Environmental Valuation & Cost-Benefit News

Executive Summary
Wind power capacity in the United States has grown substantially in recent years. From 1998 through 2006, almost 9,900 megawatts (“MW”) of new wind capacity was added, accounting for 85% of the 11,575 MW cumulative total capacity as of the end of 2006. In 2006 alone, 2,454 MW of new wind capacity was installed, representing a 27% increase in cumulative capacity.
This rapid expansion has required the mobilization of a tremendous amount of capital to finance wind project costs. Roughly $18 billion (in real 2006 dollars) has been invested in wind project installation in the U.S. since the 1980s, with more than $3.7 billion invested in 2006 alone. Looking ahead, wind project developers will need to raise close to $6 billion in 2007 in order to finance the expansion projected by the American Wind Energy Association (“AWEA”), and the required amount of capital will likely continue to increase in future years if market growth continues.

The financing of new wind projects varies from that of fossil-fueled power projects due to the different cost characteristics of each. Specifically, wind projects are capital-intensive to build but have no ongoing fuel costs, while fossil-fueled power projects are less capital-intensive (per unit of production) but have higher operating (e.g., fuel) costs. Furthermore, whereas Federal tax incentives for fossil-fueled power plants can be (and generally are) distributed throughout the entire fuel cycle (e.g., from exploration and extraction to transportation, power production, and emissions controls), tax incentives for wind projects are instead targeted almost exclusively at the power production stage. The two principal Federal tax incentives available to wind projects are the production tax credit (“PTC”) and accelerated depreciation deductions (together with the PTC, the “Tax Benefits”). These Tax Benefits provide a significant value to wind projects, but also complicate wind project finance, since most wind project developers lack sufficient Federal income tax liability to use the Tax Benefits efficiently.

In response, the wind sector has developed multiple financing structures to attract various investors to projects, manage project risk, and allocate Tax Benefits to entities that can use the Tax Benefits most efficiently. Some of these structures are intended to attract actively involved large equity investors with a strategic interest in the wind sector, labeled here as “Strategic Investors.” Others are designed to tap into more-passive equity capital from “Institutional Investors,” which are primarily interested in the Tax Benefits. Still others enable developers and equity investors to layer on debt financing to leverage their equity exposure and returns.

This report surveys the seven principal financing structures through which most new utility-scale wind projects in the United States have been financed from 1999 to the present, excluding projects owned by investor-owned and publicly-owned utilities where the project becomes part of the utilities’ internal generating portfolio and rate base. The report defines utility-scale wind projects as those designed to sell electricity directly to utilities or into power markets on a wholesale basis. The report does not cover financing structures used for smaller community-based wind power projects, though it may have some indirect utility for parties considering such projects, as several financing options used for smaller projects are derived from structures first conceived for larger projects.
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The report has three primary objectives: (1) to survey recent trends in the financing of utility-scale wind projects in the United States, (2) to describe the seven principal financing structures through which most utility-scale wind projects have been financed from 1999 to the present, and (3) to explain each structure’s relative impact on the levelized cost of wind energy. The year 1999 is used as a starting point because it marks the recent upsurge in wind power growth in the United States.

The seven structures feature varying combinations of equity capital from project developers, third-party tax-oriented investors (both Strategic and Institutional Investors, jointly known as “Tax Investors”), and commercial debt. Their origins stem from variations in the financial capacity and strength, as well as the business objectives, of wind project developers. The structures have received various names in the industry. The names given in this report are intended to reflect a defining characteristic. For the first three structures it is the nature of the Tax Investor. The Pay-As-You-Go (“PAYGO”) structure name reflects the delayed timing of the Tax Investor contribution. For the three structures involving leverage, the name refers to the type of debt financing provided. Other names are feasible and in use; care should therefore be taken to specify structures other than solely by name.

The list of financing structures covered in this report is not intended to be exhaustive. Various permutations of these structures, as well as other structures altogether, are possible. That said, the initial construction costs of most new utility-scale wind projects in the United States from 1999 to the present have been financed using one or another of these structures.

To compare the levelized cost of wind energy under each structure, a simplified Excel-based pro forma financial model of an indicative or template wind power project was constructed. The template project is based on a set of assumptions intended to reflect market conditions for projects coming on-line in 2007 and 2008 for items such as non-financing capital costs, operating costs, energy production, taxes, and revenue flows. The template project is then customized to reflect each financing structure. For the six financing structure involving third-party equity or debt capital, the analysis includes assumptions for: (1) the cost and terms of debt (if any); (2) the cost and terms of equity from Tax Investors; and (3) any financing-related transaction, or “soft” costs. The model then estimates the power prices needed to comply with those terms. For these six structures (i.e., all but the Corporate structure), the model calculates the minimum 20-year levelized cost of energy (“LCOE”) that yields the 10-year internal rate of return (“IRR”) requirement for the Tax Investors in each structure, while not violating any lender constraints.i For these structures, the 10-year Tax Investor IRR is used as a key metric, as it is a key negotiating point between developers and investors.ii For the Corporate structure, the model calculates the minimum LCOE that yields the developer’s 20-year IRR target. Using a 20-year target for the Corporate structure is consistent with the assumption that the developer, as sole project participant, evaluates the project on a longer-term basis than do pure Tax Investors. The use of a standardized template project enables the observed variations in LCOE to reflect the impact of the different financing structures.

The analysis finds significant variation – ranging from $48 per megawatt hour (“MWh”) to $63/MWh – in the 20-year LCOE required under the various financing structures. This variation is principally a function of:
(1) financing-related transaction costs (shown in Table ES-2 as “soft costs”);
(2) assumed 10-year Tax Investor IRR target rates, and Corporate 20-year IRR target; and
(3) the relative terms of each structure), including the level of equity contributions and pre- and post-flip allocations of both cash and Tax Benefits.

by John P. Harper 1, Matthew D. Karcher 2, and Mark Bolinger 3
1. Birch Tree Capital, LLC
2. Deacon Harbor Financial, L.P.
3. Lawrence Berkeley National Laboratory

Ernest Orlando Lawrence Berkeley National Laboratory www.lbl.gov
Environmental Energy Technologies Division http://eetd.lbl.gov
Paper LBNL-63434; September, 2007
http://eetd.lbl.gov/ea/ems/reports/63434.pdf