TerraGen’s recent announcement causing us to consider leasing’s in wind project finance
We start with a statement of the obvious: leasing as a method of big-ticket finance is not as popular as it once was. The decline in the popularity of leasing is due in part to coincidental industry distress (e.g. airline bankruptcies) that disrupted great numbers of lease transactions, in part to successful IRS challenges to the treatment of certain leasing structures (e.g. SILO / LILO) and the enactment of rules that in certain cases eliminated the ability to offset leasing losses against other taxable income (IRC Section 470), and in part to other financing vehicles that accomplished similar goals. We suspect these days more than one veteran leasing expert has found himself thankful for the work required by the approaching termination date of a twenty –year lease.
That said, those of us engaged in the renewable energy sector have heard and had much discussion of late concerning the possibility of financing renewable energy projects using lease structures. Solar energy projects have commonly been financed using a lease structure. The economics of a solar project and the relevant provisions of the federal tax code providing investment tax credits (“ITC”) to solar energy investors have combined to support this vehicle. Wind energy projects have, until recently, not been amenable to lease financing for a variety of reasons, though thought most obviously because the production tax credit (“PTC”) rules available to wind projects precluded it.1
The 2009 American Recovery and Reinvestment Act (the “Recovery Act”) opened up the discussion by extending the ITC (and its ability to be monetized through a lease finance) to wind projects. This change allows for the possibility that one entity (a tax equity investor) may own a wind project and claim the ITC while another entity (the operator) may be the lessee of the project and operate it. (Solar energy projects remain amenable to leasing structures.) The relevant rules are in fact flexible enough to allow either the lessor or the lessee to claim the ITC based on agreement and subject to certain limited conditions.
The Recovery Act also created a 30 percent cash grant (“Cash Grant”) equivalent of the ITC, to be paid out within 60 days of project’s commercial operation rather than realized in connection with an applicant’s tax return.2 Each of these three options (PTC, ITC or Cash Grant) is mutually exclusive. Each project may take advantage of only one of these benefits.
Congress staggered the sunset date of the Cash Grant depending on technology and project completion date (with exceptions for certain projects that begin construction by the end of 2010). For purposes of this article, it is enough to say a project must commence construction by the end of 2010 in order to claim the Cash Grant. If that condition is satisfied (not a simple question to answer), a wind project has until the end of 2012 to reach commercial operation and claim the Cash Grant and a solar project has until the end of 2016.
Given the preceding changes instituted by the Recovery Act and the rules that were left unchanged, the state of affairs which results is: (1) federal tax benefits for solar projects could previously and still may be financed using a lease structure; (2) federal tax benefits for wind projects may now be financed using a lease structure; and (3) though we do not have numbers to prove up this point and notwithstanding points (1) and (2), it seems most financings in 2010 have taken advantage of the Cash Grant to the developer utilizing straight debt or on-balance sheet financing. This is likely caused by the notion of “a bird in the hand…” and the still somewhat sticky tax equity and bank debt finance market.
Yet, it is still possible to claim the Cash Grant and finance a project with a lease structure. A lease structure in the energy space most commonly involves a project owner (the lessor) and an operator of the project (the lessee). Typically, the lessor is a financier with an appetite for the tax attributes associated with ownership of the project. The lessee is most often the developer of the project who, for various reasons, does not share that tax appetite. At financial close, the developer (and lessee-to-be) sells the project to the financier and immediately leases the project back from the financier (now a lessor).3 If the financier-lessor borrows money to fund some or all of the purchase price of the project, the structure becomes a leveraged lease.
Selection of the Cash Grant leaves a project with 85 percent of its qualified costs to depreciate on an accelerated basis.4 And the check from the US Treasury for 30 percent of the qualified costs can be directed to the lessor, as can the ITC. There is a difference of timing and some time value of that amount, but the overall effect on project economics is usually slight. So, after taking advantage of either the Cash Grant or the ITC, a lessor would have the tax benefit of accelerated depreciation of 85 percent of the project’s qualified costs.
With all that flexibility, why have leases in the wind space been so rare? We think there are three main reasons. First, the established pattern for wind project finance involves an equity investment colloquially known as a “partnership flip,” a structure for which the IRS has provided “safe harbor” status. The tax equity investor puts its capital directly in the entity owning the project as a co-investment with the existing sponsor’s equity. The tax equity investor receives the lion’s share (nearly all) of the federal tax benefits until those benefits have been exhausted. During this first phase, most of the cash income from the project is allocated to the sponsor. After the tax benefits have largely run out, the allocation flips and the tax equity investor receives cash until it realizes its desired return through the combination of prior tax benefits and cash.
Owing to the wide-spread acceptance of the partnership flip structure in the wind industry, it likely seems more efficient to many participants simply to continue with the tried and true method. Lawyer and consultant costs are minimized and the parties have a high degree of confidence that the structure will function properly and without being challenged by the IRS.
Second, we believe market participants recognize a potential disparity in the short term volatility of wind resources compared to solar resources. The greater short term volatility of wind resources may cause many participants to view the lease structure, with its required payments of rent each quarter, as incompatible which such volatility. On the one hand, investors want stability and therefore require reserves or indemnification where stability lacks. On the other hand, sponsors do not wish to see their returns diminished by having to establish reserves to deal with resource volatility.
Finally, we believe the purchase option and other legal requirements that attend lease finance make such a structure in the wind space less likely to be chosen. With lease financing, the sponsor, if it wishes to re-assert control over the project, needs to repurchase the project from the lessor at fair market value, such value determined without any reduction of the lessor’s interest to 5 percent (as will be the case in a partnership flip). With a partnership flip structure, the sponsor typically can buy out the tax equity’s interest after it has flipped down to only 5 percent and the agreed upon return has been realized.
In addition, there are often times greater reserve and/or rent pre-payment requirements in a lease structure (these in addition to what was discussed above in connection with resource volatility). There are also complicated valuation requirements in connection with a lease driven by IRS “true lease” guidelines and case law that require that the leased property be expected to have a meaningful residual value and remaining useful life at lease end. The lease guidelines set forth a “20/20” residual requirement, meaning that at lease inception the facility be expected to be worth, at lease termination, at least 20 percent (plus inflation since lease inception) of the facility’s initial inception cost to the lessor and have a remaining useful life, at lease termination, of at least 20 percent of its appraised estimated useful life at lease inception. In short, under the flip structure the sponsor’s purchase option can be as low as 5 percent of expected fair market value perhaps 10 years out while its purchase option under lease can never be less than 20 percent plus inflation (likely to approach 30 percent after 20 years).
Because the wind industry has an acceptable, IRS sanctioned, alternative that can accommodate the changes in the Recovery Act and provide a lower buyout price, it is understandable that such an alternative would remain the primary vehicle for tax benefit monetization.
We do note that the lease structure is not without significant advantages. Lease financing provides a developer with a day-one, full takeout of the developer’s costs in the form of 100 percent financing. Lease financing may also provide a lessor with preferred accounting results if the lease qualifies for leveraged lease accounting under FAS 13, permitting the lessor to report most of its financial profit in the very early years of the lease.
Endnotes:1. For 2010, the PTC is worth 2.2 cents per kilowatt hour.
2. Being lawyers, we must add for completeness that the Recovery Act affected all manner of renewable energy projects and products, in addition to much else. We have assumed the audience for this piece has some familiarity with the Recovery Act as it affects renewable energy generally. With that audience in mind, we address here only large-scale wind and solar projects and then only certain aspects of the Recovery Act applicable to those technologies. We believe those projects comprise the lion’s share of deal activity and focus amongst the large financial institutions, developers, and their consultants and lawyers.
3. Technically this is a sale-leaseback, though it is so common in the energy sector that most references are simply to “leases,” the understanding being it is necessarily a sale-leaseback.
4. Special rules reduce the depreciable tax basis by only 15 percent of the qualified costs of the project rather than the 30 percent represented by the Cash Grant.