TODAY’S STUDY: The Wind Market Now
2016 Wind Technologies Market Report
Ryan Wiser, Mark Bolinger, et.al., August 2016 (Lawrence Berkeley National Laboratory and (National Renewable Energy Laboratory)
Wind power capacity in the United States experienced strong growth in 2016. 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 have also been 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, given 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 continued at a rapid pace in 2016, with 8,203 MW of new capacity added in the United States and $13.0 billion invested. Supported by favorable tax policy and other drivers, cumulative wind power capacity grew by 11%, bringing the total to 82,143 MW. The nation’s first offshore project was also commissioned in 2016, the 30 MW Block Island project in Rhode Island. • Wind power represented the third-largest source of U.S. electric-generating capacity additions in 2016, behind solar and natural gas. Wind power constituted 27% of all capacity additions in 2016. Over the last decade, wind represented 31% of all U.S. capacity additions, and an even larger fraction of new capacity in the Interior (56%) and Great Lakes (48%) regions. Its contribution to generation capacity growth over the last decade is somewhat smaller in the Northeast (21%) and West (20%), and considerably less in the Southeast (2%). [See Figure 1 for regional definitions].
• The United States ranked second in annual wind additions in 2016, but was well behind the market leaders in wind energy penetration. Global wind additions equaled 54,600 GW in 2016, 14% below the record-level in 2015, yielding a cumulative total of 486,700 MW. The United States is the second-leading market in terms of cumulative capacity and 2016 annual wind energy production, behind China. A number of countries have achieved high levels of wind penetration; end-of-2016 wind power capacity is estimated to supply the equivalent of more than 40% of Denmark’s electricity demand, and between 20% and 35% of demand in Portugal, Ireland, and Spain. In the United States, the wind capacity installed by the end of 2016 is estimated, in an average year, to equate to 6.4% of electricity demand.
• Texas installed the most capacity in 2016 with 2,611 MW, while fourteen states exceeded 10% wind energy penetration. New utility-scale wind turbines were installed in 23 states in 2016. On a cumulative basis, Texas remained the clear leader, with 20,320 MW. Notably, the wind capacity installed in Iowa and South Dakota supplied more than 36% and 30%, respectively, of all in-state electricity generation in 2016, with Kansas close behind at nearly 30%. A total of nine states have achieved wind penetration levels of 15% or higher. • Data from interconnection queues demonstrate that a substantial amount of wind power capacity is under consideration. At the end of 2016, there were 142 GW of wind power capacity seeking transmission interconnection, representing 34% of all generating capacity in the reviewed interconnection queues—higher than all other generating sources. In 2016, 67 GW of wind power capacity entered interconnection queues (the largest annual sum since 2009), compared to 83 GW of solar and 40 GW of natural gas. The Midwest and Southern Power Pool experienced especially sizable additions in 2016.
• Vestas and GE captured 85% of the U.S. wind power market in 2016. In 2016, Vestas captured 43% of the U.S. market for turbine installations, just edging out GE at 42% and followed more distantly by Siemens at 10%. Vestas was also the leading wind supplier worldwide in 2016, followed by GE, Goldwind, Gamesa, and Enercon. Chinese manufacturers continued to occupy positions of prominence in the global ratings, with four of the top 10 spots; to date, 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. Domestic wind sector employment reached a new high of more than 101,000 full-time workers in 2016. Moreover, the profitability of turbine suppliers has rebounded over the last four years. Although there have been a number of plant closures over the last 5+ years, each of the three major turbine manufacturers serving the U.S. market has domestic manufacturing facilities. Domestic nacelle assembly capability stood at roughly 11.7 GW in 2016, and the United States had the capability to produce approximately 8 GW of blades and 7 GW of towers annually. The domestic supply chain faces conflicting pressures, including significant near- to medium-term growth, but also strong international competitive pressures and an anticipation of reduced demand over time as the PTC is phased down. As a result, though some manufacturers increased the size of their U.S. workforce in 2016, expectations for significant supply-chain expansion have become less optimistic.
• Domestic manufacturing content is strong for some wind turbine components, but the U.S. wind industry remains reliant on imports. The United States 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 (>90%), towers (65-80%), and blades and hubs (50-70%). Exports of wind-powered generating sets from the United States rose from $16 million in 2007 to $488 million in 2014, but fell back to $17 million in 2016. • The project finance environment remained strong in 2016. The U.S. wind market raised more than $6 billion of new tax equity in 2016, on par with the two previous years. Debt finance increased slightly to $3.4 billion. Tax equity yields drifted slightly higher to just below 8% (in unlevered, after-tax terms), while the cost of term debt fell below 4% for much of the year, before rising back above that threshold towards the end of the year. Looking ahead, 2017 should be another busy year, given the abundance of safe-harbored turbines (those committed to prior to the end of the year to qualify for the full PTC) to be deployed.
• IPPs own the vast majority of wind assets built in 2016. Independent power producers (IPPs) own 87% of the new wind capacity installed in the United States in 2016, with the remaining assets owned by investor-owned utilities (12%) and other entities (1%). On a cumulative basis through 2016, 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 2016, either owning wind projects (12%) or buying electricity from projects (40%) that, in total, represent 52% of the new capacity installed last year. Direct retail purchasers—including corporate off-takers—account for 24% (a share that should continue to increase next year). Merchant/quasi-merchant projects (22%) and power marketers (1%) make up the remainder. On a cumulative basis, utilities own (15%) or buy (51%) power from 66% of all wind capacity in the United States, with merchant/quasimerchant projects accounting for 23%, power marketers 6%, and direct retail buyers 4% (and likely to increase in the coming years).
Average turbine capacity and rotor diameter saw significant increases in 2016, while hub height increased only slightly; all have grown over the long term. The average rated (nameplate) capacity of newly installed wind turbines in the United States in 2016 was 2.15 MW, up 11% from the average over the previous 5 years (2011–2015). The average rotor diameter in 2016 was 108 meters, a 13% increase over the previous 5-year average, while the average hub height in 2016 was 83 meters, up just 1% over the previous 5-year average. • Year over year growth in rotor diameters has continued unabated for more than a decade, and has outpaced growth in nameplate capacity and hub height. Rotor scaling has been especially significant in recent years, and has outpaced increases in turbine capacity and hub heights. In 2008, no turbines employed rotors that were 100 meters in diameter or larger; by 2016, 97% of newly installed turbines featured rotors of at least that diameter, with over 50% of newly installed turbines featuring rotor diameters of 110 meters or larger.
• Turbines originally designed for lower wind speed sites have rapidly gained market share. With growth in swept rotor area outpacing growth in nameplate capacity, there has been a decline in the average “specific power” i (in W/m2 ), from 394 W/m2 among projects installed in 1998–1999 to 233 W/m2 among projects installed in 2016. 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 2016, the overwhelming majority of new installations used IEC Class 3 and Class 2/3 turbines— turbines specifically certified for lower wind speed sites. • Turbines originally designed for lower wind speeds are 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, turbines designed for lower wind speeds have been deployed across a wide range of 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 profile at the site.
• Pending and proposed wind power projects continue the trend of ever-taller turbines as lower wind resource sites appear to be targeted. Federal Aviation Administration data on not-yet-built “pending” and “proposed” turbines suggest that future wind projects will deploy progressively taller turbines, continuing the historical trend. Based on the locations of the pending and proposed turbines, it appears that these turbines will be deployed in lowerquality wind resource areas than were built out in 2014–2016. • A large number of wind power projects in 2016 employed multiple turbine configurations from a single turbine supplier. In what may be a new trend, nearly a quarter of the larger projects built in 2016 utilized turbines with multiple hub heights, rotor diameters and/or capacities—all supplied by the same original equipment manufacturer (OEM). This development may reflect increasing sophistication with respect to turbine siting and wake effects, coupled with an increasing willingness among turbine suppliers to provide multiple turbine configurations, leading to increased site optimization.
• Sample-wide capacity factors have gradually increased, but have been impacted by curtailment and inter-year wind resource variability. Wind project performance, as illustrated with data on capacity factors, has generally increased over time. However, interyear variations in the strength of the wind resource and changes in the amount of wind energy curtailment have partially masked the positive influence of turbine scaling on wind project performance. On average across the United States and for 2016 as a whole, wind speeds were near-normal, while wind energy curtailment remained modest at ~2%. • The impact of technology trends on capacity factors becomes more apparent when parsed by project vintage. Focusing only on performance in 2016 and analyzing capacity factors by project vintage tells a more interesting story, wherein rotor scaling over the past few years has clearly driven capacity factors higher. The average 2016 capacity factor among projects built in 2014 and 2015 was 42.5%, compared to an average of 32.1% among projects built from 2004–2011 and just 25.4% among projects built from 1998 to 2001. The ongoing decline in specific power, however, 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 influences shows that turbine design changes are driving capacity factors significantly higher over time among projects located in given wind resource regimes. 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 or 2015, average capacity factors in 2016 were the highest in the Interior region (43.7%). 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—and especially taller towers—to a much larger extent than some other regions, with corresponding implications for average regional capacity factors.
• Wind turbine prices remained well below levels seen a decade ago. After hitting a low of roughly $800/kW from 2000 to 2002, average turbine prices increased to roughly $1,600/kW by the end of 2008. Wind turbine prices have since dropped substantially, despite increases in hub heights and especially rotor diameters. Recent data suggest pricing most-typically in the $800–$1,100/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 2016 sample stood at roughly $1,590/kW. This is down $780/kW from the apparent peak in average reported costs in 2009 and 2010, but is roughly on par with—or even somewhat higher than—the installed costs experienced in the early 2000s. Early indications from a preliminary sample of projects currently under construction and anticipating completion in 2017 suggest no material change in installed costs in 2017. • 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 size range. Additionally, among projects built in 2016, the windy Interior region of the country was the lowest-cost region, with a capacity-weighted average cost of $1,530/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. O&M costs increase as projects age.
Wind Power Price Trends
• Wind power purchase agreement (PPA) prices remain very low. After topping out at $70/MWh for PPAs executed in 2009, the national average levelized price of wind PPAs within the Berkeley Lab sample has dropped to around the $20/MWh level—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 has been affected by the continued decline in wholesale power prices. A continued decline in wholesale power prices in 2016 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, where wholesale power prices are among the lowest in the nation. That said, the average future stream of wind PPA prices from contracts executed in 2014–2017 compares very favorably to the EIA’s latest projection of the fuel costs of gas-fired generation extending out through 2050.
Policy and Market Drivers
• The federal production tax credit remains a core motivator for wind power deployment. In December 2015, Congress passed a 5-year phased-down extension of the PTC, which provides the full PTC to projects that start construction prior to the end of 2016, before dropping in increments of 20 percentage points per year for projects starting construction in 2017 (80% PTC), 2018 (60%), and 2019 (40%). 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. According to various sources, 30-70 GW of wind turbine capacity had been qualified for the full PTC by the end of 2016, for deployment over the coming four years. • State policies help direct the location and amount of wind power development, but current state policies cannot support continued growth at recent levels. As of June 2017, RPS policies existed in 29 states and Washington D.C. Of all wind capacity built in the United States from 2000 through 2016, roughly 51% is delivered to load-serving entities with RPS obligations. Among wind projects built in 2016, this proportion fell to 21%. Existing RPS programs are projected to require average annual renewable energy additions of roughly 3.9 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. About 1,000 miles of transmission lines came on-line in 2016—less than in previous years. The wind industry, however, has identified 14 near-term transmission projects that—if all were completed— could carry 52 GW of additional wind capacity.
Analysts project that annual wind power capacity additions will continue at a rapid clip for the next several years, before declining, driven by the 5-year extension of the PTC signed in December 2015 and the progressive reduction in the value of the credit over time. Additionally, near-term additions are impacted by improvements in the cost and performance of wind power technologies, which contribute to low power sales prices. Demand drivers also include corporate wind energy purchases and state-level renewable energy policies. As a result, various forecasts for the domestic market show expected capacity additions averaging more than 9,000 MW/year from 2017 to 2020 (a pace that is supported by the amount of PTC-qualified wind turbine capacity that was reportedly safe-harbored by the end of 2016). Forecasts for 2021 to 2025, on the other hand, show a downturn in part due to the PTC phase-out. 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 continued state RPS requirements. 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 deeply uncertain.