For U.S. wind power, the last 12 months was both the best of times and the worst of times. That’s the conclusion from the new Wind Technologies Market Report recently released
by the U.S. Department of Energy (DOE) and prepared by DOE’s Lawrence Berkeley National Laboratory (LBNL). We take a look at the latest trends emerging from America.
Annual wind power capacity additions in the United States were modest in 2013, but all signals point to more-robust growth in 2014 and 2015. With the industry’s primary federal support – the Production Tax Credit (PTC) – only available for projects that had begun construction by the end of 2013, the next couple years will see those projects commissioned. Near-term wind additions will also be driven by recent improvements in the cost and performance of wind power technologies.
At the same time, the prospects for growth beyond 2015 are uncertain.
The PTC has expired, and its renewal remains in question. Continued low natural gas prices, modest electricity demand growth, and limited near-term demand from state renewables portfolio standards (RPS) have also put a damper on industry growth expectations.
These trends, in combination with increasingly global supply chains, continue to impact domestic manufacturing of wind equipment. What they mean for wind power additions through the end of the decade and beyond will be dictated in part by future natural gas prices, fossil plant retirements, and policy decisions.
At the same time, recent declines in wind energy costs and prices and the potential for continued technological advancements have boosted future growth prospects.
Key findings from this year’s report include:
Installation trends
Wind power additions stalled in 2013, with only 1,087 MW of new capacity added in the United States and $1.8 billion invested. Wind power installations in 2013 were just 8% of those seen in the record year of 2012. Cumulative wind power capacity grew by less than 2% in 2013, bringing the total to 61 GW.
Wind power represented 7% of U.S. electric-generating capacity additions in 2013. Overall, wind power ranked fourth in 2013 as a source of new generation capacity, standing in stark contrast to 2012 when it represented the largest source of new capacity in the United States.
The 2013 result is also a notable departure from the six years preceding 2013 during which wind constituted between 25% and 43% of capacity additions in each year. Since 2007, wind power has represented 33% of all U.S. capacity additions, and an even larger fraction of new generation capacity in the Interior (54%) and Great Lakes (48%) regions. Its contribution to generation capacity growth over that period is somewhat smaller in the West and Northeast (both 29%), and considerably less in the Southeast (2%).
The United States fell to sixth place in annual wind additions in 2013, and was well behind the market leaders in wind energy penetration. After leading the world in annual wind power additions from 2005 through 2008, and then narrowly regaining the lead in 2012, in 2013 the United States represented only 3% of global additions. In terms of cumulative capacity, the United States remained the second leading market.
A number of countries are beginning to achieve high levels of wind penetration: end-of-2013 installed wind power is estimated to supply the equivalent of 34% of Denmark’s electricity demand and approximately 20% of Spain, Portugal and Ireland’s demand. In the United States, the wind power capacity installed by the end of 2013 is estimated, in an average year, to equate to nearly 4.5% of electricity demand.
California installed the most capacity in 2013 with 269 MW, while nine states exceed 12% wind energy penetration. New large-scale wind turbines were installed in thirteen states, and Puerto Rico, in 2013. On a cumulative basis, Texas remained the clear leader. Notably, the wind power capacity installed in Iowa and South Dakota supplied 27% and 26%, respectively, of all in-state electricity generation in 2013, with Kansas close behind at more than 19%. In six other states wind supplied between 12% and 17% of all in-state electricity generation in 2013.
No commercial offshore turbines have been commissioned in the United States, but offshore project and policy developments continued in 2013. At the end of 2013, global offshore wind capacity stood at roughly 6.8 GW, with Europe being the primary locus of activity. No commercial offshore projects have been installed in the United States, and the emergence of a U.S. market faces both challenges and opportunities.
Strides continued to be made in the federal arena in 2013, both through the U.S. Department of the Interior’s responsibilities with regulatory approvals (the first competitive leases were issued in 2013) and the U.S. Department of Energy’s (DOE’s) investments in offshore wind energy research and development, including funding for demonstration projects.
Navigant, meanwhile, has identified 14 projects totalling approximately 4.9 GW that are somewhat more advanced in the development process. Two of these have signed power purchase agreements (PPAs), and both sought to commence construction in 2013 in order to qualify for the federal tax credits.
Data from interconnection queues demonstrate that a substantial amount of wind power capacity is under consideration. At the end of 2013, there were 114 GW of wind power capacity within the transmission interconnection queues reviewed for this report. 95% of this capacity is planned for Texas, the Midwest, Southwest Power Pool, PJM Interconnection, the Northwest, the Mountain region, and California. Wind power represented 36% of all generating capacity within these queues at the end of 2013, higher than all other generating sources except natural gas.
In 2013, 21 GW of gross wind power capacity entered the interconnection queues, compared to 42 GW of natural gas and 11 GW of solar. Of note is that the absolute amount of wind, coal, and nuclear power in the sampled interconnection queues has generally declined in recent years, whereas natural gas and solar capacity has increased.
Industry trends
GE captured 90% U.S. market share in a slow 2013. Siemens came in a distant second, with 8% of the 2013 buildout. Globally, Vestas recaptured the mantle of top supplier, while GE dropped to the fifth spot. Chinese turbine manufacturers continue to occupy positions of prominence in the global ratings, with eight of the top 15 spots. To date, however, their growth has been based almost entirely on sales to the Chinese market; Sany was the only Chinese manufacturer to install turbines (just 8 MW) in the United States in 2013.
The manufacturing supply chain experienced substantial growing pains. With recent cost-cutting moves, the profitability of turbine suppliers rebounded in 2013, after a number of years in decline. Five of the 10 turbine suppliers with the largest share of the U.S. market had one or more domestic manufacturing facilities at the end of 2013. Nine years earlier there was only one active utility-scale turbine manufacturer assembling nacelles in the United States.
Domestic nacelle assembly capability stood at roughly 10 GW in 2013, and the United States also had the capability of producing approximately 7 GW of blades and 8 GW of towers annually. Despite the significant growth in the domestic supply chain over the last decade, prospects for further expansion have dimmed. More domestic wind manufacturing facilities closed in 2013 than opened.
Additionally, the entire wind energy sector employed 50,500 full-time workers in the United States at the end of 2013, a deep reduction from the 80,700 jobs reported for 2012. With significant wind installations expected in 2014 and 2015, turbine orders have now rebounded. But, with uncertain demand after 2015, manufacturers have been hesitant to commit additional resources to the U.S. market.
Despite challenges, a growing percentage of the equipment used in U.S. wind power projects has been sourced domestically since 2006-2007. Trade data show that growth in installed wind power capacity has outpaced growth in selected, tracked wind equipment imports since 2006-2007. As a result, a decreasing percentage of the equipment (in dollar-value terms) used in wind power projects has been imported, when focusing on selected trade categories.
When presented as a fraction of total equipment-related wind turbine costs, the combined import share of wind equipment tracked by trade codes (i.e., blades, towers, generators, gearboxes, and wind-powered generating sets) is estimated to have declined from nearly 80% in 2006-2007 to approximately 30% in 2012-2013; the overall import fraction is considerably higher when considering equipment not tracked in wind-specific trade codes.
Domestic content has increased and is relatively high for blades, towers, and nacelle assembly; domestic content is considerably lower for much of the equipment internal to the nacelle. Exports of wind-powered generating sets from the United States have increased, rising from $16 million in 2007 to $422 million in 2013.
The project finance environment held steady in 2013. In a relatively lacklustre year for project finance, both tax equity yields and debt interest rates were essentially unchanged in 2013. Financing activity is likely to pick up in 2014 based on the number of projects with signed power purchase agreements that will need to achieve commercial operations in 2014 and 2015 in order to stay within the PTC safe harbour guidelines provided by the IRS. Investors seem confident that sufficient capital will be available to finance this expansion.
Perhaps the most notable development in 2013 (and persisting into 2014) is that several large project sponsors – including NRG, Pattern, and most recently NextEra – spun off so-called “yieldcos” as a way to raise capital from public equity markets. These “yieldcos” hold a subset of each sponsor’s operating projects, and pay out the majority of cash revenue from long-term electricity sales.
Independent power producers own 95%of the new wind capacity installed in 2013. Moreover, on a cumulative basis considering all wind installed in the United States by the end of 2013, independent power producers (IPPs) own 83% of wind power capacity, while utilities own 15%, with the final 2% owned by entities that are neither IPPs nor utilities (e.g., towns, schools, commercial customers, farmers).
Long-term contracted sales to utilities remained the most common off-take arrangement, but merchant projects may be regaining some favour, at least in Texas. Electric utilities continued to be the dominant off-takers of wind power in 2013, either owning (4%) or buying (70%) power from 74% of the new capacity installed last year.
Merchant/quasi-merchant projects accounted for another 25%, and that share may increase in the next two years as wind energy prices have declined to levels competitive with wholesale market price expectations in some regions, most projects currently under construction will come online this year or next in order to stay within the IRS safe harbour with respect to the PTC, and wind power purchase agreements remain in short supply. On a cumulative basis, utilities own (15%) or buy (54%) power from 69% of all wind power capacity in the United States, with merchant/quasi-merchant projects accounting for 23% and competitive power marketers 8%.
Technology trends
Turbine nameplate capacity, hub height, and rotor diameter have all increased significantly over the long term. The average nameplate capacity of newly installed wind turbines in the United States in 2013 was 1.87 MW, up 162% since 1998-1999. The average hub height in 2013 was 80 meters, up 45% since 1998-1999, while the average rotor diameter was 97 meters, up 103% since 1998-1999.
Growth in rotor diameter has outpaced growth in nameplate capacity and hub height in recent years. Rotor scaling has been especially significant in recent years, and more so than increases in nameplate capacity and hub heights, both of which have seen a modest reversal of the long-term trend in the most recent years. In 2012, almost 50% of the turbines installed in the United States featured rotors of 100 meters in diameter or larger. Though 2013 was a slow year for wind additions, this figure jumped to 75% in that year.
Turbines originally designed for lower wind speed sites have rapidly gained market share. With growth in average swept rotor area outpacing growth in average nameplate capacity, there has been a decline in the average “specific power” i (in W/m2) among the U.S. turbine fleet over time, from 400 W/m2 among projects installed in 1998-1999 to 255 W/m2 among projects installed in 2013.
In general, turbines with low specific power were originally designed for lower wind speed sites. Another indication of the increasing prevalence of lower wind speed turbines is that, in 2012, more than 50% of installations used IEC Class 3 and Class 2/3 turbines; in 2013, based on the small sample of projects installed that year, the percentage increased to 90%.
Turbines originally designed for lower wind speeds are now regularly employed in both lower and higher wind speed sites, whereas taller towers predominate in lower wind speed sites. Low specific power and IEC Class 3 and 2/3 turbines, originally designed for lower wind speeds, are now regularly employed in all regions of the United States, and in both lower and higher wind speed sites.
In parts of the interior region, in particular, relatively low wind turbulence has allowed turbines designed for low wind speeds to be deployed across a wide range of site-specific resource conditions. The tallest towers, on the other hand, have principally been deployed in lower wind resource areas, presumably focused on those sites with higher wind shear.
Performance trends
Trends in sample-wide capacity factors have been impacted by curtailment and inter-year wind resource variability. Wind project capacity factors have generally been higher on average in more recent years (e.g., 32.1% from 2006-2013 versus 30.3% from 2000-2005), but time-varying influences – such as inter-year variations in the strength of the wind resource or changes in the amount of wind power curtailment – have tended to mask the positive influence of turbine scaling on capacity factors in recent years.
Positively, the degree of wind curtailment has declined recently in what historically have been the most problematic areas, as a result of concrete steps taken to address the issue. For example, only 1.2% of all wind generation within ERCOT was curtailed in 2013; this was the lowest level of curtailment in Texas since 2007, and is down sharply from the peak of 17% in 2009.
Competing influences of lower specific power and lower quality wind project sites have left average capacity factors among newly built projects stagnant in recent years, averaging 31 to 34 percent nationwide. Even when controlling for time-varying influences by focusing only on capacity factors in 2013 (parsed by project vintage), it is difficult to discern any improvement in average capacity factors among projects built after 2005 (although the maximum 2013 capacity factors achieved by individual projects within each vintage have increased in the past five years). This is partially attributable to the fact that average “specific power” remained largely unchanged from 2006-2009, before resuming its downward trend from 2010 through 2013.
At the same time, the average quality of the wind resource in which new projects are located has declined; this decrease was particularly sharp – at 15% – from 2009 through 2012, and counterbalanced the drop in specific power. Controlling for these two competing influences confirms this offsetting effect and shows that turbine design changes are driving capacity factors significantly higher over time among projects located within a given wind resource regime.
Regional variations in capacity factors reflect the strength of the wind resource and adoption of new turbine technology. Based on a sub-sample of wind projects built in 2012, average capacity factors in 2013 were the highest in the Interior (38%) and the lowest in the West (26%).
Not surprisingly, these regional rankings are roughly consistent with the relative quality of the wind resource in each region, but also reflect the degree to which each region has, to this point, applied new turbine design enhancements (e.g., turbines with a lower specific power rating, or taller towers) that can boost project capacity factors. For example, the Great Lakes (which ranks second among regions in terms of 2013 capacity factor) has thus far adopted these new designs to a much larger extent than has the West (which ranks last).
Cost trends
Wind turbine prices remained well below levels seen several years ago. After hitting a low of roughly $750/kW from 2000 to 2002, average turbine prices increased to more than $1,500/kW by the end of 2008. Wind turbine prices have since dropped substantially, despite continued technological advancements that have yielded increases in hub heights and especially rotor diameters. Recently announced turbine transactions have often been priced in the $900-$1,300/kW range. These price reductions, coupled with improved turbine technology and more-favourable terms for turbine purchasers, have exerted downward pressure on total project costs and wind power prices.
Reported installed project costs continued to trend lower in 2013. The capacity-weighted average installed project cost within our limited 2013 sample stood at roughly $1,630/kW, down more than $300/kW from the reported average cost in 2012 and down more than $600/kW from the apparent peak in average reported costs in 2009 and 2010.
With just 11 projects totalling 650 MW, however, the 2013 sample size is limited, perhaps enabling a few projects to unduly influence the weighted average. Early indications from a larger sample (16 projects totalling more than 2 GW) of projects currently under construction and anticipating completion in 2014 suggest that capacity-weighted average installed costs are closer to $1750/kW – still down significantly from 2012 levels.
Installed costs differed by project size, turbine size, and region. Installed project costs exhibit some economies of scale, at least at the lower end of the project and turbine size range. Additionally, among projects built in 2013, the windy Interior region of the country was the lowest-cost region.
Operations and maintenance costs varied by project age and commercial operations date. Despite limited data availability, it appears that projects installed over the past decade have, on average, incurred lower operations and maintenance (O&M) costs than older projects in their first several years of operation, and that O&M costs increase as projects age.
Wind power price trends
Wind PPA prices have reached all-time lows. After topping out at nearly $70/MWh for PPAs executed in 2009, the national average levelised price of wind PPAs that were signed in 2013 (and that are within the Berkeley Lab sample) fell to around $25/MWh nationwide – a new low, but admittedly focused on a sample of projects that largely hail from the lowest-priced Interior region of the country.
This new low average price level is notable given that installed project costs have not similarly broken through previous lows and that wind projects increasingly have been sited in lower-quality wind resource areas.
The relative competitiveness of wind power improved in 2013. The continued decline in average levelised wind PPA prices (which embeds the value of federal incentives, including the PTC), along with a bit of a rebound in wholesale power prices, put wind back at the bottom of the range of nationwide wholesale power prices in 2013.
Based on our sample, wind PPA prices are most competitive with wholesale power prices in the Interior region. The average price stream of wind PPAs executed in 2013 also compares favourably to a range of projections of the fuel costs of gas-fired generation extending out through 2040.
Policy and market drivers
Availability of Federal incentives for wind projects built in the near term has helped restart the domestic market, but policy uncertainty persists. In January 2013, the PTC was extended, as was the ability to take the 30% investment tax credit (ITC) in lieu of the PTC. Wind projects that had begun construction before the end of 2013 are eligible to receive the PTC or ITC. These provisions have helped restart the domestic wind market and are expected to spur capacity additions in 2014 and 2015.
With the PTC now expired and its renewal uncertain, however, wind deployment beyond 2015 is also uncertain. On the other hand, the prospective impacts EPA’s proposal regulations to reduce carbon emissions from existing and new power plants may create new markets for wind energy.
State policies help direct the location and amount of wind power development, but current policies cannot support continued growth at recent levels. As of June 2014, RPS policies existed in 29 states and Washington D.C. From 1999 through 2013, 69% of the wind power capacity built in the United States was located in states with RPS policies; in 2013, this proportion was 93%.
However, given renewable energy growth over the last decade, existing RPS programs are projected to require average annual renewable energy additions of just 3-4 GW/year through 2025 (only a portion of which will be from wind), which is well below the average growth rate in wind capacity in recent years, demonstrating the limitations of relying exclusively on RPS programs to drive future deployment.
Solid progress on overcoming transmission barriers continued. Over 3,500 miles of transmission lines came on-line in 2013, a significant increase from recent years. Four transmission projects of particular importance to wind, including the Competitive Renewable Energy Zones project in Texas, were completed in 2013. A decrease in transmission investment is anticipated in 2014 and 2015. Nonetheless, the wind industry has identified 15 near-term transmission projects that – if all were completed – could carry almost 60 GW of additional wind power capacity.
The Federal Energy Regulatory Commission continued to implement Order 1000 in 2013, which requires public utility transmission providers to improve intra- and inter-regional transmission planning processes and to determine cost allocation methodologies for new transmission facilities. Despite this progress, siting, planning, and cost-allocation issues remain key barriers to transmission investment.
System operators are implementing methods to accommodate increased penetration of wind energy. Recent studies show that wind energy integration costs are almost always 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. Two recent integration studies include a detailed assessment of cycling costs.
In both, cycling was found to increase with more renewables, though the associated costs were modest. Studies on frequency response with higher shares of wind highlight technical options to maintain adequate frequency response, including the potential participation of wind plants.
Because federal tax incentives are available for projects that initiated construction by the end of 2013, significant new builds are anticipated in 2014 and 2015. Near-term wind additions will also be driven by the recent improvements in the cost and performance of wind power technologies, leading to the lowest power sales prices yet seen in the U.S. wind sector. Projections for 2016 and beyond are much less certain.
Despite the lower price of wind energy and the potential for further technological improvements and cost reductions, federal policy uncertainty – in concert with continued low natural gas prices, modest electricity demand growth, and the aforementioned slack in existing state policies – may put a damper on growth.
PES would like to thank the U.S. Department of Energy.
For more information, visit:eere.energy.gov/wind.energy.gov
