TODAY’S STUDY: Wind Right Now
2015 Wind Technologies Market Report
Ryan Wiser, Mark Bolinger, et. al., August 2016 (Lawrence Berkeley National Laboratory)
Annual wind power capacity additions in the United States surged in 2015 and are projected to continue at a rapid clip in the coming five years. Recent and projected near-term growth is supported by the industry’s primary federal incentive—the production tax credit (PTC)—as well as a myriad of state-level policies. Wind additions are also being driven by improvements in the cost and performance of wind power technologies, yielding low power sales prices for utility, corporate, and other purchasers. At the same time, the prospects for growth beyond the current PTC cycle remain uncertain: growth could be blunted by declining federal tax support, expectations for low natural gas prices, and modest electricity demand growth.
Key findings from this year’s Wind Technologies Market Report include:
• Wind power additions surged in 2015, with 8,598 MW of new capacity added in the United States and $14.5 billion invested. Supported by favorable tax policy and other drivers, cumulative wind power capacity grew by 12%, bringing the total to 73,992 MW.
• Wind power represented the largest source of U.S. electric-generating capacity additions in 2015. Wind power constituted 41% of all U.S. generation capacity additions in 2015, up sharply from its 24% market share the year before and close to its all-time high. Over the last decade, wind power represented 31% 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 the last decade is somewhat smaller in the West (22%) and Northeast (21%), and considerably less in the Southeast (2%).
• The United States ranked second in annual wind additions in 2015, but was well behind the market leaders in wind energy penetration. A record high amount of new wind capacity, roughly 63,000 MW, was added globally in 2015, yielding a cumulative total of 434,000 MW. The United States remained the second-leading market in terms of cumulative capacity, but was the leading country in terms of wind power production. A number of countries have achieved high levels of wind penetration; end-of-2015 wind power capacity is estimated to supply the equivalent of roughly 40% of Denmark’s electricity demand, and between 20% to 30% of Portugal, Ireland, and Spain’s demand. In the United States, the wind power capacity installed by the end of 2015 is estimated, in an average year, to equate to 5.6% of electricity demand.
• Texas installed the most capacity in 2015 with 3,615 MW, while twelve states meet or exceed 10% wind energy penetration. New utility-scale wind turbines were installed in 20 states in 2015. On a cumulative basis, Texas remained the clear leader, with 17,711 MW. Notably, the wind power capacity installed in Iowa and South Dakota supplied more than 31% and 25%, respectively, of all in-state electricity generation in 2015, with Kansas close behind at nearly 24%. A total of twelve states have achieved wind penetration levels of 10% or higher.
• The first commercial offshore turbines are expected to be commissioned in the United States in 2016 amid mixed market signals. At the end of 2015, global offshore wind capacity stood at roughly 12 GW. In the United States, the 30 MW Block Island project off the coast of Rhode Island will be the first plant to be commissioned, anticipated by the end of 2016. Projects in Massachusetts, New Jersey, Virginia, and Oregon, meanwhile, all experienced setbacks. Strides continued to be made in the federal arena in 2015, both through the U.S. Department of the Interior’s responsibilities in issuing offshore leases, and the U.S. Department of Energy’s (DOE’s) funding for demonstration projects. A total of 23 offshore wind projects totaling more than 16 GW are in various stages of development in the United States.
• Data from interconnection queues demonstrate that a substantial amount of wind power capacity is under consideration. At the end of 2015, there were 110 GW of wind power capacity within the transmission interconnection queues reviewed for this report, representing 31% of all generating capacity within these queues—higher than all other generating sources except natural gas. In 2015, 45 GW of wind power capacity entered interconnection queues (the largest annual sum since 2010), compared to 58 GW of natural gas and 24 GW of solar.
• GE and Vestas captured 73% of the U.S. wind power market in 2015. Continuing their recent dominance as the three largest turbine suppliers to the U.S., in 2015 GE captured 40% of the market, followed by Vestas (33%) and Siemens (14%). Globally, Goldwind and Vestas were the top two suppliers, followed by GE, Siemens, and Gamesa. Chinese manufacturers continued to occupy positions of prominence in the global ratings, with five of the top 10 spots; to date, however, their growth has been based almost entirely on sales in China.
• The manufacturing supply chain continued to adjust to swings in domestic demand for wind equipment. With growth in the U.S. market, wind sector employment reached a new high of 88,000 full-time workers at the end of 2015. Moreover, the profitability of turbine suppliers has rebounded over the last three years. Although there have been a number of recent plant closures, each of the three major turbine manufacturers serving the U.S. market has one or more domestic manufacturing facilities. Domestic nacelle assembly capability stood at roughly 10 GW in 2015, and the United States also had the capability to produce approximately 7 GW of blades and 6 GW of towers annually. Despite the significant growth in the domestic supply chain over the last decade, conflicting pressures remain, such as: an upswing in near- to medium-term expected growth, but also strong international competitive pressures and possible reduced demand over time as the PTC is phased down. As a result, though many manufacturers increased the size of their U.S. workforce in 2015, expectations for significant supply-chain expansion have become more pessimistic.
• Domestic manufacturing content is strong for some wind turbine components, but the U.S. wind industry remains reliant on imports. The U.S. is reliant on imports of wind equipment from a wide array of countries, with the level of dependence varying by component. Domestic content is highest for nacelle assembly (>85%), towers (80-85%), and blades and hubs (50-70%), but is much lower (<20%) for most components internal to the nacelle. Exports of wind-powered generating sets from the United States rose from $16 million in 2007 to $544 million in 2014, but fell to $149 million in 2015.
• The project finance environment remained strong in 2015. Spurred on by the December 2014 and March 2015 single-year extensions of the PTC’s construction start deadline and IRS safe harbor guidance, respectively, the U.S. wind market raised ~$6 billion of new tax equity in 2015—the largest single-year amount on record. Debt finance increased slightly to $2.9 billion, with plenty of additional availability. Tax equity yields drifted slightly lower to just below 8% (in unlevered, after-tax terms), while the cost of term debt fell to just 4% by the end of the year—perhaps the lowest it has ever been. Looking ahead, 2016 should be another busy year, given the recent 5-year PTC extension and phase down.
• IPPs own the vast majority of wind assets built in 2015. Independent power producers (IPPs) own 85% of the new wind capacity installed in the United States in 2015, with the remaining assets owned by investor-owned utilities (12%) and other entities (3%). On a cumulative basis through 2015, IPPs own 83% and utilities own 15% of U.S. wind capacity, with the remaining 2% owned by entities that are neither IPPs nor utilities (e.g., towns, schools, businesses, farmers).
• Long-term contracted sales to utilities remained the most common off-take arrangement, but direct retail sales gained ground. Electric utilities continued to be the dominant off-takers of wind power in 2015, either owning (12%) or buying (48%) power from 60% of the new capacity installed last year. Merchant/quasi-merchant projects accounted for another 29%, while direct retail purchasers – including corporate off-takers – are buying the remaining 10% (a share that should increase next year). On a cumulative basis, utilities own (15%) or buy (53%) power from 68% of all wind capacity in the United States, with merchant/quasi-merchant projects accounting for 24%, power marketers 6%, and direct retail buyers just 2% (though likely to increase in the coming years).
• 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 2015 was 2.0 MW, up 180% since 1998–1999. The average hub height in 2015 was 82.0 meters, up 47% since 1998-1999, while the average rotor diameter was 102 meters, up 113% 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 stabilization of the long-term trend since at least 2011. In 2008, no turbines employed rotors that were 100 meters in diameter or larger; by 2015, 86% of new installed wind capacity featured rotor diameters of at least 100 meters.
• 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 ) over time, from 394 W/m2 among projects installed in 1998–1999 to 246 W/m2 among projects installed in 2015. 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 2015, the vast majority of new installations used IEC Class 3 and Class 2/3 turbines.
• Turbines originally designed for lower wind speeds are now regularly employed in both lower and higher wind speed sites; taller towers predominate in the Great Lakes and Northeast. Low specific power and IEC Class 3 and 2/3 turbines 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 lower wind speeds to be deployed across a wide range of site-specific resource conditions. The tallest towers, meanwhile, have principally been deployed in the Great Lakes and Northeastern regions, in lower wind speed sites, with specific location decisions likely driven by the wind shear of the site.
• Sample-wide capacity factors have gradually increased, but have been impacted by curtailment and inter-year wind resource variability. Wind project capacity factors have generally increased over time. For a large sample of projects built from 1998 through 2014, capacity factors averaged 32.8% between 2011 and 2015 versus 31.8% between 2006 and 2010 versus 30.3% between 2000 and 2005. That being said, time-varying influences—such as inter-year variations in the strength of the wind resource or changes in the amount of wind energy curtailment—have partially masked the positive influence of turbine scaling on capacity factors. For example, wind speeds throughout the interior and western U.S. were significantly below normal for much of 2015, which negatively impacted fleet-wide capacity factors. Positively, the degree of wind curtailment has declined recently in what historically have been the most problematic areas. For example, only 1.0% of all wind generation within ERCOT was curtailed in 2015, down sharply from the peak of 17% in 2009.
• The impact of technology trends on capacity factor becomes more apparent when parsed by project vintage. Focusing only on performance in 2015 (to partially control for time-varying influences) and parsing capacity factors by project vintage tells a more interesting story, wherein rotor scaling over the past few years has clearly begun to drive capacity factors higher. The average 2015 capacity factor among projects built in 2014 reached 41.2%, compared to an average of 31.2% among projects built from 2004–2011 and just 25.8% among projects built from 1998–2003. The ongoing decline in specific power has been offset to some degree by a trend—especially from 2009 to 2012—towards building projects at lower-quality wind sites. 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 given wind resource regimes. Performance degradation over time is a final driver examined in this section: though many caveats are in order, older wind projects appear to suffer from performance degradation, particularly as they approach and enter their second decade of operations.
• 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 2014, average capacity factors in 2015 were the highest in the Interior region (42.7%). Not surprisingly, the regional rankings are roughly consistent with the relative quality of the wind resource in each region, and they reflect the degree to which each region has adopted turbines with lower specific power or taller towers. For example, the Great Lakes has thus far adopted these new designs to a much larger extent than has the West, with corresponding implications for average capacity factors in each region.
• 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 increases in hub heights and especially rotor diameters. Recently announced transactions feature pricing in the $850–$1,250/kW range. These price reductions, coupled with improved turbine technology, have exerted downward pressure on project costs and wind power prices.
• Lower turbine prices have driven reductions in reported installed project costs. The capacity-weighted average installed project cost within our 2015 sample stood at roughly $1,690/kW—down $640/kW from the apparent peak in average reported costs in 2009 and 2010. Early indications from a preliminary sample of projects currently under construction and anticipating completion in 2016 suggest no material change in installed costs in 2016.
• 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 2015, the windy Interior region of the country was the lowest-cost region, with a capacity-weighted average cost of $1,640/kW.
• 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 remain very low. After topping out at nearly $70/MWh for PPAs executed in 2009, the national average level-through price of wind PPAs within the Berkeley Lab sample has dropped to around the $20/MWh level, inclusive of the federal production tax credit (PTC), though this latest nationwide average is admittedly focused on a sample of projects that largely hail from the lowest-priced Interior region of the country, where most of the new capacity built in recent years is located. Focusing only on the Interior region, the PPA price decline has been more modest, from ~$55/MWh among contracts executed in 2009 to ~$20/MWh today. Today’s low PPA prices have been enabled by the combination of higher capacity factors, declining costs, and record-low interest rates documented elsewhere in this report.
• The relative economic competitiveness of wind power declined in 2015 with the drop in wholesale power prices. A sharp drop in wholesale power prices in 2015 made it somewhat harder for wind power to compete, notwithstanding the low wind energy PPA prices available to purchasers. This is particularly true in light of the continued expansion of wind development in the Interior region of the U.S., where wholesale power prices are among the lowest in the nation. That said, the price stream of wind PPAs executed in 2014-2016 compares very favorably to the EIA’s latest projection of the fuel costs of gas-fired generation extending out through 2040.
Policy and Market Drivers
• A long-term extension and phase down of federal incentives for wind projects is leading to a resurgent domestic market. In December 2015, Congress passed a 5-year phased-down extension of the PTC. To qualify, projects must begin construction before January 1, 2020. In May 2016, the IRS issued favorable guidance allowing four years for project completion after the start of construction, without the burden of having to prove continuous construction. In extending the PTC, Congress also included a progressive reduction in the value of the credit for projects starting construction after 2016. Specifically, the PTC will phase down in increments of 20 percentage points per year for projects starting construction in 2017 (80% PTC), 2018 (60%), and 2019 (40%).
• State policies help direct the location and amount of wind power development, but current policies cannot support continued growth at recent levels. As of July 2016, RPS policies existed in 29 states and Washington D.C. Of all wind capacity built in the United States from 2000 through 2015, roughly 51% is delivered to load-serving entities with RPS obligations. Among just those wind projects built in 2015, however, this proportion fell to 24%. Existing RPS programs are projected to require average annual renewable energy additions of roughly 3.7 GW/year through 2030, only a portion of which will come from wind. These additions are well below the average growth rate in wind power capacity in recent years.
• System operators are implementing methods to accommodate increased penetrations of wind energy, but transmission and other barriers remain. 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. System operators and others continue to implement a range of methods to accommodate increased wind energy penetrations and reduce barriers to deployment: treating wind as dispatchable, increasing wind’s capability to provide grid services, revising ancillary service market design, balancing area coordination, and new transmission investment. About 1,500 miles of transmission lines came on-line in 2015—less than in previous years. The wind industry, however, has identified 15 near-term transmission projects that—if all were completed—could carry 52 GW of additional wind capacity.
With the five-year phased-down extension of the PTC, annual wind power capacity additions are projected to continue at a rapid clip for several years. Near-term additions will also be driven by improvements in the cost and performance of wind power technologies, which continue to yield very low power sales prices. Growing corporate demand for wind energy and state-level policies are expected to play important roles as well, as might utility action to proactively stay ahead of possible future environmental compliance obligations. As a result, various forecasts for the domestic market show expected capacity additions averaging more than 8,000 MW/year from 2016 to 2020. Projections for 2021 to 2023, however, show a downturn in additions as the PTC progressively delivers less value to the sector. Expectations for continued low natural gas prices, modest electricity demand growth, and lower near-term demand from state RPS policies also put a damper on growth expectations, as do inadequate transmission infrastructure and competition from solar energy in certain regions of the country. At the same time, the potential for continued technological advancements and cost reductions enhance the prospects for longer-term growth, as does burgeoning corporate demand for wind energy and longer-term state RPS requirements. EPA’s Clean Power Plan, depending on its ultimate fate, may also create new markets for wind. Moreover, new transmission in some regions is expected to open up high-quality wind resources to development. Given these diverse underlying potential trends, wind capacity additions— especially after 2020—remain uncertain.