Free: Putting the Wind (Back) to Work

Wind power is in front of national discussions on energy, the environment and national security, moving from side show to the center ring in the national energy mix. President Obama gave his Earth Day address at a wind turbine tower manufacturing plant and touted the possibility that the United States could get 20 percent of its energy from wind by 2030. Yet, the wind industry is facing a tough 2009, with prospects for new wind capacity installations at least in the short term seeming to decline.

How can the prospects for this industry be so high while it is experiencing such challenges? A review of the recent history of commercial wind power in the United States shows the industry reaching its fullest potential when at least three variables work together, in addition to the obvious requirements of having suitable technology and an abundance of windy sites to build on.

In the past, it was the combination of demand for wind power, appropriate incentives for developers and investors, and easy access to capital that allowed wind power capacity to become a more significant source of energy. Current federal initiatives contained in the American Recovery and Reinvestment Act of 2009 (ARRA) and clean energy legislation are clearly intended to boost wind energy demand and provide incentives for growth. However, these factors may not be sufficient to fuel growth amid constrained capital during the current economic downturn.

The Early Gust

It was not until the early 1980s, with the enactment of state and federal tax incentives in tandem with the development of modern wind turbine technology, that significant commercial investment in U.S. wind projects materialized.

A combination of lucrative tax credits offered by California and the introduction of two federal tax incentives helped move the industry forward. The first of these tax incentives was an increase in the Investment Tax Credit (ITC) for wind properties to 25 percent (effective Jan. 1, 1980). The second was the introduction in 1981 of the Accelerated Cost Recovery System (ACRS), which allowed taxpayers to depreciate the entire value of most renewable energy assets over five years.

ITCs are tax credits equal to a percentage of the basis of qualifying tangible, depreciable property. Such credits directly offset the investing taxpayer's federal income tax liability and are claimed on the tax return for the year a wind turbine and related equipment is first placed in service.

Cost recovery deductions are tax deductions claimed over time that reduce a taxpayer's taxable income.

The combination of cost recovery deductions and the ITC effectively reduce the net capital investment in wind turbines and related equipment, providing what is in effect a government investment subsidy.

As a result of these incentives, U.S. wind power capacity surged from near-zero to 1,222 megawatts (MW) by 1986,¹ with most of the new capacity installed in California. This surge subsided after Congress and California allowed tax credits to expire without renewal in the mid 1980s, and as the still-developing and costly technology experienced mechanical difficulties and often failed to meet investor expectations.

Incentives Are Renewed

The U.S. wind power market stagnated through most of the 1990s until a spike in installed wind capacity occurred in 1998 and 1999 with over 800 MW installed and, overall, total installed wind capacity jumped from 1,711 MW in 1997 to 4,685 MW by the end of 2002.²

Investment in wind energy during this period was dominated by a select group of larger energy companies making strategic investments in wind energy, with few institutional investors participating. Most new capacity was financed on the balance sheet rather than through project-finance structures. The few lenders that were in the market tended to be European banks leveraging their experience from their home markets.

During this period, Congress introduced a new incentive in the form of the Production Tax Credit (PTC), which replaced the previously repealed ITC and came into effect in 1994. The PTC operates by providing the wind turbine owner/operator with an inflation-adjusted $0.02 credit for each kilowatt hour of electricity sold to an unrelated purchaser during the first 10 years a wind turbine is in service.

Once the initial PTC period expired in June 1999, six months elapsed before Congress renewed it, and it was again allowed to expire from December 2001 to February 2002 and from December 2003 to October 2004. Each time the PTC expired, installations of new wind capacity dropped.

Since 2004 and before the ARRA, Congress extended the PTC in increments of one to two years, creating uncertainty over the longer term availability of the incentive. Despite this challenge, the PTC was strengthened during this period by Internal Revenue Service (IRS) clarifications in private letter rulings addressing partnership issues, the requirement of a pre-tax profit and qualification of sales by utilities to ratepayers, enabling investor-owned utilities to take advantage of the PTC.

Another benefit for equity investors during this time was the continued applicability of accelerated depreciation under the Modified Accelerated Cost Recovery System (MACRS). MACRS provides for five-year, double-declining-balance depreciation of wind turbines and related equipment, which results in 90 to 95 percent of the total costs of a wind project being eligible for cost recovery deductions over six years.

From Sept. 11, 2001, through the end of 2004, the federal government allowed a temporary bonus depreciation for certain assets, including wind turbines and related equipment, further encouraging capital investments in wind.

While the PTC and MACRS provided incentives for equity investors by effectively reducing the capital cost of wind assets, demand stimulation was also introduced during this period in response to increased awareness of climate change and a growing call for clean energy sources.

Several states began requiring electric utilities to obtain a minimum percentage of their overall power from renewable sources by a specified date. These requirements, known as Renewable Portfolio Standards (RPS), were adopted in some form by nine states by the end of 2003.³ However, RPS programs varied in their requirements in respect of timetables and percentages required from renewable sources, as well as compliance mechanisms, and it may remain an open question in some states whether any stated penalties could or will be easily enforced.

The Boom Years

In the period of 2003 to 2008, incentives and the demand for renewable energy combined with significantly enhanced access to both debt and equity investment capital to fuel explosive growth, with U.S. wind capacity skyrocketing from 4,685 MW at the end of 2002 to over 28,200 MW at the end of the first quarter of 2009.⁴

The number of state RPS programs rose to 29 plus Washington, D.C. by June 2009,⁵ and some existing programs were amended to require higher levels of renewable energy. In addition, three regional greenhouse gas emissions trading programs were formed to plan cap and trade platforms, and one of these, the Regional Greenhouse Gas Initiative in the Northeast, went into operation in January 2009.

These measures, plus the timely extensions of the PTC and the desire to put increasing amounts of capital to work, helped lead an influx of financial investors into the market for tax-incentivized equity investments at the same time that tremendous liquidity was fueling the debt markets.

During this period, a common equity financing involved a "partnership flip structure" in which one equity investor received a disproportionate allocation of tax benefits and the other investor received most of the project cash flows until an agreed return was achieved, at which point the flow of benefits "flipped" between investors.

All-equity financings continued to dominate the marketplace, due to a variety of factors including intercreditor issues between debt and equity investors. Equity investors were concerned in particular that in the case of a loan default, project control and cash flow would be dominated by higher-priority lenders. Financial equity investors in the wind energy marketplace were not comfortable with some of the typical equity-type risks that were traditionally accepted by developers.

Nevertheless, there were several debt financings each year, and a pattern of combined debt and equity financings emerged. Commercial banks generally stepped in to finance turbine purchases during this period as increased demand for turbines caused a shortage, sparking fierce competition. Developers found they could leverage their turbine investment through banks eager to lend, even for advanced turbine purchases for which no project had yet been specified.

The lenders accepted the turbine purchase financing risk on the assumption that, with the turbine as collateral, they could ultimately protect their investment by selling the asset, as the demand to purchase turbines was then strong and forward turbine contracts more readily saleable. Often the turbine purchase financing was converted to a construction loan and taken out by a partnership flip structure at the completion of construction, when investors could take advantage of the PTC and MACRS cost recovery deductions.

The financial markets also fueled increasing growth on the revenue side of wind projects. While wind projects prior to this period typically required a long-term power purchase agreement with a credit-worthy purchaser be in place in order to obtain investment, financial institutions were increasingly willing to step in with hedging products creating minimum revenue streams and thereby reducing risk for investors. More sources for more predictable cash flow meant more projects were eligible for financing.

The Current Landscape

While the PTC, MACRS and the state-level RPS programs remain in place, debt arrangers have largely exited the market given constrained credit. Additionally, the pool of investors with large enough tax liabilities to utilize available tax benefits has shrunk drastically. Lack of liquidity has caused turbine manufacturers to also suffer as financing for advanced turbine purchases has become increasingly limited.

The federal government's response to the credit crunch as it relates to the wind industry is also tied to its stated commitment to building a "clean energy economy." Consequently, the ARRA and other recently proposed legislation contain not only fiscal stimulus provisions, but also regulatory changes that can be expected to increase demand for renewable energy sources.

New regulatory proposals include legislation to reduce greenhouse gas emissions through a national cap-and-trade system, as well as a proposed federal RPS. The ARRA provisions aimed at supporting debt financing have added significance in the current liquidity-constrained context.

The ARRA includes a number of tax provisions that extended and enhanced currently available production tax credits for renewable energy projects as well as first year bonus depreciation. Additionally, Congress re-introduced the ITC.

The ARRA investment tax credit available for renewable energy projects is equal to 30 percent of the capital cost of a qualifying renewable project. The ARRA also created a 30 percent grant, designed to "mimic" the 30 percent ITC. The grant is a direct subsidy payable by the U.S. Treasury Department. Qualifying renewable projects generally may select the production tax credit, the investment tax credit or the grant.

Given these incentives, both partnerships and leases, two investment structures generally suitable for third-party investments in renewable energy projects, should remain relevant.

A partnership is not itself subject to tax, but the partners are taxed on their distributive share of the partnership's income, gain, loss, deduction and credit. Entities that are taxed as partnerships for federal income tax purposes, including general and limited partnerships and limited liability companies, can be utilized in connection with investments utilizing production tax credits, the investment credit or the grant. The IRS has issued a Revenue Procedure providing a "safe harbor" structure for wind energy partnerships.⁶

Leasing structures can be used for projects utilizing the new ITC or the grant but generally not the PTC. The IRS also has outstanding a Revenue Procedure providing a "safe-harbor" for leasing structures.⁷ The new renewables ITC (and the new grant) carry many rules applicable to the "old" ITC, which was generally repealed in 1986. Many of these rules, including rules allowing sale and leasebacks, favor lease structures and a "pass through" of the investment credit to the lessee.

Investors and financial advisors are trying to work through various technical issues relating to deal structures, tax benefits and the grant program. Deal execution may, in some cases, depend on timely guidance from the Treasury or IRS on specific issues, which is not expected until July 2009 at the earliest. A number of issues have already been raised in letters to the Treasury, with more likely to come from trade organizations representing investors.

The ARRA also contains provisions intended to promote lending through expanding and enhancing an existing U.S. Department of Energy (DOE) loan guarantee program created under the Energy Policy Act of 2005. The loan guarantee program under the ARRA covers established technologies such as wind and applies to projects that will be ready to commence construction by Sept. 30, 2011.

Applicants for the expanded loan guarantees will also benefit from a $6 billion appropriation for the program under the ARRA, which is expected to support some $60 billion in loan guarantees. The appropriation will lower the credit subsidy cost that borrowers would otherwise be required to pay for the loan guarantee.

While the potential for the loan guarantee program to encourage lending is significant, it has thus far not provided the promised benefits due to uncertainty in the mechanics of implementing the program and delays by the DOE in reviewing and approving applications. Since the program was introduced in 2005, the DOE has issued five solicitations for applications, but only one loan guarantee has been issued and that was in March 2009.

Criticism of the program has also been growing with regard to the requirements placed on the guarantees under the existing regulations, which included requiring DOE to have a first lien on all project assets, containing what may be considered inflexible terms for structuring the collateral package and restricting lenders' ability to place guaranteed loans on the secondary market. Additionally, the DOE has yet to issue regulations or a solicitation in connection with the loan guarantee program under the ARRA.

Increased Demand Will Help

The tax and other financing provisions of the ARRA are intended to improve the short- to medium-term ability of developers to bring new wind projects online. However, shifts in energy policy at the federal level that will increase demand for renewable energy sources could have a greater effect on the medium- to long-term health of the wind industry.

In the past several years, legislation limiting greenhouse gas emissions has been proposed several times. Currently, the leading proposed legislation addressing greenhouse gas emissions and climate change is the American Clean Energy and Security Act of 2009 (H.R. 2454) (the ACES Act), which most notably would establish a U.S. cap-and-trade system.

Complementing this legislative effort are growing calls for a federal RPS. President Obama has discussed targets of 10 percent of the nation's energy from renewable sources by 2012 and 25 percent by 2025. The ACES Act contains a federal renewable energy standard and Representative Ed Markey (D., Mass.) and Senators Tom Udall (D., N.M.) and Jeff Bingaman (D., N.M.) have also proposed legislation mandating this.

Ultimately the effect of such legislation on renewable energy demand could depend upon the mandatory minimum purchase requirements and the cost of non-compliance. Supporters of a federal RPS provide that it would also benefit the wind industry by ensuring upgrades to national transmission infrastructure that many industry players point out are needed to support an enhanced wind energy economy. Such transmission upgrades would increase investment attractiveness by ensuring that projects will be able to reliably sell their power to a larger pool of buyers.

Conclusion

The recent growth of the wind power industry was driven by a combination of demand-side growth generated by regulatory requirements, investment subsidies provided by tax-based incentives and a very liquid financing market. If this history is telling, it will likely take a similar mix to drive future growth in at least the near term.

Proposed environmental and energy-related legislation and the recent stimulus provide two out of these three drivers of sustained growth, but it remains to be seen whether this will be sufficient to attract capital back to the marketplace to support further development of wind projects.

Patricia G. Hammes is a partner in Shearman & Sterling's finance group and head of its sustainable development group. Mitchell E. Menaker is a tax partner, and Robert N. Freedman is a counsel in the finance group. Counsel Jeffrey L. Salinger, associates Erin Kelly and Derek Kershaw, and summer associate Jackson Murley assisted in the preparation of this article.

Endnotes:

1. AM. WIND ENERGY ASS'N, ANNUAL WIND INDUSTRY REPORT 4 (2009), http://www.awea.org/publications/reports/AWEA-Annual-Wind-Report-2009.pdf.

2. Id.

3. THOMAS PETERSIK, ENERGY INFO. ADMIN., U.S. DEP'T. OF ENERGY, STATE RENEWABLE ENERGY REQUIREMENTS AND GOALS: STATUS THROUGH 2003 1 (2004), http://www.eia.doe.gov/oiaf/analysispaper/rps/pdf/rps.pdf.

4. AM. WIND ENERGY ASS'N, 1ST QUARTER 2009 MARKET REPORT 1 (2009), http://www.awea.org/publications/reports/1Q09.pdf; AM. WIND ENERGY ASS'N, supra note 1, at 4.

5. PowerPoint: Database of State Incentives for Renewables & Efficiency, Renewable Portfolio Standards (June 2009), available at http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=1 (last visited June 17, 2009).

6. Rev. Proc. 2007-65, 2007-45 I.R.B. 967.

7. Rev. Proc. 2001-28, 2001-1 C.B. 1156.