costs and the Implications of Wind
Curtailment for Public Service of Colorado. Denver, CO: Xcel Energy.
Xcel Energy and EnerNex Corp. 2011. Public Service Company of Colorado 2 GW and 3 GWWind Integration Cost Study. Denver, CO: Xcel Energy.

812011 Wind Technologies Market ReportWind Energy Web Sites
U.S. Department of Energy Wind Programwind.energy.gov

Ames Laboratory
www.ameslab.gov

Wind Powering America
www.windpoweringamerica.gov

Los Alamos National Laboratory
www.lanl.gov

Lawrence Berkeley National Laboratory
http://eetd.lbl.gov/EA/EMP/re-pubs.html

Savannah River National Laboratory
http://srnl.doe.gov

National Renewable Energy Laboratory
www.nrel.gov/wind

Brookhaven National Laboratorywww.bnl.gov

Sandia National Laboratories
www.sandia.gov/wind

American Wind Energy Associationwww.awea.org

Paciﬁc Northwest National Laboratory
www.pnl.gov

Database of State Incentives for
Renewables & Efficiency
www.dsireusa.org

Lawrence Livermore National Laboratory
www.llnl.gov
Oak Ridge National Laboratory
www.ornl.gov

International Energy Agency – Wind Agreement
www.ieawind.org
National Wind Coordinating Collaborative
www.nationalwind.org

Argonne National Laboratory
www.anl.gov

Utility Wind Integration Groupwww.uwig.org

Idaho National Laboratorywww.inl.gov

For more information on
this report, contact:
Ryan Wiser, Lawrence Berkeley National Laboratory
510-486-5474; RHWiser@lbl.gov
Mark Bolinger, Lawrence Berkeley National Laboratory
603-795-4937; MABolinger@lbl.gov

On the CoverThe 3-MW Alstom ECO 100 wind turbine installed at the
National Renewable Energy Laboratory’s National Wind
Technology Center near Boulder, Colorado, is part of along-term research and development agreement between
NREL and Alstom.
Photo by Dennis Schroeder, NREL/PIX 18891

eere.energy.gov

DOE/GO-102012-3472 • August 2012

wind.energy.gov
Printed with a renewable-source ink on paper containing atleast 50% wastepaper, including 10% post consumer waste.