TODAY’S STUDY: WIND THIS YEAR
2014 Wind Technologies Market Report
Ryan Wiser and Mark Bollinger, August 2015 (Lawrence Berkerley National Laboratory)
Wind power capacity additions in the United States rebounded in 2014, and continued growth through 2016 is anticipated. Recent and projected near-term growth is supported by the industry’s primary federal incentive—the production tax credit (PTC)—which is available for projects that began construction by the end of 2014. Wind additions are also being driven by recent improvements in the cost and performance of wind power technologies, which have resulted in the lowest power sales prices ever seen in the U.S. wind sector. Growing corporate demand for wind energy and state-level policies play important roles as well. Expectations for continued technological advancements and cost reductions may further boost future growth. At the same time, the prospects for growth beyond 2016 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 growth expectations. These trends, in combination with increasingly global supply chains, have limited the growth of 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. Key findings from this year’s Wind Technologies Market Report include:
• Wind power additions rebounded in 2014, with 4,854 MW of new capacity added in the United States and $8.3 billion invested. After a lackluster year in 2013, cumulative wind power capacity grew by nearly 8%, bringing the total to 65,877 MW.
• Wind power represented 24% of electric-generating capacity additions in 2014. Wind power was the third-largest source of new generation capacity in 2014, after natural gas and solar. 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 (49%) regions. Its contribution to generation capacity growth over that period is somewhat smaller in the Northeast (27%) and West (26%), and considerably less in the Southeast (2%).
• The United States ranked third in annual wind additions in 2014, but was well behind the market leaders in wind energy penetration. Global wind additions reached a new high in 2014, with cumulative capacity standing at 372,000 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-2014 wind power is estimated to supply the equivalent of roughly 39% of Denmark’s electricity demand and more than 20% of Ireland, Portugal, and Spain’s demand. In the United States, the wind power capacity installed by the end of 2014 is estimated, in an average year, to equate to 4.9% of electricity demand.
• Texas installed the most capacity in 2014 with 1,811 MW, while nine states exceed 12% wind energy penetration. New utility-scale wind turbines were installed in nineteen states in 2014. On a cumulative basis, Texas remained the clear leader, with more than 14,000 MW installed. Notably, the wind power capacity installed in Iowa and South Dakota supplied more than 28% and 25%, respectively, of all in-state electricity generation in 2014, with Kansas close behind at nearly 22%. In six other states wind supplied between 13% and 18% of all in-state electricity generation in 2014.
• No commercial offshore turbines have been commissioned in the United States, but progress toward the first U.S. offshore wind project in Rhode Island continued in 2015 amid mixed market signals. At the end of 2014, global offshore wind capacity stood at roughly 7.7 GW. Though no commercial offshore projects have been installed in the United States, a project in Rhode Island started construction in 2015. Projects in Massachusetts, New Jersey, and Virginia, meanwhile, all experienced set-backs. Strides continued to be made in the federal arena in 2014, both through the U.S. Department of the Interior’s responsibilities in granting offshore leases and the U.S. Department of Energy’s (DOE’s) funding for demonstration projects. A total of 18 offshore wind projects (15 GW) are in various stages of development in the continental United States.
• Data from interconnection queues demonstrate that a substantial amount of wind power capacity is under consideration. At the end of 2014, there were 96 GW of wind power capacity within the transmission interconnection queues reviewed for this report, representing 30% of all generating capacity within these queues – higher than all other generating sources except natural gas. In 2014, 29 GW of gross wind power capacity entered the interconnection queues, compared to 65 GW of natural gas and 20 GW of solar.
• GE, Siemens, and Vestas captured 98% of the U.S. market in 2014. Continuing the recent dominance of the three largest turbine suppliers to the U.S. market, in 2014 GE captured 60% of the market, followed by Siemens (26%) and Vestas (12%). Globally, Vestas remained the top supplier, followed by Siemens, GE, and Goldwind. 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 in China.
• The manufacturing supply chain continued to adjust to swings in domestic demand for wind equipment. With near-term growth in the U.S. market, wind sector employment increased from 50,500 in 2013 to 73,000 in 2014. Moreover, the profitability of turbine suppliers has generally rebounded over the last two years, after a number of years in decline. Although there have been a number of recent closures, four major turbine manufacturers had one or more domestic manufacturing facilities operating at the end of 2014. Domestic nacelle assembly capability stood at roughly 9 GW in 2014, and the United States also had the capability to produce approximately 7 GW of blades and 7 GW of towers annually. Despite the significant growth in the domestic supply chain over the last decade, however, prospects for further expansion have dimmed. Far more domestic manufacturing facilities closed in 2014 than opened. With an uncertain domestic market after 2016, some manufacturers have been hesitant to commit additional long-term resources to the U.S. market.
• Domestic manufacturing content is strong for some wind turbine components, but the U.S. wind industry remains reliant on imports. The U.S. wind sector 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 (70-80%), and blades and hubs (45-65%), but is much lower (<20%) for most components internal to the nacelle. Exports of wind-powered generating sets from the United rose from $16 million in 2007 to $488 million in 2014; tower exports equaled $116 million in 2014.
• The project finance environment remained strong in 2014. Spurred on by the 2015 expiration (later extended through 2016) of the PTC safe harbor guidance provided by the IRS in late 2013, the U.S. wind market raised $5.8 billion of new tax equity in 2014—the largest single-year amount on record. Debt finance increased slightly to $2.7 billion, with plenty of additional availability. Tax equity yields held steady at around 8% (in unlevered, after-tax terms), while the cost of term debt fell by roughly 100 basis points (i.e., an absolute decrease of 1%). Looking ahead, 2015 should be another busy year, given the extension of the safe harbor guidance through 2016.
• Utility ownership of wind assets rebounded somewhat in 2014. Utilities own 26% of all new wind capacity installed in 2014, up from just 4% in 2013 and 10% in 2012, and just edging out the previous high of 25% in 2011. Independent power producers (IPPs) own the remaining 74% of new 2014 capacity. On a cumulative basis through 2014, IPPs own 82% and utilities own 16% of U.S. wind capacity, with the remaining 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 continued to expand, at least in Texas. Electric utilities continued to be the dominant off-takers of wind power in 2014, either owning (26%) or buying (40%) power from 66% of the new capacity installed last year. Merchant/quasimerchant projects accounted for another 33%. On a cumulative basis, utilities own (16%) or buy (53%) power from 69% of all wind power capacity in the United States, with merchant/quasi-merchant projects accounting for 23% and competitive power marketers (defined here as intermediaries that purchase power under contract and then resell that power to others, but also including corporate wind purchasers) accounting for 7%. Looking ahead, the latter segment should grow in response to a surge (~2 GW) of recently announced corporate wind power purchases from projects that will be built in the next few 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 2014 was 1.9 MW, up 172% since 1998–1999. The average hub height in 2014 was 82.7 meters, up 48% since 1998-1999, while the average rotor diameter was 99.4 meters, up 108% 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 in recent years. In 2008, no turbines employed rotors that were 100 meters in diameter or larger; by 2014, that percentage was 80%.
• 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 249 W/m2 among projects installed in 2014. 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 2014, 94% 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, whereas 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 sitespecific resource conditions. The tallest towers, on the other hand, 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 increased, but 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., 32.9% between 2011 and 2014 versus 31.8% between 2006 and 2010 versus 30.3% between 2000 and 2005), but 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 tended to mask the positive influence of turbine scaling on capacity factors. Positively, the degree of wind curtailment has declined recently in what historically have been the most problematic areas. For example, only 0.5% of all wind generation within ERCOT was curtailed in 2014, 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 32% to 35% nationwide. When controlling for time-varying influences by focusing only on capacity factors in 2014 (parsed by project vintage), it is difficult to discern any improvement in average capacity factors among projects built after 2005 (although the maximum 2014 capacity factors achieved by individual projects within each vintage have generally increased in the past six years). This is partially attributable to the fact that the average quality of the wind resource in which new projects are located has declined; this decrease was particularly sharp—at 10-15%—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 or 2013, average capacity factors in 2014 were the highest in the Interior (41%) and the lowest in the West (27%). 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 adopted new turbine design enhancements (e.g., turbines with a lower specific power, or taller towers) that can boost project capacity factors. For example, the Great Lakes (which ranks second among regions in terms of 2014 capacity factor) has thus far adopted these new designs to a much larger extent than has the West (which ranks last).
• 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 2014 sample stood at roughly $1,710/kW—down $580/kW from the apparent peak in average reported costs in 2009 and 2010. Early indications from a preliminary sample of 17 projects totaling more than 2 GW that are currently under construction and anticipating completion in 2015 suggest no material change in installed costs in 2015.
• 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 2014, 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 have reached all-time lows. After topping out at nearly $70/MWh for PPAs executed in 2009, the national average levelized price of wind PPAs that were signed in 2014 (and that are within the Berkeley Lab sample) fell to around $23.5/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 have, in recent years, been sited in somewhat lower-quality resource areas.
• The relative economic competitiveness of wind power improved in 2014. The continued decline in average levelized wind PPA prices, along with a continued rebound in wholesale power prices, left average wind PPA prices signed in 2014 below the bottom of the range of nationwide wholesale power prices. 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 or 2014 also compares favorably 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 is leading to a resurgent domestic market, but a possible policy cliff awaits. In December 2014, the PTC was extended, as was the ability to take the 30% investment tax credit (ITC) in lieu of the PTC. To qualify, projects had to begin construction before the end of 2014. These provisions are expected to spur solid growth in wind capacity additions in both 2015 and 2016. With the PTC now expired and its renewal uncertain, however, wind deployment beyond 2016 is also uncertain. On the other hand, the prospective impacts of EPA’s proposed regulations on power-sector carbon emissions 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 2015, RPS policies existed in 29 states and Washington D.C. Of all wind capacity built in the United States from 1998 through 2014, roughly 54% is delivered to load serving entities with RPS obligations; in 2014, this proportion was 31%. Existing RPS programs are projected to require average annual renewable energy additions of 4–5 GW/year through 2025, 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, demonstrating the limitations of relying exclusively on RPS programs to drive future deployment.
• Solid progress on overcoming transmission barriers continued. About 2,000 miles of transmission lines came on-line in 2014—substantially lower than 2013 but consistent with the 2009-2012 time period. The wind industry has identified 18 near-term transmission projects that—if all were completed—could carry 55-60 GW of additional wind capacity. The Federal Energy Regulatory Commission continues to implement Order 1000, which was intended to improve transmission planning and cost allocation. Despite this progress, planning, siting, and cost-allocation remain key barriers to transmission investment.
• System operators are implementing methods to accommodate increased penetrations of wind energy. 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 continue to implement a range of methods to accommodate increased wind energy penetrations, including: centralized wind forecasting, treating wind as dispatchable, shorter scheduling intervals, and balancing areas consolidation and coordination.
Because federal tax incentives are available for projects that initiated construction by the end of 2014, a further resurgence in new builds is anticipated in both 2015 and 2016. Near-term wind additions will also be driven by the recent improvements in the cost and performance of wind power technologies, which have led to the lowest power sales prices yet seen in the U.S. wind sector. Projections for 2017 and beyond are much less certain. Despite the low price of wind energy and the potential for further cost reductions, analysts note that 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.