[These are here to help me do research and find citations]
Notes from 96 page: EERE. August 2014. 2013 Wind technologies market report. Energy Efficiency & Renewable Energy.
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.
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
Independent power producers own 95% of the new wind capacity installed in 2013. [My note: this is why it’s so hard to get true figures to come up with a realistic EROI, because this data is private and when data is shared with scientists, may be from the best performing windfarms, since this could lead to more investment money coming in].
Operations and maintenance costs varied by project age and commercial operations date Operations and maintenance costs are a significant component of the overall cost of wind energy and can vary substantially among projects. Anecdotal evidence and recent analysis (Lantz 2013) suggest that unscheduled maintenance and premature component failure in particular continue to be key challenges for the wind power industry. Given the scarcity, limited content, and varying quality of the data, the results that follow may not fully depict the industry’s challenges with O&M issues and expenditures.
Lack of transmission can be a barrier to new wind power development, and insufficient transmission capacity in areas where wind projects are already built can lead to curtailment, as illustrated earlier. New transmission is particularly important for wind energy because wind power projects are constrained to areas with adequate wind speeds, which are often located at a distance from load centers. There is also a mismatch between the relatively short timeframe often needed to develop a wind power project compared to the longer timeframe typically required to build new transmission. Uncertainty over transmission siting and cost allocation, particularly for multi-state transmission lines, further complicates transmission development.
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). 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%.
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.
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
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.
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.
Recently announced turbine transactions have often been priced in the $900–$1,300/kW range. [My comment: So a typical 2 MW turbine (2,000 kW) would cost $1.8 to $2.6 million dollars, and so replacing a 500 MW fossil-powered plant would cost $450 million to $650 million dollars, and last 20 years rather than the 35 year lifespan of natural gas and coal plants]
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.
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.
2013 Wind Technologies Market Report
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.
[My comment: it appears that wind turbines depend on government subsidies, implying a low EROI]
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.
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.
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.
The report concentrates on larger-scale wind turbines, defined here as individual turbines that exceed 100 kW in size.1 The U.S. wind power sector is multifaceted, however, and also includes smaller, customer-sited wind turbines used to power residences, farms, and businesses. Data on these smaller turbines are not the focus of this report, although a brief discussion on Smaller Wind Turbines is provided on page 4.
The U.S. wind power market slowed dramatically in 2013, with only 1,087 MW of new capacity added, bringing the cumulative total to 61,110 MW (Figure 1).3 This growth required $1.8 billion of investment in wind power project installations in 2013, for a cumulative investment total of $125 billion since the beginning of the 1980s (all cost and price data are reported in real 2013$).4
The table below summarizes sales of smaller (100-kW and smaller) wind turbines into the U.S. market from 2003 through 2013. As shown, 5.6 MW of small wind turbines were sold in the United States in 2013, with 88% of that capacity coming from U.S. suppliers (Orrell and Rhoads-Weaver 2014). These installation figures represent a very substantial decline in sales relative to recent years. The average installed cost of U.S. small wind turbines in 2013 was reportedly $6,940/kW
Annual Sales of Smaller Wind Turbines (= 100 kW) Year into the United States Capacity Additions Number of Turbines 2003 3.2 MW 3,200 2004 4.9 MW 4,700 2005 3.3 MW 4,300 2006 8.6 MW 8,300 2007 9.7 MW 9,100 2008 17.4 MW 10,400 2009 20.4 MW 9,800 2010 25.6 MW 7,800 2011 19.0 MW 7,300 2012 18.4 MW 3,700 2013 5.6 MW 2,700 Source: Orrell and Rhoads-Weaver (2014) Sales in this sector historically have been driven—at least in part—by a variety of state incentive programs. In addition, wind turbines of 100 kW or smaller are eligible for an uncapped 30% federal investment tax credit (ITC, in place through 2016). The Section 1603 Treasury Grant Program and programs administered by the U.S. Department of Agriculture have also played a role in the sector. According to AWEA (2014a), competitive PV and natural gas prices, suspended state incentives, and a weak economy have all contributed to recent declines in sales.
With the drop-off in annual wind power capacity additions in 2013, wind power’s share of total U.S. electric generation capacity additions in that year shrank to 7% (Figure 2).5 Overall, wind power ranked fourth in 2013 as a source of new generation capacity, behind natural gas (48% of total U.S. capacity additions), solar (26%), and coal (10%). This diminished contribution stands in stark contrast to 2012 when wind power represented the largest source of new capacity in the United States, and it marks a notable divergence from the six years preceding 2013 during which it constituted between 25% and 43% of capacity additions in each year.
Led by the decline in the U.S. market, global wind additions contracted to approximately 36,000 MW in 2013, 20% below the record of roughly 45,000 MW added in 2012. Cumulative global capacity stood at approximately 321,000 MW at the end of the year (Navigant 2014; Table 1).6 The United States ended 2013 with 19% of total global wind power capacity, a distant second to China by this metric (Table 1).7 Annual growth in cumulative capacity in 2013 was 2% for the United States and 13% globally. After leading the world in annual wind power capacity additions from 2005 through 2008, and then losing the mantle to China from 2009 through 2011, the United States narrowly regained the global lead in 2012. In 2013, however, the United States dropped precipitously to 6th place in annual wind additions (Table 1).
The U.S. wind power market represented just 3% of global installed capacity in 2013. The top five countries in 2013 for annual capacity additions were China, Germany, India, the UK, and Canada. Table 1. International Annual Capacity (2013, MW) China 16,088 Germany 3,237 India 1,987 United Kingdom 1,833 Canada 1,599 United States 1,087 Brazil 948 Poland 894 Sweden 724 Romania 695 Rest of World 7,045 TOTAL 36,137 Cumulative Capacity (end of 2013, MW) China 91,460 United States 61,110 Germany 34,468 Spain 22,637 India 20,589 United Kingdom 10,946 Italy 8,448 France 8,128 Canada 7,813 Denmark 4,747 Rest of World 51,031 TOTAL 321,377
A number of countries have achieved relatively high levels of wind energy penetration in their electricity grids. Figure 4 presents data on end-of-2013 (and earlier years’) installed wind power capacity, translated into projected annual electricity supply based on assumed country-specific capacity factors and then divided by projected 2014 (and earlier years’) electricity consumption. Using this approximation for the contribution of wind power to electricity consumption, and focusing only on those countries with the greatest cumulative installed wind power capacity, 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 cumulative wind power capacity installed at the end of 2013 is estimated, in an average year, to equate to almost 4.5% of the nation’s electricity demand. On a global basis, wind energy’s contribution is estimated to be 3.4%.
On a cumulative basis, Texas remained the clear leader among states, with 12,354 MW installed at the end of 2013—more than twice as much as the next-highest state (California, with 5,829 MW). In fact, Texas has more installed wind capacity than all but five countries (including the United States) worldwide. States (distantly) following Texas in cumulative installed capacity include California, Iowa, Illinois, Oregon, and Oklahoma—all with more than 3,000 MW. Thirty-four states, plus Puerto Rico, had more than 100 MW of wind capacity installed as of the end of 2013, with 23 of these topping 500 MW, 16 topping 1,000 MW, and 10 topping 2,000 MW. Although all commercial wind projects in the United States to date have been installed on land,
The right half of Table 2 lists the top 20 states based on actual wind electricity generation in 2013 divided by total in-state electricity generation in 2013.9 Iowa and South Dakota lead the list, each with more than 25% wind penetration. A total of nine states have achieved wind penetration levels of above 12% of in-state generation.
Wind energy penetration can either be expressed as a percentage of in-state load or in-state generation. In-state generation is used here, primarily because wind energy (like other energy resources) is often sold across state lines, which tends to distort penetration levels expressed as a percentage of in-state load.
Annual (2013) California 269 Kansas 254 Michigan 175 Texas 141 New York 84 Nebraska 75 Iowa 45 Colorado 32 Ohio 3 Massachusetts 3 Alaska 3 North Dakota 2 Indiana 1 Puerto Rico 1 Rest of U.S. 0 TOTAL 1,087 Table 2. U.S. wind power rankings: the top 20 states Percentage ofInstalled Capacity (MW)In-State Generation
Cumulative (end of 2013) Actual (2013)* Texas California Iowa Illinois Oregon Oklahoma Minnesota Kansas Washington Colorado New York North Dakota Indiana Wyoming Pennsylvania Michigan Idaho South Dakota New Mexico Montana Rest of U.S. TOTAL 12,354 Iowa 27.4% 5,829 South Dakota 26.0% 5,177 Kansas 19.4% 3,568 Idaho 16.2% 3,153 Minnesota 15.7% 3,134 North Dakota 15.6% 2,987 Oklahoma 14.8% 2,967 Colorado 13.8% 2,808 Oregon 12.4% 2,332 Wyoming 8.4% 1,722 Texas 8.3% 1,681 Maine 7.4% 1,544 California 6.6% 1,410 Washington 6.2% 1,340 New Mexico 6.1% 1,163 Montana 6.0%
One testament to the continued interest in land-based wind energy is the amount of wind power capacity currently working its way through the major transmission interconnection queues across the country. Figure 7 provides this information for wind power and other resources aggregated across 37 different interconnection queues administered by independent system operators (ISOs), regional transmission organizations (RTOs), and utilities.11 These data should be interpreted with caution: although placing a project in the interconnection queue is a necessary step in project development, being in the queue does not guarantee that a project actually will get built. Efforts have been made by FERC, ISOs, RTOs, and utilities to reduce the number of speculative projects that have—in recent years—clogged these queues. One consequence of those efforts, as well as perhaps the uncertain size of the future U.S. wind market, is that the total amount of wind power capacity in the nation’s interconnection queues has declined dramatically since 2009.
Much of the wind capacity in the interconnection queues is planned for Texas, the Midwest, Southwest Power Pool (SPP), PJM Interconnection, the Northwest, the Mountain region, and California; wind power projects in the interconnection queues in these regions at the end of 2013 accounted for 95% of the aggregate 114 GW of wind power in the selected queues (Figure 8). Smaller amounts of wind power capacity were represented in the interconnection queues of ISONew England (ISO-NE, 2.5%), the New York ISO (NYISO, 1.9%), and the Southeast (0.7%).
Manufacturing facilities that produce multiple components are included in multiple bars. “Other” includes facilities that produce items such as: Enclosures, composites, power converters, slip-rings, inverters, glass prepeg, electrical components, tower internals, climbing devices, couplings, castings, steel, rotor hubs, plates, walkways, doors, bearing cages, fasteners, bolts, magnetics, safety rings, struts, clamps, fiberglass, transmission housings, embed rings, electrical cable systems, yaw/pitch control systems, bases, generator plates, slew bearings, lubrication, resin, flanges, anemometers, template rings. Source: National Renewable Energy Laboratory Figure 11. Number of operating wind turbine and component manufacturing facilities in the United States Five of the ten wind turbine OEMs with the largest share of the U.S. market through 2013 (GE, Vestas, Siemens, Gamesa, Acciona) had one or more manufacturing facilities in the United States at the end of 2013. In contrast, nine years earlier (2004), there was only one active utility-scale wind energy OEM assembling nacelles in the United States (GE).15 In 2013, however, several of the OEMs’ manufacturing facilities were largely if not entirely dormant given the lack of turbine orders, and at least one of these facilities was subsequently closed in 2014. Another major OEM, Nordex, ceased U.S. manufacturing in 2013, while several others stopped U.S. manufacturing in past years (e.g., Clipper and Suzlon). In aggregate, domestic turbine nacelle assembly capability—defined here as the maximum nacelle assembly capability of U.S. plants if all were operating at maximum utilization—grew from less than 1.5 GW in 2006 to exceed 12 GW in 2012, before dropping to roughly 10 GW in 2013 (Figure 12;
Manufacturing facilities that produce multiple components are included in multiple bars. “Other” includes facilities that produce items such as: Enclosures, composites, power converters, slip-rings, inverters, glass prepeg, electrical components, tower internals, climbing devices, couplings, castings, steel, rotor hubs, plates, walkways, doors, bearing cages, fasteners, bolts, magnetics, safety rings, struts, clamps, fiberglass, transmission housings, embed rings, electrical cable systems, yaw/pitch control systems, bases, generator plates, slew bearings, lubrication, resin, flanges, anemometers, template rings.
Figure 14 presents calendar-year data on the dollar value of estimated imports to the United States of wind-related equipment that can be tracked through trade codes. Specifically, the figure shows imports of wind-powered generating sets (i.e., nacelles not surprisingly, taller towers have seen higher market share in the Great Lakes (56%) and Northeast (43%) than in the Interior (7%) and West (3%). This is largely due to the fact that such towers are most commonly used in lower wind speed sites, and presumably those with higher wind shear, to access the better wind speeds that are typically higher up.
Figure 31. Average cumulative sample-wide capacity factor by calendar year Table 5.
Inter-Year Wind Resource Variability. The strength of the wind resource varies from year to year, in part in response to significant persistent weather patterns such as El Niño/La
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
Counterbalancing the decline in specific power, however, has been a tendency to build new wind projects in lower-quality wind resource areas; this is especially the case among projects installed from 2009 through 2012.
the average estimated quality of the wind resource at 80 meters among projects built in 2012 (i.e., the most recent project vintage in our capacity factor sample included in figure 32) is roughly 15% lower than it is among projects built back in 1998–1999 and that the decline has been particularly sharp since 2008.45 Although there was a bit of a rebound in 2013 (which will impact our sample in future years), this trend of building wind power projects in progressively lower-quality wind resource areas is a key reason why overall average capacity factors have not increased for projects installed in recent years. The trend may also come as a surprise, given that the United States still has an abundance of undeveloped high-quality wind resource areas.
Several factors could be driving this trend:
Technology Change. The increased availability of low-wind-speed turbines that feature higher hub heights and a lower specific power may have enabled the economic build-out of lower-wind-speed sites. Transmission and Other Siting Constraints. Developers may have reacted to increasing transmission constraints (or other siting constraints, or even just regionally differentiated wholesale electricity prices) by focusing on those projects in their pipeline that may not be located in the best wind resource areas but that do have access to transmission (or higher priced markets, or readily available sites without long permitting times).
Policy Influence. Projects built in the 4-year period from 2009 through 2012 were able to access a 30% cash grant (or ITC) in lieu of the PTC. Because the dollar amount of the grant (or ITC) was not dependent on how much electricity a project generates, it is possible that developers seized this limited opportunity to build out the less-energetic sites in their development pipelines. Additionally, state RPS requirements sometimes require or motivate in-state or in-region wind development in lower wind resource regimes.
Berkeley Lab has gathered price data for 112 U.S. wind turbine transactions totaling 29,250 MW announced from 1997 through the beginning of 2014, including ten transactions (2,082 MW) announced in 2013/14. Sources of turbine price data vary, including SEC and other regulatory filings, as well as press releases and news reports. Most of the transactions included in the Berkeley Lab dataset include turbines, towers, delivery to site, and limited warranty and service agreements.48 Nonetheless, wind turbine transactions differ in the services included (e.g., whether towers and installation are provided, the length of the service agreement, etc.), turbine characteristics (and therefore performance), and the timing of future turbine delivery, driving some of the observed intra-year variability in transaction prices.
Unfortunately, collecting data on U.S. wind turbine transaction prices is a challenge: only a fraction of the announced turbine transactions have publicly revealed pricing data. In part as a result, Figure 38—which depicts these U.S. wind turbine transaction prices—also presents data from: (1) Vestas on that company’s global average turbine pricing from 2005 through 2013, as reported in Vestas’ financial reports; and (2) a range of recent global average wind turbine prices for both older turbine models (smaller rotors) and newer models (larger rotors), as reported by Bloomberg NEF (2014b).
After hitting a low of roughly $750/kW from 2000 to 2002, average wind turbine prices increased by approximately $800/kW (more than 100%) through 2008, rising to an average of more than $1,500/kW. The increase in turbine prices over this period was caused by several factors, including a decline in the value of the U.S. dollar relative to the Euro; increased materials, energy, and labor input prices; a general increase in turbine manufacturer profitability due in part to strong demand growth and turbine and component supply shortages; increased costs for turbine warranty provisions; and an up-scaling of turbine size, including hub height and rotor diameter (Bolinger and Wiser 2011).
our limited sample of recently announced U.S. turbine transactions shows pricing in the $900–$1,300/kW range. Bloomberg NEF (2014b) reports global average pricing for the most-recent contracts of approximately $1,000/kW for older turbine models and $1,300/kW for newer turbine models that feature larger rotors.
In aggregate, the dataset (through 2013) includes 708 completed wind power projects in the continental United States totaling 50,210 MW and equaling roughly 82% of all wind power capacity installed in the United States at the end of 2013.
Operations and maintenance costs varied by project age and commercial operations date Operations and maintenance costs are a significant component of the overall cost of wind energy and can vary substantially among projects. Anecdotal evidence and recent analysis (Lantz 2013) suggest that unscheduled maintenance and premature component failure in particular continue to be key challenges for the wind power industry.
Figure 44 shows an upward trend in project-level O&M costs as projects age, although the sample size after year 5 is limited. In addition, the figure shows that projects installed more recently (from 2005–2008 and/or 2009-2012) have had, in general, lower O&M costs than those installed in earlier years (from 1998–2004), at least for the first 8 years of operation. Parsing the “recent project” cohort into two sub-periods, however, reveals that this trend towards lower costs has not necessarily continued with the most recent projects in the sample, those installed from 2009-2012 (though cost differences between the 2005-2008 and 2009-12 sample are small and sample size is limited).
Many of the projects installed more recently may still be within their turbine manufacturer warranty period, and/or may have capitalized O&M service contracts within their turbine supply agreement.
As indicated previously, the data presented in Figures 43 and 44 include only a subset of total operating expenses. In comparison, the financial statements of public companies with sizable U.S. wind project assets indicate markedly higher total operating costs. Specifically, two companies—Infigen and EDP Renováveis (EDPR), which together represented approximately 4,730 MW of installed capacity at the end of 2013 (nearly all of which has been installed since 2000)—report total operating expenses of $24.2/MWh and $23.6/MWh, respectively, for their U.S. wind project portfolios in 2013 (EDPR 2014, 2013, 2012; Infigen 2014, 2013, 2012, 2011).59 These total operating expenses are more than twice the $10/MWh average O&M cost reported above for the 85 projects in the Berkeley Lab data sample installed since 2000.
This disparity in operating costs between these two project owners and the Berkeley Lab data sample reflects, in large part, differences in the scope of expenses reported.
Important Note: Notwithstanding the comparisons made in this section, neither the wind nor wholesale electricity prices (nor fuel cost projections) reflect the full social costs of power generation and delivery. Specifically, the wind PPA prices are reduced by virtue of federal and, in some cases, state tax and financial incentives. Furthermore, these prices do not fully reflect integration, resource adequacy, or transmission costs.
Various policy drivers at both the federal and state levels have been important to the expansion of the wind power market in the United States, as have been federal investments wind energy research and development (R&D). In addition to R&D expenditure, at the federal level, the most important policy incentives in recent years have been the PTC (or, if elected, the ITC), accelerated tax depreciation, and an American Recovery and Reinvestment Act of 2009 (Recovery Act) provision that enabled wind power projects to elect, for a limited time, a 30% cash grant in lieu of the PTC.
First established in 1992, the PTC provides a 10-year, inflation-adjusted credit that stood at 2.3¢/kWh in 2013.
The historical importance of the PTC to the U.S. wind power industry is illustrated by the pronounced lulls in wind power capacity additions in the 4 years (2000, 2002, 2004, 2013) in which the PTC lapsed as well as the increased development activity often seen during the year in which the PTC is otherwise scheduled to expire (see Figure 1); the spike in wind additions in 2012 is a clear example of this latter effect.
Accelerated tax depreciation enables wind project owners to depreciate the vast majority of their investments over a 5- to 6-year period for tax purposes. An even more attractive 50% 1st-year “bonus depreciation” schedule was in place during 2008–2010. Legislation in midDecember 2010 further increased 1st-year bonus depreciation to 100% for those projects placed in service between September 8, 2010 and the end of 2011, after which the 1st-year bonus reverted to 50% for projects placed in service during 2012. The American Taxpayer Relief Act then extended this 50% bonus depreciation for qualifying property placed in service in 2013 (and 2014 for certain long-lived property).
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%.66 As of June 2014, mandatory RPS programs existed in 29 states and Washington D.C. (Figure 50).67
In aggregate, existing state RPS policies require that by 2025 (at which point most state RPS requirements will have reached their maximum percentage targets) at least 9% of total U.S. generation supply will be met with RPS-eligible forms of renewable electricity, equivalent to roughly 106 GW of renewable generation capacity.68 Incremental growth in RPS requirements through 2025 represents 40% of projected growth in total U.S. electricity generation over that timeframe, although some portion of the growth in RPS requirements may be met with existing capacity (e.g., in regions that are currently over-supplied relative to their RPS targets).
Given the size of RPS targets and the amount of new renewable energy capacity that has been built since enactment of those policies, Berkeley Lab projects that existing state RPS programs require average annual renewable energy additions of roughly 3–4 GW/year through 2025, not all of which will be wind.69 This is below the average of 7 GW of wind power capacity added in each year over the 2007–2013 period, and even further below the 9 GW per year of total renewable generation capacity added during that time frame, demonstrating the limitations of relying exclusively on state RPS demand to drive future wind power development.
WA: 15% by 2020 MN: 26.5% by 2025ME: 40% by 2017MT: 15% by 2015 Xcel: 31.5% by 2020 NH: 24.8% by 2025 ND: 10% by 2015 MI: 10% by 2015 VT: 20% by 2017MA: 11.1% by 2009 +1%/yrOR: 25% by 2025 (large utilities) 5-10% by 2025 (smaller utilities) SD: 10% by 2015 WI: 10% by 2015 NY: 30% by 2015RI: 16% by 2019 PA: 8.5% by 2020 NV: 25% by 2025 IA: 105 MW by 1999 CT: 23% by 2020 NJ: 22.5% by 2020DE: 25% by 2025 OH: 12.5% by 2024 UT: 20% by 2025 KS: 20% of peak IL: 25% by 2025 demand by 2020 CO: 30% by 2020 (IOUs) MO: 15% by 2021CA: 33% by 2020 20% by 2020 (co-ops) 10% by 2020 (munis)OK: 15% by 2015 AZ: 15% by 2025 NM: 20% by 2020 (IOUs) 10% by 2020 (co-ops) AK: 50% by 2025 DC: 20% by 2020 MD: 20% by 2022 VA: 15% by 2025 NC: 12.5% by 2021 (IOUs) 10% by 2018 (co-ops and munis) TX: 5,880 MW by 2015 HI: 40% by 2030 Mandatory RPS Non-Binding Goal Source: Berkeley Lab
State renewable energy funds provide support for wind power projects (both financial and technical) in some jurisdictions, as do a variety of state tax incentives.
Transmission development has gained traction in recent years. FERC reports that over 3,500 miles of transmission lines came on-line in 2013, a significant increase from recent years (Figure 51). Another 15,000 miles of transmission lines are in various stages of development with a proposed on-line date of 2016 or earlier, with about one-third of those lines having a high probability completion (FERC 2014). According to the Edison Electric Institute (EEI), total transmission investment by investor-owned utilities reached $17.5 billion in 2013. EEI forecasts a decrease in investment in 2014 and 2015, primarily attributable to recent economic conditions and the continuance of low electric demand growth. Nonetheless, EEI identified over 170 transmission projects in development representing more than $60 billion in possible investment, 76% of which would—at least in part—support the integration of renewable energy (EEI 2014).
One of the most significant transmission undertakings devoted to wind power, the Competitive Renewable Energy Zones (CREZ) project in Texas, was largely finished by the end of 2013. The CREZ includes almost 3,600 circuit miles of transmission lines and was designed to accommodate up to 18,500 MW of total wind power capacity, 11,500 MW of which is additional to what existed when the lines were planned in 2008.70 The $6.8 billion cost of CREZ was $2 billion higher than first estimated, in part because over 600 circuit miles of additional transmission lines were needed to accommodate requested changes in routing from landowners. Because of CREZ, ERCOT reports that wind-related congestion between West Texas and other zones has largely disappeared. Moreover, ERCOT predicts that over 7,000 MW of new wind capacity will be installed in Texas by the end of 2015, with another 1,300 MW projected to come online in 2016. ERCOT recently issued a report stating that projected wind development in the Texas Panhandle is exceeding expectations, and additional transmission, reactive power and synchronous condensers will need to be added (ERCOT 2014). Partly in response, the Texas PUC has opened a staff investigation on whether any such costs should be assigned to renewable energy generators rather than to all customers, as is currently the case (Texas PUC 2014).
Elsewhere, NV Energy and Great Basin Transmission South, an affiliate of LS Power, completed the 236 mile, 500-kV, One Nevada transmission project that connects NV Energy and Sierra Pacific Power. LS Power is also developing two other transmission projects: the 500-kV Southern Nevada Intertie Project and the 500-kV Southwest Intertie Project North, both of which in combination with the ON Line could transmit over 2,000 MW. Two other transmission projects of importance to wind that were completed in 2013 include: (1) the Montana-Alberta Tie Line, a 230-kV merchant transmission line capable of transmitting 300 MW that connects Alberta to Northwestern Energy in Montana; and (2) the Pawnee-Smoky Hill double-circuit, 345-kV transmission line between the cities of Brush and Aurora in Colorado, which can transmit 300 to 500 MW of generation.
Due to the variable nature of wind, considerable attention is paid to the potential impacts of wind energy on power systems. Concerns about, and solutions to, these issues have affected, and continue to impact, the pace of wind power deployment in the United States. Experience in operating power systems with wind energy is also increasing worldwide, leading to an emerging set of best practices (Exeter and GE 2012, WGA 2012).
Figure 52 provides a selective listing of estimated wind integration costs associated with increased wind energy from integration studies completed from 2003 through 2013 at various levels of wind power capacity penetration. With one exception, wind integration costs estimated by the studies reviewed are below $12/MWh—and often below $5/MWh—for wind power capacity penetrations up to and even exceeding 40% of the peak load of the system in which the wind power is delivered. Variations in estimated costs across studies are due, in part, to differences in methodologies, definitions of integration costs, power system and market characteristics, wind energy penetration levels, fuel price assumptions, and the degree to which thermal power plant cycling costs are included.
Note also that the rigor with which the various studies have been conducted varies, as does the degree of peer review.
Finally, there has been some recent literature questioning the methods used to estimate wind integration costs and the ability to disentangle those costs explicitly, with up to 30% of PJM’s energy coming from wind and solar, given adequate transmission expansion and additional regulating reserves.