NewEnergyNews: TODAY’S STUDY: The Wind Market Now

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    Monday, September 17, 2018

    TODAY’S STUDY: The Wind Market Now

    2017 Wind Technologies Market Report

    August 2017 (U.S. Department of Energy)

    Executive Summary

    Wind power capacity in the United States continued to experience strong growth in 2017. Recent and nearterm additions are supported by the industry’s primary federal incentive—the production tax credit (PTC)—as well as a myriad of state-level policies. Wind capacity additions have also been driven by improvements in the cost and performance of wind power technologies, yielding low-priced wind energy for utility, corporate, and other power purchasers. The prospects for growth beyond the current PTC cycle remain uncertain, however, given declining tax support, expectations for low natural gas prices, and modest electricity demand growth.

    Key findings from this year’s Wind Technologies Market Report include:

    Installation Trends

    • Wind power additions continued at a rapid pace in 2017, with 7,017 MW of new capacity added in the United States and $11 billion invested. Supported by favorable tax policy and other factors, cumulative wind power capacity grew to 88,973 MW. In addition to this newly installed wind capacity, 2,131 MW of partial wind plant repowering was completed in 2017, mostly involving upgrades to the rotor diameters and major nacelle components of existing turbines in order to increase energy production with more-advanced turbine technology, extend project life, and access favorable tax incentives.

    • Wind power represented the third-largest source of U.S. electric-generating capacity additions in 2017, behind solar and natural gas. Wind power constituted 25% of all capacity additions in 2017. Over the last decade, wind represented 30% of all U.S. capacity additions, and an even larger fraction of new capacity in the Interior (55%) and Great Lakes (44%) regions. Its contribution to generation capacity growth over the last decade is somewhat smaller in the Northeast (19%) and West (18%), and considerably less in the Southeast (2%). [See Figure 1 for regional definitions].

    • Globally, the United States ranked second in annual wind capacity additions in 2017, but was well behind the market leaders in wind energy penetration. Global wind additions equaled 52,500 MW in 2017, well below the record 63,600 MW added in 2015, yielding a cumulative total of 539,000 MW. The United States remained the second-leading market in terms of annual and cumulative capacity as well as annual wind generation, behind China. A number of countries have achieved high levels of wind penetration; end-of-2017 wind power capacity is estimated to supply the equivalent of 48% of Denmark’s electricity demand, and roughly 30% of demand in Ireland and in Portugal. In the United States, the total wind capacity installed by the end of 2017 is estimated, in an average year, to equate to 7% of electricity demand.

    • Texas installed the most capacity in 2017 with 2,305 MW, while fourteen states exceeded 10% wind energy penetration as a fraction of total in-state generation. New utility-scale wind turbines were installed in 24 states in 2017. On a cumulative basis, Texas remained the clear leader, with 22,599 MW of capacity. Notably, the wind capacity installed in Iowa, Kansas, Oklahoma, and South Dakota supplied 30%–37% of all in-state electricity generation in 2017.

    • A record level of wind power capacity entered transmission interconnection queues in 2017; solar and storage also reached new highs in 2017. At the end of 2017, there was 180 GW of wind power capacity seeking transmission interconnection, representing 36% of all generating capacity in the reviewed queues. In 2017, 81 GW of wind power capacity entered interconnection queues, second only to solar capacity additions. Energy storage interconnection requests have also increased in recent years. The Southwest Power Pool, Texas, and Mountain regions experienced especially sizable wind additions to their queues in 2017.

    Industry Trends

    • Vestas, GE, and Siemens Gamesa captured 88% of the U.S. wind power market in 2017. In 2017, Vestas captured 35% of the U.S. market for turbine installations, edging out GE at 29% and followed by Siemens-Gamesa Renewable Energy (SGRE) at 23%. Vestas was also the leading turbine supplier for land-based wind installations worldwide in 2017, followed by SGRE, Goldwind, and GE.

    • Some manufacturers increased the size of their U.S. workforce in 2017 or otherwise expanded their existing facilities, but expectations for significant long-term supply-chain expansion have become less optimistic. Domestic wind sector employment reached a new high of 105,500 full-time workers in 2017. Moreover, the profitability of turbine suppliers has generally been strong over the last four years. Although there have been a number of plant closures over the last 5+ years, the three major turbine manufacturers serving the U.S. market have domestic manufacturing facilities. Domestic nacelle assembly capability stood at roughly 11.7 GW in 2017, and the United States had the capability to produce blades and towers sufficient for approximately 8.9 GW and 7.4 GW, respectively, of wind capacity annually. The domestic supply chain faces conflicting pressures, including significant near-term growth, but also strong competitive pressures and an anticipation of reduced demand as the PTC is phased out.

    • 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 manufacturing content is highest for nacelle assembly (>85%), towers (70–90%), and blades and hubs (50–70%).

    • The project finance environment remained strong in 2017. The U.S. wind market raised $6 billion of new tax equity in 2017, on par with the three prior years. Project-level debt finance decreased to $2.5 billion. Tax equity yields held at just below 8% (in unlevered, after-tax terms), while the cost of term debt hovered around 4% for much of the year, before pushing higher during the first half of 2018. Looking ahead, 2018 should be another busy year, given the abundant backlog of turbines that met safeharbor requirements to qualify for 100% PTC, along with another reported 10 GW of safe-harbored turbines at 80% PTC, still to be deployed.

    • Independent power producers own the vast majority of wind assets built in 2017. IPPs own 91% of the new wind capacity installed in the United States in 2017, with the remaining assets owned by investor-owned utilities (9%) and other entities (<1%)

    • Long-term contracted sales to utilities remained the most common off-take arrangement, but direct retail sales and merchant off-take arrangements were both significant. Electric utilities continued to be the largest off-takers of wind power in 2017, either owning wind projects (9%) or buying electricity from projects (36%) that, in total, represent 45% of the new capacity installed in 2017. Direct retail purchasers—including corporate off-takers—account for 24%. Merchant/quasi-merchant projects (20%) and power marketers (6%) make up the remainder (with 5% undisclosed).

    Technology Trends

    • Average turbine capacity, rotor diameter, and hub height increased in 2017, continuing the longterm trend. To optimize wind power project cost and performance, turbines continue to grow in size. The average rated (nameplate) capacity of newly installed wind turbines in the United States in 2017 was 2.32 MW, up 8% from the previous year and 224% since 1998−1999. The average rotor diameter in 2017 was 113 meters, a 4% increase over the previous year and a 135% boost over 1998−1999, while the average hub height in 2017 was 86 meters, up 4% over the previous year and 54% since 1998−1999.

    • Growth in average rotor diameter and turbine nameplate capacity have outpaced growth in average hub height over the last two decades. Rotor scaling has been especially significant in recent years. In 2008, no turbines employed rotors that were 100 meters in diameter or larger; in contrast, by 2017, 99% of newly installed turbines featured rotors of at least that diameter, with 80% of newly installed turbines featuring rotor diameters of greater than 110 meters, and 14% greater than or equal to 120 meters.

    • Turbines originally designed for lower wind speed sites have rapidly gained market share, and are being deployed in a range of wind resource conditions. With growth in swept rotor area outpacing growth in nameplate capacity, there has been a decline in the average “specific power” 1 (in W/m2 ), from 394 W/m2 among projects installed in 1998–1999 to 231 W/m2 among projects installed in 2017. 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 2017, the overwhelming majority of new installations used IEC Class 3 and Class 2/3 turbines—turbines specifically certified for lower wind speed sites.

    • Wind turbines were deployed in somewhat lower wind-speed sites in 2017 in comparison to the previous three years. With an estimated long-term average wind speed of 7.7 meters per second at a height of 80 meters above the ground, wind turbines installed in 2017 were located in lower wind-speed sites than in the previous three years; however, the 2017 average exceeds that for turbines installed from 2009 to 2013. Federal Aviation Administration data suggest that near-future wind projects will be located in similar or slightly better wind resource areas than those installed in 2017.

    • Low specific power turbines continue to be deployed 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 continue to be employed in all regions of the United States, and at both lower and higher wind speed sites. In parts of the Interior region, in particular, turbines designed for lower wind speeds continue to be deployed across a wide range of resource conditions. Meanwhile, the tallest towers continue to be 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.

    • Wind power projects planned for the near future continue the trend of ever-taller turbines. Federal Aviation Administration permit data suggest that near-future wind projects will deploy progressively taller turbines, with a significant portion (>35%) of permit applications in early 2018 over 500 feet.

    • A large number of wind power projects continued to employ multiple turbine configurations from a single turbine supplier. Nearly a quarter of the larger wind power projects built in 2016 and 2017 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.

    • Turbines that were partially repowered in 2017 now have significantly larger rotors and correspondingly lower specific power ratings. In 2017, 1,317 turbines totaling 2,131 MW of capacity were partially repowered. Larger rotors were installed on all of these repowered turbines, with an average increase of 12 meters, while only 10% saw increases in rated capacity. On average, these changes resulted in a 25% decrease in specific power, from 335 W/m2 to 252 W/m2 . All of these turbines had been in service for just 9–14 years prior to being repowered, with the primary motivation for partial repowering being to increase operational efficiencies while also re-qualifying for the PTC.

    Performance Trends

    • Sample-wide capacity factors have gradually increased, but have been impacted by curtailment and inter-year wind resource variability. Wind project performance, as illustrated by data on capacity factors, has generally increased over time, driven largely by turbine scaling. However, inter-year variations in the strength of the wind resource and changes in the amount of wind energy curtailment have partially masked the influence of turbine scaling on wind project performance. On average, across the United States and for 2017 as a whole, wind speeds were near-normal as compared to earlier years, while wind energy curtailment remained modest at around 2.5%.

    • Turbine design changes are driving capacity factors significantly higher over time among projects located in given wind resource regimes. Focusing on performance solely in 2017 helps identify underlying trends. The average 2017 capacity factor among projects built from 2014 to 2016 was 42.0%, compared to an average of 31.5% among projects built from 2004 to 2011 and just 23.5% among projects built from 1998 to 2001. The decline in specific power is a major contributor to these trends, but has been offset to a degree by a tendency—especially from 2009 to 2012—towards building projects at lowerquality 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. Older projects, meanwhile, appear to suffer from performance degradation, particularly in 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 2015–2016, average capacity factors in 2017 were highest in the Interior region (43.2%). 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 and/or taller towers. For example, the Great Lakes region has thus far adopted these new designs (particularly taller towers) to a larger extent than some other regions, leading to an increase in average regional capacity factors.

    Cost Trends

    • Wind turbine prices remained well below levels seen a decade ago. After hitting a low of roughly $800/kW2 from 2000 to 2002, average turbine prices increased to more than $1,600/kW by 2008. Since then, wind turbine prices have steeply declined, despite increases in size. Recent data suggest pricing most-typically in the $750–$950/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 capacityweighted average installed project cost within our 2017 sample stood at $1,610/kW. This is a decrease of $795/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 sample of projects currently under construction suggest that somewhat lower costs are on the horizon.

    • 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 2017, the Interior of the country was the lowest-cost region, with a capacity-weighted average cost of $1,550/kW.

    • Operations and maintenance costs varied by project age and commercial operations date. Despite limited data availability, 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. The data suggest that O&M costs have increased as projects age for the older projects in the sample, but hold steady with age among those projects installed over the last decade.

    Wind Power Price Trends

    • Wind power purchase agreement prices remain very low. After topping out at $70/MWh for power purchase agreements (PPAs) executed in 2009, the national average levelized price of wind PPAs within the Berkeley Lab sample has dropped to around or even below $20/MWh—though this 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 around $55/MWh among contracts executed in 2009 to below $20/MWh in 2017. Today’s low PPA prices have been enabled by the combination of higher capacity factors, declining installed costs, and record-low interest rates documented elsewhere in this report; the PTC has also been a key enabler over time. Regional and nationwide trends in the levelized cost of wind energy (LCOE) closely follow the PPA price trends—i.e., generally decreasing from 1998 to 2005, rising through 2009, and then declining through 2017. The lowest LCOEs are found in the Interior region, with a 2017 average of $42/MWh and with some projects as low as $38/MWh.

    • The economic competitiveness of wind power has been affected by low natural gas prices and by declines in the wholesale market value of wind energy. Given the location of wind projects and the hourly profile of wind generation, the average wholesale energy market value of wind has generally declined since 2008. Following the sharp drop in wholesale electricity prices (and, hence, wind energy market value) in 2009, average wind PPA prices tended to exceed the wholesale energy value of wind through 2012. Continued declines in wind PPA prices, however, brought those prices back in line with the energy market value of wind in 2013, and wind has generally remained competitive in subsequent years. The energy market value of wind in 2017 was the lowest in the Southwest Power Pool, at $14/MWh, whereas the highest-value market was California at $28/MWh. Meanwhile, the average future stream of wind PPA prices from contracts executed in 2015–2017 is lower than the Energy Information Administration’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 one of the core motivators for wind power deployment. In December 2015, via the Consolidated Appropriations Act of 2016, Congress passed a five-year extension of the PTC that provides the full PTC to projects that started construction prior to the end of 2016, but that phases out the PTC for projects starting construction in subsequent years (e.g., projects that started construction in 2017 get 80% of the PTC, which drops to 60% and 40% for projects starting construction in 2018 and 2019, respectively). In 2016, the IRS issued Notice 2016-31, 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, with another 10 GW qualifying for the 80% PTC.

    • State policies help direct the location and amount of wind power development, but wind power growth is outpacing state targets. As of June 2018, renewables portfolio standards (RPS) existed in 29 states and Washington D.C. Of all wind capacity built in the United States from 2000 through 2017, roughly 49% is delivered to load-serving entities with RPS obligations. Among wind projects built in 2017, this proportion fell to 23%. Existing RPS programs are projected to require average annual renewable energy additions of roughly 4.5 GW/year through 2030.

    • System operators are implementing methods to accommodate increased penetrations of wind energy, but transmission and other barriers remain. Studies show that the cost of integrating wind energy into the grid varies widely, from often below $5/MWh to close to $20/MWh for wind power capacity penetrations of up to or exceeding 40% of the peak load of the system in which the wind power is delivered. Grid system operators and others continue to implement a range of methods to accommodate increased wind energy penetrations. Just over 500 miles of transmission lines came online in 2017—less than in previous years. The wind industry has identified 26 near-term transmission projects that, if completed, could support considerable amounts of wind capacity.

    Future Outlook

    Energy analysts project that annual wind power capacity additions will continue at a rapid clip for the next several years, before declining, driven by the five-year extension of the PTC 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. Other factors influencing demand include corporate wind energy purchases and state-level renewable energy policies. As a result, various forecasts show additions increasing in the near term, from more than 8 GW in 2018 to roughly 10–13 GW in 2020.

    Forecasts for 2021 to 2025, on the other hand, show a downturn in wind capacity additions in part due to the PTC phase-out. Expectations for continued low natural gas prices, modest electricity demand growth, and lower demand from state policies also put a damper on growth expectations, as do limited transmission infrastructure and competition from natural gas and solar energy. 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 for development. Given these diverse and contrasting underlying potential trends, wind additions—especially after 2020—remain uncertain.

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