Consolidation Among Wind Farm Project Developers Continues
Consolidation on the development end of the wind energy business has slowed somewhat since 2007, but in 2009 remained on par with the pace set in 2008. The more-subdued pace of activity since 2007 may be a reflection of several factors, including the simple fact that many of the prime targets for investment and/or acquisition were acquired in earlier years.
In addition, some traditional buyers of U.S. wind assets may have decided to reign in new investments following aggressive purchases made in previous years, while some developers who might otherwise entertain offers may be holding out for better pricing as the market recovers. Looking ahead, however, the relatively weak demand for wind energy projected in 2010 (and the trouble that will cause for smaller wind farm developers), coupled with an influx of cash from the Section 1603 Treasury grant program, may help to drive continued consolidation.
Projects less than 2 MW in size are excluded from Figure 16 so that a large number of single-turbine “projects” (that, in practice, may have been developed as part of a larger, aggregated project) do not end up skewing the average.
For wind farm projects installed in phases, each phase is considered to be a separate project. Projects that are partially constructed in two different years are counted as coming online in the year in which a clear majority of the capacity was completed. If roughly equal amounts of capacity are built in each year, then the full project is counted as coming online in the later year. Due to methodological differences, these figures differ somewhat from those presented in AWEA, though the trend is consistent.
At least six significant transactions involving roughly 18 GW of in-development wind power projects (also called the development “pipeline”) were announced in 2009, similar to the five transactions and 19 GW in 2008, but well below the 11 transactions and 37 GW in 2007, and the 12 transactions and 34 GW in 2006. In 2005, eight transactions totaling 11 GW were announced, while only four transactions totaling less than 4 GW were completed from 2002 through 2004.
A number of large companies have entered the U.S. wind project development business in recent years, some through acquisitions and investments as highlighted, and others through their own development activity or through joint development agreements with others. Particularly striking in recent years has been the entrance of large European energy companies, as well as the increased interest of U.S. utility affiliates in wind project development.
Treasury Cash Grant Expands Financing Options, Buoys the Wind Sector
Due to the global credit crisis, wind power project financing in the United States declined precipitously at the close of 2008, with many lenders and tax equity investors sidelined by extreme uncertainty and shrinking tax capacity. By mid-February of 2009, however, the U.S. Congress had passed the Recovery Act, parts of which were intended to alleviate financial constraints on the industry.
Most notably, Section 1603 of the Recovery Act enables wind (and other qualifying) power projects to temporarily choose a 30% cash grant administered by the U.S. Treasury in lieu of either the PTC or a 30% investment tax credit (ITC). Title IV of the Recovery Act also expands an existing federal loan guarantee program administered by DOE to renewable energy projects using commercially proven (rather than just innovative) technology.
By replacing the PTC with an up-front 30% cash grant, Section 1603 greatly reduces, but does not completely eliminate, the dependence of wind project developers on third-party tax equity investors. Tax appetite from outside of the project itself is still needed to efficiently use accelerated depreciation deductions in the year that they are generated.
Many wind farm developers, however, have found that financing their projects with low-cost debt rather than more-expensive tax equity can more-than-make-up-for the value lost from carrying forward depreciation deductions until they can be fully used within the project itself.
The Section 1603 cash grant program has been heavily subscribed by the industry. Owners of more than 6,400 MW – i.e., more than 64% – of the wind power capacity installed in 2009 elected the grant in lieu of the PTC. As much as 2,400 MW of this wind energy capacity may not have been built in 2009 had the cash grant not been available.
And in another sign that Section 1603 has accomplished its goal of reducing dependence on the tax equity market, only about seven of the more-than-sixty 2009 projects that elected the grant were financed using third-party tax equity; many of the rest substituted project-level term debt for third-party tax equity (and are presumably planning to carry forward unused depreciation deductions), while still others were built by developers that have their own internal tax appetite.
At present, wind power projects must be under construction by the end of 2010, and online by the end of 2012, in order to qualify for the grant. Congress is considering several bills that would extend the grant program in some form or fashion, and one oft-cited rationale for an extension is that the tax equity market has not yet recovered sufficiently to supply the amount of capital that the market would otherwise require.
As of May 2010, there were roughly a dozen tax equity investors active in the wind power market – up from the handful of investors that maintained their presence throughout 2009, but still down from the market heights of early 2008. That said, as of June 2010, more than $2 billion of tax equity had reportedly been invested in the wind power sector since the start of the year –more than was invested throughout all of 2009 – and the market was considered to be on pace to reach tax equity investment levels seen in the peak year of 2007.
Although the tax equity market may still be somewhat constrained, capital has been flowing more-freely in the debt market, both from banks and institutional lenders. So-called “mini-perms” (i.e., term debt with a balloon payment due in 5-7 years) dominated for much of 2009, though tenors began to lengthen somewhat as the year progressed. By early 2010, fully amortizing loans were once again seen in the market, some with tenors as long as 15-17 years. Spreads remain high – as high as 350 basis points above LIBOR in early 2010, compared to just 125 basis points a few years ago – but were reportedly under downward pressure in mid-2010 as the number of banks active in the wind power market increased to more than thirty (Zaelke et al. 2010), and in fact had fallen below 300 basis points according to some sources (Chadbourne & Parke 2010b).
The rebound in the debt market is just one reason that there has been relatively weak demand for the federal loan guarantee program that was created as part of the Energy Policy Act of 2005 and expanded by the Recovery Act to include projects using commercially proven technologies. Other oft-cited reasons that the Section 1703 (for projects using innovative technology) and Section 1705 (for projects using commercially proven technology) loan guarantee programs have not been more popular include the relatively slow initial implementation of these programs, challenging application requirements (including the need to for a federal environmental review and complying with the Davis-Bacon Wage Act), initial inflexibility with regard to financing structures involving third-party tax equity, and the additional complexities and time to close that come from having another party – DOE – at the bargaining table (Bailey 2010, Zaelke et al. 2010, Stolarski et al. 2010, Chadbourne & Parke 2010b).
By mid-July 2010, just two wind-related loan guarantees had been awarded under the Section 1703 program: Nordic Windpower received a $16 million loan guarantee to expand its wind turbine manufacturing facility in Pocatello, Idaho, while First Wind received a $117 million loan guarantee for its 30 MW Kahuku wind farm project (which includes battery storage) in Hawaii. No wind power project has yet been awarded a guarantee under the Section 1705 program for commercial technologies, but that program could be particularly useful for larger wind power projects that can spread the transaction costs over more capacity, and that might otherwise be too large to raise debt financing through the normal channels (Zaelke et al. 2010, Stolarski et al. 2010, Chadbourne & Parke 2010b).
IPP Project Ownership Remained Dominant, but Utility Ownership Increased
Independent power producers (IPPs) continued to dominate the ownership of wind power projects in 2009, owning 83% (8,247 MW) of all new capacity additions. Nearly 16% of the total wind power capacity additions in 2009 are owned by local electric utilities, with investor-owned utilities (IOUs) owning 1,057 MW and publicly owned utilities (POUs) owning another 510 MW.
Community wind power projects – defined here as projects using turbines over 100 kW in size and completely or partly owned by towns, schools, commercial customers, or farmers, but excluding publicly owned utilities – constitute the remaining 2% of new capacity, with 180 MW. Of the cumulative installed wind power capacity at the end of 2009, IPPs owned 83% (29,164 MW), with utilities contributing 15% (4,265 MW for IOUs and 1,071 MW for POUs), and community ownership just 2% (656 MW).
The dominance of IPP ownership, and the more recent trend towards increased utility ownership, has been driven by several factors. Up until the Internal Revenue Service (IRS) clarified the issue in 2005, some IOUs were uncertain as to whether they could claim the PTC on utility-owned wind power projects (due to the requirement that PTC-eligible power must be sold to an unrelated party – in 2005 the IRS clarified that ratepayers are indeed unrelated parties).
More broadly, when wind energy was a small part of the generation mix, some utilities felt that buying wind power was less risky than owning wind power projects. As utilities have gained comfort with wind power over the years, however, their interest in ownership has increased for several reasons: IOUs are typically allowed to earn a regulated return on project ownership (i.e., by adding it to their rate base) but not on power purchases; credit rating agencies have at times considered long-term power purchase agreements to be debt-like instruments, thereby potentially negatively impacting a utility’s credit rating; and ownership places the utility in a position of greater control over the cost and price of wind energy that it receives. As a result of these drivers, utility ownership of wind power projects may continue to increase in the coming years.
General Electric (GE) remained the number one manufacturer of wind turbines supplying the U.S. market in 2009, with 40% of domestic turbine installations (down slightly from 43% in 2008, 45% in 2007, and 47% in 2006).
Following GE were Vestas (15%), Siemens (12%), Mitsubishi (8%), Suzlon (7%), Clipper (6%), Gamesa (6%), REpower (3%), Acciona (2%), and Nordex (1%). Other utility-scale (>100 kW) wind turbines installed in the United States in 2009 (and that fall into the “Other” category in Figure 9) include turbines from NedWind (6.5 MW), AAER (6 MW), DeWind (6 MW), Fuhrlander (4.5 MW), Goldwind (4.5 MW), RRB (2.4 MW), Elecon (0.6 MW), and Wind Energy Solutions (0.25 MW).
Primary authors: Ryan Wiser, Lawrence Berkeley National Laboratory, Mark Bolinger, Lawrence Berkeley National Laboratory. With contributions from Galen Barbose, Naïm Darghouth, Ben Hoen, and Andrew Mills (Berkeley Lab), Kevin Porter and Sari Fink (Exeter Associates), Suzanne Tegen (National Renewable Energy Laboratory).