Oklahoma, United States [Renewable Energy World North America Magazine] The American Recovery and Reinvestment Act of 2009 (ARRA) included several provisions intended to stimulate the development of wind power projects. In particular, ARRA not only extended the deadline for production tax credit (PTC) eligibility, but also granted developers the ability to choose between the $21/MWh PTC and the 30 percent investment tax credit (ITC). The economic decision-making process for selecting a tax credit can be complex since the value of the PTC is driven by production while the value of the ITC depends on the installed cost.
Recently, staff from the Lawrence Berkeley National Laboratory (LBNL) and the National Renewable Energy Laboratory (NREL) conducted an analysis to quantify the value of each incentive as a function of a project’s capacity factor and installed cost. Their analysis was meant to educate developers on which incentive maximizes return given the specifics of a project. In this article, we aim to build on NREL’s analysis by extending their results to determine the percentage of future projects that are likely to select one tax credit over the other. In order to make this determination, we first answer two questions: (1) how do tax credit preferences vary by region, and (2) in which regions are wind projects likely to be installed?
Based on our analysis, approximately 70 percent of the wind installations projected to occur through 2012 should favor the existing PTC rather than the newly-available ITC. However, we recognize that should need not imply will. In a financially-constrained environment, the ITC–particularly in cash grant form–may be the only feasible alternative to developers even if it results in “money left on the table.” In the event that external factors force the suboptimal selection of tax credits, we estimate that the wind industry would be forfeiting as much as $2 billion in potential value by 2012.
Development Follows PTC
Historically, the construction of wind power projects has been highly correlated with the availability of the PTC. Installations surged in the years following a PTC extension; conversely, when the PTC was allowed to expire (temporarily) in 2000, 2002 and 2004, wind installations were scarce. In 2008, the PTC was again set to expire at year’s end. As a result, developers exhibited caution as they awaited legislative action on an extension.
In October 2008, the PTCs were extended by an additional year via the Emergency Economic Stabilization Act of 2008 (EESA). At that time, however, it was primarily the macroeconomic forces of the credit crunch that were driving market conditions. Renewable energy projects in general — and wind projects in particular — were affected by both their demand for capital and their need for investors with an appetite for tax credits. Because of the financial crisis, many of these institutions no longer had sufficient taxable income to make full use of the offsets. The wind industry suffered, as few entities possessed both the capital necessary to invest in a renewable project and the tax posture required to exploit the tax advantages of such projects.
ARRA contained certain provisions that sought to remove these barriers. First, ARRA extended the PTCs through 2012, which is three years beyond the extension provided by EESA. In addition, ARRA gave wind projects the opportunity to elect to take the ITC in lieu of the PTC. The ITC is equal to 30 percent of a project’s qualifying costs. Previously the ITC vested linearly over a five-year period. However, ARRA also permitted qualifying projects to select a one-time cash grant in lieu of the original five-year schedule. The significance of this provision is that the benefits of the ITC can be recognized immediately, and therefore a developer does not necessarily require a partner with a tax appetite to optimize the value of the project.
Which Tax Credit?
The question facing developers now becomes: which tax credit maximizes investor returns? The value of the ITC is heavily dependent on a project’s construction cost. The value of the PTC, however, is driven by a project’s energy production (as expressed through its capacity factor in our analysis) and the discount rate used to calculate the present value of future tax credits. In seeking to answer this question, LBNL and NREL conducted an analysis to quantitatively and qualitatively analyze, from the project developer/owner perspective, the choice between the PTC and the ITC. The results of their analysis are shown in Table 1, below.
A negative value in Table 1 represents value lost (or, more correctly, foregone) when selecting the ITC instead of the PTC. Therefore, it is evident that the PTC is preferred for projects with installed costs at the lower end of the spectrum. The ITC is preferred for projects with installed costs at the higher end of the spectrum.
The question that remains is to what extent each cell is likely to occur. The LBNL-NREL report appears to conclude that roughly half of all combinations of installed cost and capacity factors prefer the ITC. This statement may lead one to believe that half of all wind installations will select the ITC. But this conclusion is based on the erroneous assumption that each combination of capacity factor and installed cost in Table 1 has an equal probability of occurring. For example, while the ITC is the preferred choice for a project with a capacity factor of 25 percent and an installed project cost of $2,500/kW, it is unlikely that a project of that nature would be constructed.
To make a more informed assessment of likelihood in tax incentive selection, we attached probabilities to the cells to calculate how likely any particular combination of parameters would be. Since the parameters tend to be a function of location, historical data can be used to ascertain the average cost and capacity factor for a region and its corresponding tax credit preference. The tax credit preference of a region can then be considered in conjunction with regional capacity addition projections to formulate a conception of the tax credit profile of the country as a whole.
Project conditions vary by location. Construction costs differ regionally due to variations in terrain, transportation costs, required permits and labor costs. Capacity factors also depend on the specific wind resource of a location. The extent to which construction costs and capacity factors have varied across regions for installed projects has been documented by another LBNL report. The Wiser-Bolinger report divides the country into the nine regions illustrated in Figure 1 (top of page), eight of which are considered here. The average capacity factor and installed cost for each region are listed in Table 2.
For illustrative purposes the map in Figure 2 (below) was created using the average capacity factor and installed cost for each region in an effort to determine which tax credit is preferred given a project’s location.
It is evident from Figure 2 that most regions tend to favor the PTC. The degree to which a region favors one tax credit or the other is captured by the shading in each state; the lighter the shade, the less partial a region is to a particular tax credit. As the value added by switching from the PTC to ITC approaches zero and the shading verges on white, a developer becomes indifferent when selecting the PTC or ITC. In some regions, the capacity factor and/or installed cost can vary by ±30 percent without impacting the tax credit decision. In other regions, however, the choice of a tax credit is sensitive to small deviations from the average values.
For example, the optimal tax credit for projects in the Texas and Eastern regions will vary according to small fluctuations in project cost, capacity factor and discount rate. To further refine the LBNL-NREL analysis, Figure 3 (below) illustrates how the three aforementioned independent variables impact the tax credit decision for projects in the Texas and Eastern regions. Figure 3 is representative of Texas and the Eastern region in that the minimum and maximum capacity factors were selected according to the minimum and maximum values for those regions as reported in the Wiser and Bolinger report. Minimum and maximum installed costs were selected in the same manner. Therefore, the chart encompasses the scenarios a developer is likely to encounter in both regions.
The colored lines in Figure 3 represent the case in which a developer is indifferent to the ITC or PTC. The area above each line represents situations in which the ITC is preferred; the area below each line represents situations in which the PTC is preferred. For example, in the case that a project has an installed cost of $1,900 and a capacity factor of 34 percent, the ITC is preferred for discount rates above 10 percent and the PTC is preferred for discount rates below 10 percent. In a similar manner, any of the three variables can be evaluated independently to quantify their influence on the tax credit decision.
Where Will Development Occur?
Knowing how tax credit preference varies according to geography, one question remains: which regions are projected to see the majority of wind installations? This question can be answered by turning to the U.S. Energy Information Administration’s (EIA) Annual Energy Outlook (AEO). The EIA projections regarding power installations are broken down according to the North American Electric Reliability Council regions.
The 2009 AEO was issued in March 2009. Subsequent to the AEO’s release, ARRA was passed, which had a substantial impact on the power sector as a whole. As a result, the EIA issued a revised AEO in April to account for the ramifications of ARRA. In particular, the original conclusions were modified to reflect the tax credit extension. The influence that ARRA is projected to have on the wind sector is illustrated in Table 3, which shows the incremental change in wind capacity additions between the pre-ARRA March AEO and its post-ARRA revision.
Positive values in Table 3 (above) represent additional wind installations that are directly attributable to ARRA. For example, the April revision of the AEO had 2.29 GW more of installations in 2010 for NERC Region 7 (New England) than the March version. As one would expect, the projected number of installations increases in the near future for most regions as the tax credit extensions provide a renewed incentive for market entry. In particular, New England, California and the Northwest are projected to see a substantial increase in installations due to the passage of ARRA. By combining this information with regional tax incentive preferences, as in Table 4 (below), we can begin to understand the market’s response to the new options available under ARRA.
According to Table 4, some 30 percent of the total wind capacity expected to be added through 2012 (in these regions) is expected to occur in regions that favor the ITC. The EIA estimates that approximately 36.3 GW of wind power will be installed in these regions between now and the end of 2012. Therefore, 10.9 GW will likely favor the ITC and 25.4 GW will favor the PTC.
The results of the prior two sections are predicated on assuming that the sole objective in selecting a tax credit is the unconstrained maximization of a project’s value. Undoubtedly, other factors will influence a developer’s decision. For example, the continued absence of investors with a tax appetite could prompt some projects to select the ITC cash grant option regardless of whether it optimizes the project’s return or not. In addition, the LBNL-NREL report identified other factors that may constrain a developer’s profit-maximizing incentive choice, including concern over performance risk, project salability, subsidized energy financing, power sale requirements, and owner/operator requirements.
While details of these factors are beyond the scope of this article, we note that only the issue of project salability favors the PTC. Imposition of the remaining constraints favors selecting the ITC. Therefore, if the difference in value between selection of the ITC and PTC is modest for a particular project, the addition of constraints could motivate the project to select the ITC even though it may diminish its return (or, one might say, the project was seeking to maximize its return subject to constraints).
The EIA used this line of reasoning in its post-ARRA AEO revision. In performing its analysis, EIA assumed the aforementioned constraints would compel companies to select the ITC grant option over the PTC regardless of any resulting diminution of value and revised its forecasts accordingly. If the EIA’s logic holds and all installations through 2012 select the ITC rather than the PTC, it would result in the wind industry essentially leaving nearly $2 billion “on the table” due to these constraints.It is unlikely that developers would allow this to happen. Instead, one would expect that financing structures would evolve in an effort to stimulate the renewed interest of tax equity investors.
For example, in the case of the Heartland region, which would forego on average $157/kW if the ITC were selected rather than the PTC, it may be reasonable to assume a project developer would be willing to forfeit a portion of the $157/kW in order to entice the interest of a tax equity investor. As a result of the superior returns available from selecting the PTC in most regions, we would expect to see efforts made to find ways to “share the wealth” among potential investors so that all stakeholders end up better off.
If, however, tax equity financing continues to face constraints, an unintended consequence of the ARRA could be a shift in the geographic location of wind installations from the wind-resource-rich Midwest to the high-energy-price Northeast. The Northeast’s high installation costs would no longer be detrimental to the development of projects since they would essentially result in larger tax credits. The remaining tradeoff between the two regions is the higher energy prices of the Northeast versus the higher capacity factors of the Midwest. While the Midwest offers a significant advantage in electricity production, its advantage may be curtailed by the fact that a project in the Northeast will receive an average 68 percent more revenue for the power it produces.
Therefore, in the short term while various constraints remain in place, it is conceivable that developers will focus their energies on projects in the Northeast, as those projects may receive the greatest incremental incentives under ARRA. Given the challenging market conditions prevailing today, developers may temporarily refrain from projects in the Midwest until the market recovers in such a way that those projects are able to realize their inherent full potential.
Budd M. Shaffer, P.E., is a senior financial analyst at DAI Management Consultants Inc., a valuation and risk management consulting firm specializing in the power and energy infrastructure sectors. Mr. Shaffer is a licensed professional engineer in Pennsylvania and holds a B.S. degree in mechanical engineering from Virginia Tech and an MBA from Carnegie Mellon.
David C. Rode is managing director of DAI Management Consultants. He has a B.S. degree in economics from the Wharton School of the University of Pennsylvania, an M.S. degree in behavioral decision making and economics from Carnegie Mellon University, and is currently completing his Ph.D in decision sciences, also at Carnegie Mellon.
Steve R. Dean, ASA, P.E. is managing principal of DAI Management Consultants. A graduate of the U.S. Naval Academy, Mr. Dean has an MBA from the University of Pittsburgh and is an accredited senior appraiser of the American Society of Appraisers in the specialties of public utilities and machinery and equipment. In addition, he is a licensed professional engineer in Pennsylvania, Michigan and Hawaii.