Leasing Wind Power Facilities: A New Reality

In 2010, however, leasing appeared on the national stage as another potentially viable, though complex, type of financing, with its successful use in two large utility scale projects and one community wind project. Although these transactions do not assure that leasing will become a mainstream form of financing, they suggest that leasing of wind energy facilities has shifted from being technically feasible to a market reality. (A discussion of other financing options and structures, including those used in community wind projects, extends beyond the scope of this article.)

Leasing Wind Energy Facilities in 2010

On July 21, 2010, Terra-Gen Power, LLC (“Terra-Gen”) announced that it had closed a $1.2 billion financing of 570 MW of wind power projects in Kern County, CA, called Alta II-Alta V (“Alta Wind Projects”). To pay for the construction of the Alta Wind Projects, Terra-Gen arranged diverse financing using pass-through trust certificates under a Rule 144A offering, a construction bridge loan and ancillary credit lines. Citibank, as the tax equity investor and owner-lessor, agreed to provide the permanent financing structured as a sale and leaseback.

On Dec. 16, 2010, Pattern Energy Group LP (“Pattern”) achieved another milestone when it completed the first lease of an operational wind facility since the early 1990s. Pattern's subsidiary, Hatchet Ridge Wind, LLC (“Hatchet”), sold its 101.2 MW wind farm in Burney, CA, to MetLife, the New York insurance company. Met Life, as the new owner/lessor, entered into a sale-leaseback transaction with Hatchet, as lessee.

Even before these deals closed, on July 7, 2010, Project Resources Corporation (“PRC”) announced that it closed construction financing from Union Bank, N.A., for its 25.3 MW Ridgewind Project located in Woodstock, MN. According to PRC, Union Bank arranged and underwrote a $51 million construction financing. An affiliate of Union Bank will repay the construction loan on its purchase of the facility in a sale-leaseback transaction soon after commercial operations commence.

Lessor Challenges: Project Size and Project Finance Structure

The size of a wind energy “facility” is usually expressed in kW, MW or GW. For an onshore wind farm, total development costs vary depending on the attributes of the project, but as a general proposition, approximate $1.8-$2.2 million per MW. Thus, a 100 MW project can cost $180-$220 million.

Typically, a developer, as the owner of the project company, arranges for a lender and/or an equity investor to provide financing on a project basis, which means they essentially can exercise recourse only against the project company (not the developer or others). The project company enters into the contracts relevant to the project including the power purchase agreement (“PPA”). The payments under the PPA to the project company provide revenue and credit support to service the debt and/or pay rent. Power purchasers broadly include investor and independently owned utilities, universities, and even some industrial companies, that optimally offer financiers strong financials and acceptable credit ratings.

Although many equipment lessors may have been reluctant to finance wind facilities, that has begun to change. The project financing structure, coupled with a potentially large and lengthy financial commitment, present substantial obstacles to entry and finance approvals for other lessors. If equipment lessors cannot or will not finance an entire wind facility, however, they still can acquire an undivided interest in a wind facility or become a partner in a partnership that owns the facility. In addition, a lessor can side step the project finance structure by leasing equipment used to build, transport or manufacture wind energy products.

Alternative Financing Structures for Lessors: Partnership Flip and Lease Financing

Developers have the option to engage in a lease or partnership “flip” structure to finance their wind energy projects. In a partnership structure, “tax equity” investors anticipate receiving a target after-tax return on their investments over a period that ranges from six to 12 years depending on the amount of project debt and transaction structure. Tax equity investors typically claim 99% of project tax losses and investment or production tax credits. When they achieve their target yield, which includes tax benefits and cash flow from the project, the partners' allocation and distribution ratios change (“flip”). If the flip is not expected to occur too early, the partners may agree to distribute cash flow to the developer until it recovers its equity investment. This priority distribution is sometimes called the “cash sweep.” After the flip occurs, the partnership distributes cash flow to the developer and tax equity investor in the same ratio as their respective income allocations (excluding minimum gain chargebacks attributable to project debt), which may be as disproportionate as 95:5.

Tax equity investors have gravitated to the partnership structure because of its economic benefits and the federal income tax “safe harbor” afforded by Revenue Procedure 2007-65, as modified by Announcement 2007-112 and Announcement 2009-69. The safe harbor shields specific partnership flip transactions from an audit challenge by the Internal Revenue Service (“IRS”), but does not address certain key issues, including whether the transaction satisfies tax law economic substance requirements. In contrast, the IRS lease guidelines, contained in Revenue Procedure 2001-28, are not as favorable because they are applied only for purposes of obtaining an advance ruling for a leveraged lease transaction and do not permit lessee fixed-price purchase options (singularly, an “FPPO”). Although lessors have not sought advance rulings very often in the last several decades, in the current legal environment some investors may be reluctant to enter into a leveraged lease without one.

At the flip point in a flip partnership, the developer becomes the economic owner of nearly all of the project, and the developer may exercise its option to purchase the tax equity investor's remaining interest in the project for the project's fair market value. The developer does not, therefore, need an FPPO (although the safe harbor permits them), and the cost of acquiring the tax equity investor's interest may be substantially less than in a lease financing. In contrast, if a developer desires to capture residual value at the least all-in cost, a lessee early buy-out option (“EBO”) may be essential to the comparative viability of a lease financing.

Lease and flip partnership structures can generally produce comparable developer yields depending on the parties' assumptions and objectives. In some circumstances, however, only one of these structures may be economically appropriate. For example, the developer may require more financing or more consistent cash flow than may be provided in the partnership structure. By using a deferred rent structure permitted by Internal Revenue Code (“IRC”) section 467, the developer's returns can also be more favorable in a lease when the developer's effective tax rate is lower than the tax equity investor's tax rate. Alternatively, a tax equity investor may wish to recover its investment, and the developer may desire to have the right to buy the tax equity investor's interest too early during the arrangement for an EBO to be economically viable ' an advantage for partnerships.

If the project is financed partly with long-term debt, the project company will almost certainly pay most or all of its free cash to its lender until the lender is paid in full. To protect and enhance their combined economic returns, the developer and tax equity investors may need to adjust their initial capital contributions and cash flow shares so that the flip does not occur until the debt is fully or nearly repaid.

In a partnership flip, the tax equity investor secures its target yield substantially prior to the end of the financing term, whereas a lessor typically is willing to rely on late-term cash flows and residuals to meet its target yield. Leasing may be preferable to the partnership if the tax equity investors rely on late-term cash flows to recover their investments, assume significant residual value for the project and/or bet that the developer will exercise an EBO. For developers who are not overly concerned about their ability to acquire the project residual, or the risk of defaulting on their lease obligations, tax equity pricing that includes a significant residual value assumption or late-term cash flows may also favor leasing.

Apart from the tax attributes and structuring of a transaction, leasing may also offer longer maturity financing than project finance loan tenors.

Wind Energy Subsidies and Incentives

The American Recovery and Reinvestment Act of 2009 (“ARRA”) created the Section 1603 cash grant program (“1603 Program”). In December 2010, Congress extended the 1603 Program one year (through Dec. 31, 2011) under the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (the “2010 Act”) for projects that otherwise qualify under ARRA. The cash grant equals 30% of the cost basis of the energy property. Most, but not all, projects seek to utilize the cash grant.

As administered by the U.S. Treasury Department (“Treasury”), an eligible owner of a qualified energy facility will receive a cash grant within 60 days after a project is placed in service and the Treasury has received a properly and timely completed application. In ARRA Energy Co. I v. United States, No. 10-84 C (Fed. Cl. Jan. 18, 2011), a court determined that the 1603 Program does not provide the government with any discretion to refuse a cash grant when the applicant meets the specific requirements of the statute. Applicants must use care to furnish Treasury with proper documentation to substantiate the cost basis of their property.

If a project takes the cash grant, neither the federal business energy investment tax credit (“ITC”) nor the production tax credit (“PTC”) may be claimed. The project owner must be the original user, except for a sale leaseback to another owner/tax equity investor within the first three months of the date the facility is placed in service. The cash grant is not taxable although it reduces the depreciation basis by one half of the cash grant. Pass-through entities are eligible only if all of their members are eligible.

In the 2010 Act, Congress also authorized owners to write off, in the first year, the entire depreciable basis of qualified property, including turbines and towers, placed in service after Sept. 8, 2010 and before Jan. 1, 2012. For qualified property placed in service in 2012, a 50% depreciation bonus is available. These first year write-offs are not available if the taxpayer (or the lessee in a sale leaseback) committed to acquire, or commence construction of, the property before 2008.

If a wind project has a high net capacity factor, the PTC may provide greater economic benefit for the developer and investors than either the ITC or cash grant. The net capacity factor, which typically ranges from 20%-45% (and higher in some locations), is the ratio of actual energy production to the energy production of a turbine in a given period running full time at its rated power (reduced by operational or other energy losses). More specifically, the “capacity factor” equals the annual energy production divided by the theoretical maximum energy production if the generator were running at its rated power all the year. For example, if a 1500 kW machine makes 3.5 million kWh in a year, that's 3,500,000 / (365 ' 24 ' 1500) = 27% capacity factor. The PTC provides the producer of electricity from a wind facility a tax credit in 2010 of 2.2 cents per kWh computed for each kWh of electricity generated and sold to unrelated third parties, over a 10-year period. In such case, the partnership flip structure can work if the partnership produces the electricity, but leasing does not because under IRC section 45(a)(2)(A) the producer (rather than the facility owner) claims the PTC.

An important non-tax policy incentive for wind projects is a State renewable portfolio standard (“RPS”) or a federal Clean Energy Standard (“CES”), should Congress enact one now that the Administration has thrown its support behind one. According to the “DSIRE” Web site (see Database of State Incentives for Renewables and Efficiency), as of September 2010, 29 states, plus Washington, DC and Puerto Rico, have enacted RPS requirements and seven states have set renewable portfolio goals. An RPS sets a percentage of an electric provider's energy sales (MWh) or installed capacity (MW) to come from renewable resources. To meet the applicable RPS (or a CES, if enacted), utilities and other power purchasers may, as one option, buy electric power from wind projects.

In some cases, the Department of Energy (“DOE”) may subsidize projects through grants or loan guarantees. However, DOE applications require patience, tenacity and diligence. A developer must apply with enough lead time to avoid execution risk or undermine project economic assumptions. An applicant should consider alternative financing for a project should the DOE decline or excessively delay a decision on the application for a grant or guarantee.

Economic Substance: Tax Abusive Transactions at Risk

The economic substance doctrine (“ESD”) disallows tax benefits in transactions motivated excessively by tax avoidance. IRC section 7701(o) codified and enhanced the common law ESD. If a tax equity financing is subject to the new law, in many cases the present value of the tax equity investor's reasonably expected pretax profit must be substantial in relation to its expected net tax benefits. This pretax profitability requirement may differ from how many advisers interpreted prior law. See Report on Codification of the Economic Substance Doctrine by New York State Bar Association Tax Section (Jan. 5, 2011). Exacerbating the problem, the IRS has been unwilling to clarify the statute.

In Historic Boardwalk Hall, LLC v. Commissioner, 136 T.C. No. 1 (2011), the Tax Court upheld a tax equity financing transaction involving tax credits that benefit historic rehabilitation projects. Although the case arose under pre-Section 7701(o) law, the court's generous application of ESD principles may help to resolve how the codified ESD applies to wind energy projects.

Accounting Mayhem

The International Accounting Standards Board (“IASB”) and the Financial Accounting Standards Board (“FASB”) have been engaged in a joint project to overhaul current lease accounting rules under the Statement of Financial Accounting No. 13 (“FAS 13″). They published their proposals in an Exposure Draft for Leases on Aug. 17, 2010 (“ED”). The IASB and FASB may issue a final standard this summer.

The ED contains proposals that lessors and lessees account for leases under a “right-of-use” model instead of the currently available method of classifying leases under FAS 13 into two categories: a capital lease (recognizes an asset and liability) and an “operating lease” (does not recognize an asset and liability). If adopted, the changes will result in the capitalization of lease obligations on the lessee's balance sheet. In addition, the new rules would eliminate leveraged lease accounting, which has encouraged capital investment and benefited leasing for decades. These changes would occur without “grandfathering” of transactions existing on the date of initial application of the final rules.

The final lease accounting changes will affect wind energy transactions as well as other property, plant and equipment. Their significance cannot be overstated. Yet, potential tax equity investors should not assume that developers in wind energy deals will refuse to enter a lease because the lease obligations will be put on the lessee's balance sheet. In some circumstances, project companies may lease a wind project despite these accounting changes because the impact may be neither material nor inconsistent with their respective business models. See Lease Accounting: New Rules and Realities by Shawn D. Halladay, Journal of Equipment Lease Financing, Vol. 29 Number 1 (Winter 2011).

Conclusion

Though partnership flip deals have dominated the wind energy financing market, leasing has been, and continues to be, a multi-billion dollar source of capital for investment in equipment and facilities. The Alta Wind Project, the PRC Project and the Hatchet Project attest to the viability of, if not the demand for, lease financing of wind energy facilities. Lessors can participate in this growing market as tax equity investors through selected opportunities to lease equipment and facilities. However, tax equity investors that remain flexible enough to invest via a partnership flip, leasing or other financing structures may find that their investments buy them a ticket into a bigger game of financing wind energy projects of all sizes and descriptions, well into the future.

David G. Mayer ([email protected], 214-758-1545), a member of this newsletter's Board of Editors, is a Patton Boggs partner in the Business Practice Group in Dallas. Joel Bannister ([email protected], 214-758-6681) is an associate in the Business Practice Group. The views expressed in this article are those of the individual authors and not the views of Patton Boggs LLP.

Electric power generation from wind continues to grow at a rapid pace. Wind is such an abundant natural resource that in a 2010 assessment, the Department of Energy found that the contiguous 48 states have the potential to generate up to 37 million gigawatt-hours (“GWh”) of electricity from wind annually, which is approximately nine times the total U.S. electricity generation from all sources in 2009.

The American Wind Energy Association (“AWEA”) reported more recently that the U.S. installed capacity of electrical wind energy reached 40,180 megawatts (“MW”) at the end of 2010. Texas leads the country in installed wind energy capacity with more than 10,000 MW. The Energy Information Agency estimates (based on the 2009 Census) that the average U.S. home consumes 908 kWh per month (as of 2009). Clearly, wind energy now and in the future can power a vast number of homes in the United States. (A kilowatt (“kW”), MW (10,000,000 kW) or GW (1,000 MW) is an instantaneous measure of power. A kilowatt hour (“kWh”), MW hour (“MWh”) or GWh is a measure of electricity defined as a unit of work or energy, measured as one kW, MW or one GW, respectively, of power expended for one hour.)

For all its natural force, wind energy growth is really powered with money provided through loans, leases, equity investments and other funding vehicles. Leasing is a technically feasible means of financing wind energy facilities, but, in recent years, partnership “tax equity” investments and project finance lending have dominated the market for wind energy financing.

In 2010, however, leasing appeared on the national stage as another potentially viable, though complex, type of financing, with its successful use in two large utility scale projects and one community wind project. Although these transactions do not assure that leasing will become a mainstream form of financing, they suggest that leasing of wind energy facilities has shifted from being technically feasible to a market reality. (A discussion of other financing options and structures, including those used in community wind projects, extends beyond the scope of this article.)

Leasing Wind Energy Facilities in 2010

On July 21, 2010, Terra-Gen Power, LLC (“Terra-Gen”) announced that it had closed a $1.2 billion financing of 570 MW of wind power projects in Kern County, CA, called Alta II-Alta V (“Alta Wind Projects”). To pay for the construction of the Alta Wind Projects, Terra-Gen arranged diverse financing using pass-through trust certificates under a Rule 144A offering, a construction bridge loan and ancillary credit lines. Citibank, as the tax equity investor and owner-lessor, agreed to provide the permanent financing structured as a sale and leaseback.

On Dec. 16, 2010, Pattern Energy Group LP (“Pattern”) achieved another milestone when it completed the first lease of an operational wind facility since the early 1990s. Pattern's subsidiary, Hatchet Ridge Wind, LLC (“Hatchet”), sold its 101.2 MW wind farm in Burney, CA, to MetLife, the New York insurance company. Met Life, as the new owner/lessor, entered into a sale-leaseback transaction with Hatchet, as lessee.

Even before these deals closed, on July 7, 2010, Project Resources Corporation (“PRC”) announced that it closed construction financing from Union Bank, N.A., for its 25.3 MW Ridgewind Project located in Woodstock, MN. According to PRC, Union Bank arranged and underwrote a $51 million construction financing. An affiliate of Union Bank will repay the construction loan on its purchase of the facility in a sale-leaseback transaction soon after commercial operations commence.

Lessor Challenges: Project Size and Project Finance Structure

The size of a wind energy “facility” is usually expressed in kW, MW or GW. For an onshore wind farm, total development costs vary depending on the attributes of the project, but as a general proposition, approximate $1.8-$2.2 million per MW. Thus, a 100 MW project can cost $180-$220 million.

Typically, a developer, as the owner of the project company, arranges for a lender and/or an equity investor to provide financing on a project basis, which means they essentially can exercise recourse only against the project company (not the developer or others). The project company enters into the contracts relevant to the project including the power purchase agreement (“PPA”). The payments under the PPA to the project company provide revenue and credit support to service the debt and/or pay rent. Power purchasers broadly include investor and independently owned utilities, universities, and even some industrial companies, that optimally offer financiers strong financials and acceptable credit ratings.

Although many equipment lessors may have been reluctant to finance wind facilities, that has begun to change. The project financing structure, coupled with a potentially large and lengthy financial commitment, present substantial obstacles to entry and finance approvals for other lessors. If equipment lessors cannot or will not finance an entire wind facility, however, they still can acquire an undivided interest in a wind facility or become a partner in a partnership that owns the facility. In addition, a lessor can side step the project finance structure by leasing equipment used to build, transport or manufacture wind energy products.

Alternative Financing Structures for Lessors: Partnership Flip and Lease Financing

Developers have the option to engage in a lease or partnership “flip” structure to finance their wind energy projects. In a partnership structure, “tax equity” investors anticipate receiving a target after-tax return on their investments over a period that ranges from six to 12 years depending on the amount of project debt and transaction structure. Tax equity investors typically claim 99% of project tax losses and investment or production tax credits. When they achieve their target yield, which includes tax benefits and cash flow from the project, the partners' allocation and distribution ratios change (“flip”). If the flip is not expected to occur too early, the partners may agree to distribute cash flow to the developer until it recovers its equity investment. This priority distribution is sometimes called the “cash sweep.” After the flip occurs, the partnership distributes cash flow to the developer and tax equity investor in the same ratio as their respective income allocations (excluding minimum gain chargebacks attributable to project debt), which may be as disproportionate as 95:5.

Tax equity investors have gravitated to the partnership structure because of its economic benefits and the federal income tax “safe harbor” afforded by Revenue Procedure 2007-65, as modified by Announcement 2007-112 and Announcement 2009-69. The safe harbor shields specific partnership flip transactions from an audit challenge by the Internal Revenue Service (“IRS”), but does not address certain key issues, including whether the transaction satisfies tax law economic substance requirements. In contrast, the IRS lease guidelines, contained in Revenue Procedure 2001-28, are not as favorable because they are applied only for purposes of obtaining an advance ruling for a leveraged lease transaction and do not permit lessee fixed-price purchase options (singularly, an “FPPO”). Although lessors have not sought advance rulings very often in the last several decades, in the current legal environment some investors may be reluctant to enter into a leveraged lease without one.

At the flip point in a flip partnership, the developer becomes the economic owner of nearly all of the project, and the developer may exercise its option to purchase the tax equity investor's remaining interest in the project for the project's fair market value. The developer does not, therefore, need an FPPO (although the safe harbor permits them), and the cost of acquiring the tax equity investor's interest may be substantially less than in a lease financing. In contrast, if a developer desires to capture residual value at the least all-in cost, a lessee early buy-out option (“EBO”) may be essential to the comparative viability of a lease financing.

Lease and flip partnership structures can generally produce comparable developer yields depending on the parties' assumptions and objectives. In some circumstances, however, only one of these structures may be economically appropriate. For example, the developer may require more financing or more consistent cash flow than may be provided in the partnership structure. By using a deferred rent structure permitted by Internal Revenue Code (“IRC”) section 467, the developer's returns can also be more favorable in a lease when the developer's effective tax rate is lower than the tax equity investor's tax rate. Alternatively, a tax equity investor may wish to recover its investment, and the developer may desire to have the right to buy the tax equity investor's interest too early during the arrangement for an EBO to be economically viable ' an advantage for partnerships.

If the project is financed partly with long-term debt, the project company will almost certainly pay most or all of its free cash to its lender until the lender is paid in full. To protect and enhance their combined economic returns, the developer and tax equity investors may need to adjust their initial capital contributions and cash flow shares so that the flip does not occur until the debt is fully or nearly repaid.

In a partnership flip, the tax equity investor secures its target yield substantially prior to the end of the financing term, whereas a lessor typically is willing to rely on late-term cash flows and residuals to meet its target yield. Leasing may be preferable to the partnership if the tax equity investors rely on late-term cash flows to recover their investments, assume significant residual value for the project and/or bet that the developer will exercise an EBO. For developers who are not overly concerned about their ability to acquire the project residual, or the risk of defaulting on their lease obligations, tax equity pricing that includes a significant residual value assumption or late-term cash flows may also favor leasing.

Apart from the tax attributes and structuring of a transaction, leasing may also offer longer maturity financing than project finance loan tenors.

Wind Energy Subsidies and Incentives

The American Recovery and Reinvestment Act of 2009 (“ARRA”) created the Section 1603 cash grant program (“1603 Program”). In December 2010, Congress extended the 1603 Program one year (through Dec. 31, 2011) under the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (the “2010 Act”) for projects that otherwise qualify under ARRA. The cash grant equals 30% of the cost basis of the energy property. Most, but not all, projects seek to utilize the cash grant.

As administered by the U.S. Treasury Department (“Treasury”), an eligible owner of a qualified energy facility will receive a cash grant within 60 days after a project is placed in service and the Treasury has received a properly and timely completed application. In ARRA Energy Co. I v. United States, No. 10-84 C (Fed. Cl. Jan. 18, 2011), a court determined that the 1603 Program does not provide the government with any discretion to refuse a cash grant when the applicant meets the specific requirements of the statute. Applicants must use care to furnish Treasury with proper documentation to substantiate the cost basis of their property.

If a project takes the cash grant, neither the federal business energy investment tax credit (“ITC”) nor the production tax credit (“PTC”) may be claimed. The project owner must be the original user, except for a sale leaseback to another owner/tax equity investor within the first three months of the date the facility is placed in service. The cash grant is not taxable although it reduces the depreciation basis by one half of the cash grant. Pass-through entities are eligible only if all of their members are eligible.

In the 2010 Act, Congress also authorized owners to write off, in the first year, the entire depreciable basis of qualified property, including turbines and towers, placed in service after Sept. 8, 2010 and before Jan. 1, 2012. For qualified property placed in service in 2012, a 50% depreciation bonus is available. These first year write-offs are not available if the taxpayer (or the lessee in a sale leaseback) committed to acquire, or commence construction of, the property before 2008.

If a wind project has a high net capacity factor, the PTC may provide greater economic benefit for the developer and investors than either the ITC or cash grant. The net capacity factor, which typically ranges from 20%-45% (and higher in some locations), is the ratio of actual energy production to the energy production of a turbine in a given period running full time at its rated power (reduced by operational or other energy losses). More specifically, the “capacity factor” equals the annual energy production divided by the theoretical maximum energy production if the generator were running at its rated power all the year. For example, if a 1500 kW machine makes 3.5 million kWh in a year, that's 3,500,000 / (365 ' 24 ' 1500) = 27% capacity factor. The PTC provides the producer of electricity from a wind facility a tax credit in 2010 of 2.2 cents per kWh computed for each kWh of electricity generated and sold to unrelated third parties, over a 10-year period. In such case, the partnership flip structure can work if the partnership produces the electricity, but leasing does not because under IRC section 45(a)(2)(A) the producer (rather than the facility owner) claims the PTC.

An important non-tax policy incentive for wind projects is a State renewable portfolio standard (“RPS”) or a federal Clean Energy Standard (“CES”), should Congress enact one now that the Administration has thrown its support behind one. According to the “DSIRE” Web site (see Database of State Incentives for Renewables and Efficiency), as of September 2010, 29 states, plus Washington, DC and Puerto Rico, have enacted RPS requirements and seven states have set renewable portfolio goals. An RPS sets a percentage of an electric provider's energy sales (MWh) or installed capacity (MW) to come from renewable resources. To meet the applicable RPS (or a CES, if enacted), utilities and other power purchasers may, as one option, buy electric power from wind projects.

In some cases, the Department of Energy (“DOE”) may subsidize projects through grants or loan guarantees. However, DOE applications require patience, tenacity and diligence. A developer must apply with enough lead time to avoid execution risk or undermine project economic assumptions. An applicant should consider alternative financing for a project should the DOE decline or excessively delay a decision on the application for a grant or guarantee.

Economic Substance: Tax Abusive Transactions at Risk

The economic substance doctrine (“ESD”) disallows tax benefits in transactions motivated excessively by tax avoidance. IRC section 7701(o) codified and enhanced the common law ESD. If a tax equity financing is subject to the new law, in many cases the present value of the tax equity investor's reasonably expected pretax profit must be substantial in relation to its expected net tax benefits. This pretax profitability requirement may differ from how many advisers interpreted prior law. See Report on Codification of the Economic Substance Doctrine by New York State Bar Association Tax Section (Jan. 5, 2011). Exacerbating the problem, the IRS has been unwilling to clarify the statute.

In Historic Boardwalk Hall, LLC v. Commissioner , 136 T.C. No. 1 (2011), the Tax Court upheld a tax equity financing transaction involving tax credits that benefit historic rehabilitation projects. Although the case arose under pre-Section 7701(o) law, the court's generous application of ESD principles may help to resolve how the codified ESD applies to wind energy projects.

Accounting Mayhem

The International Accounting Standards Board (“IASB”) and the Financial Accounting Standards Board (“FASB”) have been engaged in a joint project to overhaul current lease accounting rules under the Statement of Financial Accounting No. 13 (“FAS 13″). They published their proposals in an Exposure Draft for Leases on Aug. 17, 2010 (“ED”). The IASB and FASB may issue a final standard this summer.

The ED contains proposals that lessors and lessees account for leases under a “right-of-use” model instead of the currently available method of classifying leases under FAS 13 into two categories: a capital lease (recognizes an asset and liability) and an “operating lease” (does not recognize an asset and liability). If adopted, the changes will result in the capitalization of lease obligations on the lessee's balance sheet. In addition, the new rules would eliminate leveraged lease accounting, which has encouraged capital investment and benefited leasing for decades. These changes would occur without “grandfathering” of transactions existing on the date of initial application of the final rules.

The final lease accounting changes will affect wind energy transactions as well as other property, plant and equipment. Their significance cannot be overstated. Yet, potential tax equity investors should not assume that developers in wind energy deals will refuse to enter a lease because the lease obligations will be put on the lessee's balance sheet. In some circumstances, project companies may lease a wind project despite these accounting changes because the impact may be neither material nor inconsistent with their respective business models. See Lease Accounting: New Rules and Realities by Shawn D. Halladay, Journal of Equipment Lease Financing, Vol. 29 Number 1 (Winter 2011).

Conclusion

Though partnership flip deals have dominated the wind energy financing market, leasing has been, and continues to be, a multi-billion dollar source of capital for investment in equipment and facilities. The Alta Wind Project, the PRC Project and the Hatchet Project attest to the viability of, if not the demand for, lease financing of wind energy facilities. Lessors can participate in this growing market as tax equity investors through selected opportunities to lease equipment and facilities. However, tax equity investors that remain flexible enough to invest via a partnership flip, leasing or other financing structures may find that their investments buy them a ticket into a bigger game of financing wind energy projects of all sizes and descriptions, well into the future.

David G. Mayer ([email protected], 214-758-1545), a member of this newsletter's Board of Editors, is a Patton Boggs partner in the Business Practice Group in Dallas. Joel Bannister ([email protected], 214-758-6681) is an associate in the Business Practice Group. The views expressed in this article are those of the individual authors and not the views of Patton Boggs LLP.