In the move towards non-carbon-based energy, and the push by Congress to encourage this move to cleaner alternative energy sources, tax incentives have encouraged investments in solar and wind facilities. Financing structures have developed to likewise monetize these tax benefits.
In a recent webinar hosted by Mayer Brown, after-tax returns for selected types of projects were estimated to range from 6.75% to 8.50% for utility-scale solar or wind power, and from 9.00% to 12.50% for commercial and industrial (C&I) solar investments. Accordingly, these returns continue to appear very attractive.
Federal Income Tax Considerations
Alternative energy investments derive economic returns disproportionately from the tax incentives inherent in the projects. Two forms of tax credits are available for alternative energy projects. The Production Tax Credit (PTC), defined under IRC §45, is targeted at wind energy projects. The Investment Tax Credit (ITC) for energy property, currently 30%, is defined under IRC §48 and is eligible for both wind and solar projects. These projects are also largely eligible for accelerated tax depreciation, including the current 100% bonus tax depreciation.
The PTC is earned based on a rate per kilowatt hour of electricity produced from qualified energy resources, largely wind. It can only be claimed by the producer of the energy and is available for a 10-year period from the commercial operation date of the project. Once determined, the PTC rate per kilowatt hour remains the same through the 10-year period. Although the projects typically have a life approaching 25 to 30 years, the credit was meant to create the initial incentive to make the cost of this energy more competitive. The PTC is earned by the energy producer, which is often structured as a “tax-equity flip partnership”. When a partner buys into the partnership, it can claim the future PTCs generated for the period they own an interest in the partnership during the 10-year PTC period.
The ITC, claimable by a wind project in lieu of PTC or by a solar project, is equal to a percentage (currently 30%) applied to the qualified energy property. The ITC accrues only one time when the asset is placed in service and has a five-year “vesting period” wherein if the asset is disposed of prior to that period a portion of the ITC is recaptured. In the case of an ITC investment, the tax basis of the property is also reduced by half of the ITC claimed. Thus a $10 million solar project claiming a $3 million ITC will have a tax basis of $8.5 million that can be depreciated.
Generally speaking with wind projects, the decision to claim ITC versus PTC is often based on the efficiency of the project weighted by the risks of waiting to receive the tax credits over a 10-year period. That is, more efficient projects tend create a present value of PTCs sufficiently greater than the 30% ITC otherwise available. The downside of claiming the PTC compared to the ITC is while the theoretical absolute tax credits may be greater, the investor must also consider 1) whether the project will perform as expected, 2) whether the investor has sufficient tax appetite for the next 10 years to be able to efficiently utilize those benefits and 3) whether tax laws remain stable enough to be able to actually utilize the full PTCs.
In H.R. 1, otherwise known as the Tax Cuts and Jobs Act, a new tax “regime” was introduced, known as Base Erosion Anti-Abuse Tax or BEAT. Under BEAT, a taxpayer (usually a U.S. subsidiary of a foreign entity) must calculate its taxes two ways and pay the higher of the two taxes. The PTCs and ITCs from alternative energy investments are reduced somewhat in the BEAT formula. Therefore, if an investor assumed a PTC of $10 million to achieve its targeted return, when it calculated its BEAT liability a portion of the PTCs assumed may be lost and the project yield may be reduced. This “after-the-fact” tax law change did not provide a grandfathering clause and is a “back-door” means of changing existing tax law, albeit in this case for only certain investors. Nonetheless, this example illustrates the risk and potential uncertainty of relying on a 10-year tax benefit, particularly in a volatile political environment.
How Are Alternative Energy Tax Benefits Monetized?
The first option to consider may be a true tax lease. However, for tax-exempt off-takers such as municipalities, many colleges and government agencies, leasing the facility is not economically feasible because under the tax code, leasing to a tax-exempt entity changes the type of tax depreciation that may be claimed and eliminates the ITC.
Alternatively, a tax-exempt entity may be able to finance the project using a commercial loan or tax exempt-debt, but it would not receive the 30% (or more) of tax credit subsidies.
The more widely utilized approach is known as a “service contract” for alternative energy assets under IRC Sec. 7701(e)(3). Under these favorable rules, the service provider owns the assets, produces electricity and sells “services”, in this case electricity. By selling electricity rather than leasing the asset, the service provider is entitled to claim both accelerated tax depreciation and either the ITC or PTC as part of the transaction. The off-taker buys all or most of the energy produced as a supplement to obtaining energy from the local utility. As long as the sun shines or the wind blows, energy is produced and the off-taker buys that energy.
Larger projects are often developed by an entity that does not have the capacity to efficiently absorb all the tax credits and initial tax losses, either because the developer simply does not have a large taxable base or because it has many other projects which have already created tax benefits resulting in a limited tax appetite. The challenge then is how to efficiently monetize these robust tax benefits: the 30% ITC or PTCs often exceeding 30% on a present value basis, and the highly accelerated tax depreciation currently at 100%. As a point of reference, a $100 million ITC transaction could produce tax savings of almost $50 million in the first year; $30 million of ITC and $18 million from the immediate write-off of $85 million.
This is solved with what is known as the “tax-equity flip structure”.
The transaction usually starts with the formation of a limited liability company (LLC) taxed as a partnership for federal income tax purposes. All taxable income or losses and tax credits flow-through to the partners, who are divided into two classes: the developer who acts as the managing member and makes day-to-day management decisions and the tax-equity investors, which are somewhat less active partners.
Subject to certain rules, IRC partnership regulations permit 1) cash distributions, 2) taxable income and losses and 3) tax credits to be allocated in a manner different from the ownership percentages. The partnership agreement initially allocates the majority of free cash, PTCs or ITCs and early year tax losses to the tax-equity investors. The tax-equity investors essentially receive the majority of their economic return in the form of the cash equivalent of tax benefits. Tax losses have a cash equivalent value equal to the loss times the federal tax rate and tax credits are equivalent dollar-for-dollar.
Basically, the tax-equity investor is there to monetize the tax benefits for the developer. These flip partnerships are subject to technical partnership tax regulations and a safe-harbor promulgated by the IRS in Revenue Procedure 2007-65 which is outlined in the table below.
The allocations of the different elements during the investment are as follows:
|Phase||Phase Description||Free Cash||Tax Benefits||Free Cash||Tax Benefits|
|0||Development of project||None; funding project||N/A||Committed but not funded|
|1||Initial tax-equity period||100%||1%||0%||99%|
|2||Tax-equity earning period||0%||1%||100%||99%|
Although the tax equity investors receive the majority of free cash during the earning period of the transaction, often there is little free cash actually available. The tax equity investors in realty receive the majority of their return in the form of the tax credits and the cash equivalent of the tax losses that are allocated to them.
The typical transaction can be broken down into several different actual phases which follow the tax allocations as follows
Phase 0 — The developer selects a site, contracts for wind studies, estimates the project cost and output, determines if the cost at which they can sell the power is economical to the buyer and then obtains commitments for the purchase of power. The developer then arranges construction financing based on the commitment to sell the power. Lastly, the developer seeks equity investment commitments from tax-equity investors subject to all of the other circumstances occurring successfully. Tax equity investors will typically not be able to make a tentative commitment until the project is within a year of completion.
Phase 1 — At or around the commercial operation date (COD) when the project is essentially complete or very near completion and nothing stands in the way of it entering into commercial operations, the tax-equity investors close on the funding which usually pays off the construction financing and repays the developer a portion of its initial investment. The facility can usually be funded for its projected fair market value which is based on the normal construction costs plus a reasonable profit and is also subject to what energy the facility is expected to produce based on the rates established in the power purchase agreement. At this point some developers seek to take a certain amount of profit out of the transaction for all their earlier work and investments. Tax equity investors will permit a certain amount to be taken out but want to ensure that the developer stays invested in the project to ensure that it is maintained and operating during their investment period. Once the facility is placed in service, the developer is initially allocated a substantial portion of free cash to continue to recoup some of its investment while up to 99% of tax benefits are allocated to the tax-equity investors. The specific free cash allocation is a point of negotiation.
Phase 2 — After the developer has taken out the negotiated cash, the partnership makes its first flip and generally the partnership agreement provides that 100% of the free cash and 99% of the tax benefits are allocated to the tax-equity investors. As stated above, during the operations period there often is not an abundance of free cash and the tax equity investors returns are largely from the tax benefits allocated to them. Under partnership tax rules, the tax equity investors’ ownership interest increases or decreases based on profits or losses allocated to it and decreases based on cash distributed to them. Thus, over time the tax equity investors’ tax basis in the investment is decreasing.
Phase 3 — Around the time the targeted AT IRR for the tax-equity investors is expected to be achieved based on the nature of the tax credits claimed (investment tax credit or production tax credit), the developer is commonly provided an option to buy out the tax-equity investors for a fair market value usually defined as the greater of the fair market value of tax-equity investors’ partnership interests and the value required to ensure that the tax-equity investors’ achieve their targeted AT IRR. Since the fair value of the tax equity investors interests is directly related to the partnership allocations which now have decreased substantially as per the partnership agreement, that fair market value is generally approximately equal to the remaining nominal tax basis in the investment. So generally there is little tax effect of the buyout. If for some reason the planned benefits and free cash do not work out as expected, the developer can usually buy out the tax equity investors by making them whole with respect to the targeted IRR. This is accomplished by a grossing up of the amount paid, always targeting the after tax IRR.
The tax-equity flip structure is highly complex and summarized in its most basic form above. There are many more tax rules which must be followed, and the financial model used to calculate the business plan of the partnership — along with the allocations of the cash and tax benefits —add to the complexity. Additionally, the accounting for the transaction follows a unique approach under U.S. GAAP known as “hypothetical liquidation at book value” or HLBV.
One large obstacle to overcome when deciding whether to invest in these transactions is explaining to upper management that the yield is on an after-tax basis and largely comes through the tax-provision line on the income statement and also through the deferred taxes created by the accelerated tax depreciation. That is, tax credits flow through the tax provision line as a reduction of the tax provision. Most organizations and managers measure themselves on a pre-tax basis under the theory that the taxes are something the managers generally have no control over.
Nonetheless, the benefits of investing in these transactions are 1) a robust after tax return, 2) a high probability of achieving this return given it is largely from tax benefits and the generation of power is highly probable given mother-nature, and 3) the satisfaction in knowing that your investment is taking a positive step towards more clean energy.
A future article will discuss the complex accounting treatment afforded these investments and point out some of the challenges associated with investing in them as a result of that treatment.
Joe Sebik is a CPA who has worked in the equipment finance industry since 1980. He has worked for PriceWaterhouse, IBM Credit, Citicorp Global Equipment Finance, Chase Equipment Leasing, JPMorgan’s Tax-Oriented Investments group and Siemens Financial Services. His roles during his career have spanned all aspects of equipment finance, from auditing to financial reporting to transaction structuring and marketing to tax reporting. He has been on the ELFA’s Accounting Committee since 2005 and has been the chairman of the ELFA’s Federal Tax Committee since 2013. He has written extensively about the industry including numerous technical portfolios for Bloomberg/BNA on both lease accounting and the economics of equipment finance.
Disclaimer – This article represents the views and interpretations of the author and does not reflect any of the positions, views or opinions of the company for which the author works. None of this information should be viewed as providing of tax or business planning advice. In all cases you should consult with your own tax counsel regarding any actions or positions you take.