Proximo Weekly: Are you PTC or ITC?
The Inflation Reduction Act has given US solar developers a choice of two types of tax credit – ITC and PTC. So how to get the best from the system? Match the right tax credit with the right solar project characteristics.
The scope of the Inflation Reduction Act (IRA) is vast and the full impact of the watershed legislation on the US renewables space has yet to be seen, particularly as the IRS is still drafting more specific guidance on the law’s application. But one major change for renewables is clear – the IRA makes production tax credits (PTCs) available to solar projects and enables tax credits to be transferred.
Signed into law by US President Joe Biden on 15 August 2022, the IRA will ensure that current tax credits are extended until the end of 2024, after which a new clean electricity credit will apply until the end of 2023. Solar projects are now eligible for PTCs, along with other renewable energy technologies such as biomass, geothermal, and hydropower. Investment tax credits (ITCs) remain available for solar projects and developers can choose between the two types of tax credit. Selecting the PTC or the ITC for a given project depends on its location to a significant degree.
Discussing this choice, Jason Segal, a managing partner at Javelin Capital, notes: “A new development for solar projects post-IRA is that there is flexibility for choosing between the PTC and the ITC. Based on pure project economics, there will be many situations in which the PTC is more attractive for solar projects. In cases where you have relatively high production from higher irradiation and relatively low capex, such as in the desert south-west as opposed to New England, it is logical that the PTC will yield better economics. In a high-capex area with relatively low irradiation, the ITC will probably be better and also provide more attractive adders than the PTC.”
Solar irradiation in the south-west is generally high, while the north-east has lower levels of irradiation on average. Project costs also tend to be higher in the north-east, which largely makes use of unionised labour and has a greater concentration of hills and uneven terrain. By contrast, the south-west has, in general terms, a less unionised labour market and flatter terrain. A similar analysis could, of course, be applied to other parts of the US, but the differences between the south-west and north-east are the most illustrative of differences in capex and solar production potential.
Solar projects in the south-west will gain from using the PTC, as energy production is likely to be high due to irradiation levels, while capex is low relative to projects in other areas. Making use of a tax credit that applies to energy produced rather than capital cost is therefore appealing. Projects in the north-east stand to benefit from using the ITC. The ITC is based on capital cost – which is relatively high for such projects – rather than on production, which is low compared to projects in other regions. According to some market estimates, the project-level return for a PTC solar project in Texas before tax equity and before leverage could be as much as 200bp better than for an identical ITC project.
Where PTCs are suitable for projects, using these tax credits might be more straightforward than is the case for wind projects, which have long been eligible for the PTC. Solar energy generation is far easier to predict than generation from wind and some solar resource is available each day. It is also simpler to calculate a minimum level of power production across the different seasons. This level of predictability may be desirable for tax equity investors considering a solar PTC project.
A factor that may make PTCs less viable is curtailment risk, although this risk is only a major consideration in certain regions. Notably, ERCOT currently has some grid capacity constraints, while Texas is one of the best locations for solar projects in terms of solar resource. From a tax equity investor’s perspective, returns from an ITC solar project are less affected by curtailment than returns from an equivalent PTC project. While a tax equity investor in an ITC project that is curtailed will lose some cashflow from the project, tax credits earned from investment in the project will be wholly unaffected unless the curtailment is so severe that the project fails, which is fairly unlikely. By contrast, PTC projects only earn tax credits for the energy that they supply to the grid, meaning that curtailment risk is a significant concern for tax equity investors backing a PTC project. Curtailment will, therefore, be a factor when developers are deciding whether to opt for the ITC or the PTC.
A further area of consideration that might make the ITC more tempting in some circumstances is the bonus tax credits that can be claimed for projects that meet certain criteria. Under the PTC and the ITC, solar and onshore wind projects (amongst other technologies) that source 40% of their steel, iron, or manufactured products from domestic suppliers qualify for a 10% bonus tax credit. Similarly, both PTC and ITC projects qualify for a 10% bonus if located in an energy community, which, according to Linklaters, refers to ‘brownfield sites or areas that previously had significant employment relating to coal, oil or natural gas’. However, only ITC projects qualify for a further 10% bonus tax credit that applies to small-scale solar and wind projects located in low-income communities, or a 20% bonus tax credit for projects that form part of a qualified low-income residential building project or a low-income economic benefit project.
It remains to be seen if these tax credits are ‘stackable’, although market sources confirm that it is probable that multiple bonus credits can be accrued. In some instances, it might be possible for solar or wind projects to claim a bonus of 30% or even 40% under the ITC, where these projects would only be eligible for a 20% bonus under the PTC. Instances of overlapping bonus tax credits might be rare, particularly given current domestic renewables manufacturing limitations in the US. The choice between the ITC or the PTC, while not irrelevant to onshore wind, will be most applicable to solar projects, given the historical preference of wind projects for the PTC.
Transferability: An alternative to the tax equity partnership
Both ITC and PTC tax credits are now transferable, meaning that they can simply be sold to a third party rather than earned by a tax equity investor in a tax equity partnership. Some potential advantages include avoiding the lengthy administrative process of forming a tax equity partnership and any associated transaction fees. These fees can be prohibitively expensive for small projects, making a transfer an appealing option. If a project needs to become operational particularly quickly for reasons such as satisfying offtaker demand, developers now have the option to sell credits directly. The primary disadvantage of a transfer is that it will not necessarily raise as much capital as a tax equity partnership, as tax credits must be discounted by a certain number of cents on the dollar to make purchasing the credits worthwhile for the buyer.
In addition, as Matthew Shanahan, a managing director at Marathon Capital, notes: “When you sell tax credits, you cannot sell the depreciation, so that stays with the project. In an ITC project, the depreciation probably has 100-150bp of value. If a sponsor’s return is 8% with tax equity and back leverage, in a transfer this return might be 6.5%. In a PTC project this is probably a 200-250bp spread, because the PTC is more effective at monetising tax losses. So the go-to structure is still going to be tax equity partnerships. The transfer market will be useful in certain situations, such as when because of the sponsor, the market, or the offtake, tax equity is not comfortable entering into a partnership and exposing itself directly to that risk. There could be a structure, particularly for PTCs, where a tax equity investor agrees to buy the PTCs for the next ten years at a fixed price, but only for actual production.”
The fact that depreciation cannot be included when selling tax credits means that in a transfer deal, developers have to take a haircut, as depreciation can be claimed in a tax equity partnership. Nonetheless, the decision as to whether or not to opt for a transfer will be influenced by whether a tax equity partnership is possible at all. If tax equity investors deem a project too risky for such a partnership, they could still agree to buy the tax credits, giving sponsors access to capital that would otherwise be unavailable and making a transfer the only option.
The choice to use a transfer will also be affected by interest rates. In a low interest rate environment, a transfer would allow the developer to raise inexpensive debt to finance the majority of the project cost. This debt can be cheaper than tax equity, offsetting the capital lost through both the discount and the inability to sell depreciation. With the Federal Reserve’s target policy rate sitting at 3.75-4% at the time of writing, the option to transfer tax credits carries fewer benefits than it would have done a year ago.
Calculating the point at which a transfer might be of a similar value to a partnership is a complex process. Discussing this, Martin Pasqualini, a managing director at CCA Group, says: “The question we are frequently being asked is where the “cross-over point” between traditional tax equity partnerships and transfers is, by that I mean where the level of discount on a transfer is such that a traditional tax equity transaction has an economic advantage over a transaction involving the transfer of credits. That is an evolving question as we came to the realization that the transfer results were very sensitive to interest rates. One of the built-in assumptions for a transfer case was that you would get better debt execution.
“However, the dramatic increase in underlying interest rates as well credit spreads negatively impact the hypothetical transfer case. In very rough terms, the cross-over point when we first started comparing cases was in the low 90 cent range, but now it is closer to 97c. We have received some transfer proposals on behalf of some clients and the discounts that are being offered right now are greater than 3c on the dollar. We have seen transfer proposals as low as 84c on the dollar and as high as 92c, so you are going to leave some economic value on the table in a transfer transaction as compared to a traditional tax equity partnership transaction.”
Transfer deals may see striking changes to the nature of renewables financings. There may be an opportunity for experienced tax equity providers to play an underwriting role with the sale of tax credits. Once purchased, it is unlikely that tax credits can be sold down further, as would be the case with debt. If an institution is to act as an underwriter, this will require a further discount to the tax credits to allow the underwriter to earn a fee. If partial transfers of tax credits are allowed, an investor with a large tax equity ticket in a project may decide to sell some of the credits earned if its tax capacity becomes unexpectedly limited in a given year.
Perhaps most interestingly, transfer deals might see banks lending to renewables at the project level, rather than through a back-levered structure, as is usually the case with a tax equity partnership. This could lower the margins on renewables debt. As Shanahan points out: “When financing a project transferring tax credits, you could raise debt against the cashflow of the project and the obligation of the tax equity provider buying the transferable credit to commit funds. There would be two tranches of debt with one tranche functioning like a tax equity bridge loan, except instead of just bridging construction, it bridges the full ten years of PTC and construction. On that basis, I also think that project-level debt makes sense.”
The Proximo perspective
Much has yet to be made clear about how the IRA will be applied in practice. As Andrew Compton, a partner at Linklaters, says: “We are awaiting guidance from the IRS on both the energy community bonus and the domestic content bonus, in order to better understand how these additive credits will be defined. More generally, I think the tax equity bar is still working its way through the IRA as we look to structure projects under the new tax equity regime.”
It is, nonetheless, evident that the IRA will provide more options for renewables investment. PTCs will make solar projects in locations with high irradiation even more competitive. The fact that solar projects have more reliable production forecasts than wind might widen the pool of PTC investors beyond the small group of established PTCs investors that mostly includes large banks such as Goldman Sachs, Wells Fargo, Bank of America, and JP Morgan.
Transfer deals will allow projects considered too risky for a tax equity partnership to receive investment. Investors will be largely insulated from opex exposure in such a transfer deal, as no project cashflows are allocated to the purchaser. The investor either buys the ITC credits upfront and has no further involvement with the project or buys PTCs as and when they are earned. The PTC transfer is the equivalent of a PAYGO structure for 100% of the tax equity investment, rather than the 25% allowed in a PTC partnership.
It is currently assumed that a five-year recapture period will apply to ITCs sold in a transfer – as would be the case in a partnership – to make sure that ITCs are earned for projects that actually operate. This will necessitate some documentation such as an indemnity from the seller of tax credits that is backed by a creditworthy entity and there will probably be covenants designed to protect the purchaser from recapture liability. Returns on transfer deals could be lower for investors than in partnership deals due to the lack of project cashflows, but as transfer deals will often take place where a partnership is not possible, such deals will still hold value for investors.
The expanded range of investors now open to developers may even include pension funds, which as tax-exempt entities may be able to access a ‘direct pay’ option, in which they claim a direct tax refund to the value of tax credits earned. If pension funds can use this option while co-investing with a developer, the number of investors accessible to developers will be orders of magnitude higher than the present number of tax equity investors. Lenders will have to become comfortable with these new participants in the US renewables market, as well as with contingent PTC revenues if providing project-level debt. Project debt has seldom been leveraged against PAYGO payments, but the additional revenue stream might increase debt capacity and could function similarly to a PPA.
The alterations made to renewables investment incentives by the IRA will not change tax equity in its entirety. What the IRA will do is create further pathways by which project sponsors can access capital via tax equity. This might lead to riskier investments in some instances, particularly if less experienced investors enter the market. But the legislation will deliver a shake-up to US renewables investment and will ask tax equity investors to work slightly harder to offer value to developers as different sources of capital become available.
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