It still feels like Christmas morning for the US renewable energy industry, with so many presents scattered among the torn-off wrapping paper. Months after enactment, market participants have yet to fully appreciate all that was provided in the Inflation Reduction Act. By Paul Astolfi, Nadav Klugman and Eric Pogue, Mayer Brown.
Additionally, the US Treasury, Internal Revenue Service and Department of Labor guidance on existential questions such as prevailing wage and apprenticeship rules have come so far only in drams, not full pints. Further guidance on these issues – and other critical matters including equipment sourcing and project siting – will be critical before achieving anything near certainty for a particular project. One thing is certain, however: the IRA creates increased flexibility for financing structures. Three in particular are the new resource-neutral Investment Tax Credit (ITC) and Production Tax Credit (PTC), the opportunity to earn ITCs for standalone storage, and transferability of both ITCs and PTCs outside of traditional tax equity structures.
In this article we will explore the benefits of this increased flexibility from the perspective of parties to a hypothetical utility-scale solar-plus-storage project financing. Specifically, we discuss four different financing structures that are available under the new law and some of the advantages and disadvantages associated with each.
* Base case – An ITC partnership flip, through which the tax credits for the solar and storage project are monetised by a single tax equity transaction. In the base case, we have assumed construction and, at term-conversion, back-leverage debt.
* PTC case – The second is largely similar, except that the solar portion of the project will elect PTCs.
* Standalone case – Third, we have considered a structure made possible through the new IRA stand-alone solar ITC. Specifically, in our third scenario, we discuss the battery as a standalone ITC financing.
* Transfer case – Finally, we will avoid the tax equity structure entirely and instead have the project sell the ITC for cash on the open market using the new transferability provisions of the Act.
Each has advantages and disadvantages, and we expect all of them to be used at some point in the coming years. There is no one-size-fits-all solution to financing renewable generation optimally, but this rising tide is likely to lift all ships and could even usher others into the harbour at the same time.
Our base case will look familiar to US renewable energy market participants. It has been the primary structure in the market for solar-plus-storage transactions prior to the passage of the IRA. It starts with a solar project and BESS owned by one or more special-purpose entities, the ProjectCos. The ProjectCos are in turn owned by a single holding company, the HoldCo, which will also serve as the vehicle in which the outside tax equity investor holds an ownership stake creating a partnership at the HoldCo level for US tax purposes. The HoldCo, once the tax equity transaction closes, will have two classes of ownership interests – Class A, or the tax equity membership interests, and Class B, or the cash equity membership interests. While the focus of this article is not on the finer points of the partnership flip structure, we would note the following regarding the tax equity transaction:
i) An amount of tax credits (ITC) – based on the eligible basis – effectively the value, as determined and supported by a third-party appraisal – of the solar project and the BESS – will become available to the Class A and Class B members of HoldCo when the solar project and BESS are placed in service.
ii) Under an ITC partnership flip structure, the tax equity investor must be an owner of the HoldCo prior to either the solar project or BESS being placed in service. The prevailing market structure for ITC partnership flip transactions consists of a two-stage closing: an initial, typically 20%, funding by the Class A tax equity investor just prior to the placed-in-service date, followed by a second funding, typically 80%, after the project is placed in service. The initial funding date coincides with the Class A tax equity investor taking title to the Class A membership interests in the HoldCo.
iii) The ITCs that are available to the HoldCo, along with other tax benefits, most notably depreciation, and revenue from operating the solar project and the BESS, are allocated between the Class A tax equity and Class B cash equity members – with the common approach being to allocate 99% of the tax benefits to the tax equity investor. The tax equity investor typically makes its up-front funding in two parts in the same year in which the investor is also able to recognise 99% of the ITC associated with solar project and BESS. This effectively means the tax equity investor is repaid a significant portion of its investment in year one – with the remaining principal and return coming to the tax equity investor in future years through remaining tax benefits and distributions of a portion of the project and BESS revenues.
iv) Once the solar project and BESS are placed in service, the tax equity investor cannot transfer its interests to a non-affiliated party during a five-year recapture period.
v) Prior to the passage of the Act, only BESS systems that were collocated with (and charged by) a solar system were eligible for ITCs. Under this construct, the BESS was considered, for legal and financing purposes, to be part of the solar system – with the BESS being treated like the inverters or racking systems. Prior to the Act, third-party tax equity financings were only possible with the solar system and BESS system being financed as a single asset with the same set of papers, investors and lenders.
With respect to the debt utilised in this base case, we have assumed a typical construction financing and back leverage. A credit agreement will be signed simultaneously with the tax equity investors signing their commitment. Normally, immediately following those closings, the sponsor will issue the notice-to-proceed under the construction contracts. With respect to the construction period financing, the ProjectCos and project assets serve as primary collateral for the debt.
The lenders also have the right to step in, complete the project, and cause the tax equity investor to fund. On the first funding date of the tax equity transaction (as noted above, just prior to the project and BESS being placed in service), the construction debt remains in place along with the full security package – notwithstanding that tax equity will have come into the transaction. On the second funding date of the tax equity transaction (as noted above, just after the project and BESS have been placed in service), the construction debt is paid off in part, and the remaining debt converts to a term loan facility (back-leverage). The security package at the ProjectCo level is released, and the term debt become the primary obligation of the Class B member with no security below that level (ie, the back-leverage lender only benefits from a pledge of the Class B cash equity interests in the HoldCo).
* Why will project participants continue to utilise the base case structure? – Over the last several years, the overwhelming majority of solar-plus-storage transactions have been financed using this tried and tested structure. The simplicity of the structure and familiarity to developers, investors and lenders is based in part on the fact that the transaction differs little from a solar (without storage) ITC transaction. Other than additional diligence related to technical, offtake contract and tax matters with respect to the BESS, the treatment of the BESS mimics the solar project. Accordingly, the transaction documents, the model and the ancillary documentation (such as appraisals) are largely unchanged from a solar-only deal.
Beyond familiarity, there are certain benefits to ITC-only transactions relative to the structures described below. Although these are deal-specific, advantages include (i) the fact that there is a large pool of investors for ITC transactions (many investors prefer, for example, the timely receipt of the ITC tax benefit relative to the up-front investment as well as the fact that the investor’s tax liability can more easily be forecast for such a short horizon); (ii) the base case structure allows a developer to monetise (via a third party) the majority of the tax attributes associated with the project (including depreciation); and (iii) the ITC-only structure (relative to a PTC transaction) is more insulated from production and curtailment risks (in a PTC project, if power is not being produced, PTCs are not being produced).
Why will project participants consider alternative structures? – As discussed in more detail below, there are certain advantages created by the alternative structures that are available as a result of the IRA – these include the ability to claim solar PTCs, which is preferable for some investors and, in many cases, may result in better economics for developers. In addition, over time, just like developers, investors and lenders have become accustomed to the base case, we expect that certain project participants will develop preferred structures (and documents, models, etc) which in turn may lead to programmatic approaches for certain sponsors and the benefits of scale that follow. For example, it may be the case that certain developers partner up with tax credit “buyers” and prefer the simplicity of transferability over the more highly structured base case.
In this scenario of many flavours, we assume that the parties will claim an ITC on the BESS portion of the project and PTCs on the solar portion of the project. The ITC is a function of the cost to the owner to build the project; the PTCs are a function of how much energy the project produces during its first 10 years of operation. As noted above, until passage of the Act, this was not possible – solar was eligible only for the ITC, not PTCs, and BESS was eligible for credits only as a component of an energy project, not on a stand-alone basis.
Splitting the BESS and solar components of the project for purposes of the tax credit should be possible even if the components share the same site and even the same offtake arrangement, but sponsors will need to be able to demonstrate that the BESS functions on a stand-alone basis.
Simply, a project’s developer typically will seek to maximise the size of the tax equity investment, and will choose PTCs over the ITC if it believes that the net amount it will receive from the tax equity investor will be higher.2 A higher tax equity investment may also have the benefit of allowing the tax equity investor to utilise the project’s available depreciation benefits more efficiently.
The comparison of the value of the available ITC and PTCs will depend upon two economic inputs – the aggregate construction and development cost and the project’s expected production (the latter often calculated as the project’s “net capacity factor”, which is a comparison of the project’s output with its nameplate capacity). Expected production is impacted by the efficiency of the project’s equipment, the available solar resource, and potential curtailment, among other factors. The lower the cost and the higher the production, the likelier it is that the PTCs, even discounted to reflect the 10-year production period, will be higher than the ITC. As a result, PTCs will be particularly attractive for larger utility-scale projects, typically built at a lower per-kW cost and with higher expected capacity factors.
The difference in available ITC and available PTCs is not the only point of analysis in determining which credit will lead to the higher net amount of tax equity financing that will be available for the project. In most ITC structures, the developer will sell the project to the tax equity partnership, for the project’s appraised fair market value, in order to “step up” the project’s asset basis for purposes of calculating the available tax benefits, including the ITC. The developer will realise a gain to the extent that the sale price exceeds cost.
The tax equity proceeds actually available to the developer will generally be calculated net of the tax liability on that gain. Gain is not able to be avoided simply by eliminating that sale, but it is possible. Most tax equity investors will limit the amount of the step-up they will finance – this is often 20% of the project’s “hard cost” – and in some cases, particularly for smaller projects, will require the project to obtain insurance to cover the risk that the IRS will challenge the determination of fair market value. In contrast, transaction costs may be higher in a split ITC/PTC transaction.
The sponsor’s preference for the ITCs or PTCs may not, however, be the deciding factor – a tax equity investor must agree, and different tax equity investors have different preferences that will impact the decision. While there may be more available PTCs, certain tax equity investors prefer ITCs because they are received in the first year of the investment, resulting in less need to project the investor’s tax liability far into the future. Other tax equity investors prefer PTCs to allow them to make more tax equity investments by spreading the repayment over longer periods.
Certain tax equity investors prefer PTCs because of the ability to utilise a “PAYGO” structure – up to 25% of the total tax equity investment amount can be made over time, contingent upon the actual PTC-eligible electricity generation at the project.3 The structures that the tax equity investor is willing to offer the project may differ from the “optimal” result from the developer’s perspective.
A key provision under the Act is the availability of standalone ITC for storage projects. This means it is now possible to monetise the tax credits from a BESS regardless of whether such system is part of a solar project or charged exclusively by renewable energy. With reference to our hypothetical solar-plus-storage project, this creates the possibility of a third structure – an ITC tax equity financing for the BESS that is completely separate from the solar project (different tax equity partnership, different tax equity investors, etc).
Standalone BESS financing creates opportunities to have different project (and financing) timelines and to bring in different financing parties. If a solar asset is going to be placed in service in 2023 and the BESS is expected to follow one or more years later, for example, the ability to develop and finance the BESS project with a separate financing may make the BESS easier to finance. The solar project could be financed with a different investor (who is interested in a 2023 PTC deal) and the BESS could have different financing terms and different investors (given it would be a 2024 ITC transaction) and there would be no need to combine site-control documents, third-party reports or permitting efforts.
One key reason that project participants will continue to finance BESS and solar projects as single-asset is efficiency. In many cases, solar projects and BESS will continue to be developed together – with shared real estate, permits and interconnect facilities. Keeping these assets together in a single financing with the same counterparties makes sense from a simplification and cost-saving perspective. For example, a single financing streamlines diligence and allows for shared third-party reports and diligence (appraisals, insurance, IE reports, etc).
Transferability of credits
The sine qua non of tax equity financing for decades has been that ITCs and PTCs could not be sold or simply transferred. One had to own the project in order to claim the tax credit. No longer – and that is at once perhaps the most profound and the most inscrutable aspect of the IRA. Beginning with credits arising in 2023, the owner of the project will now be permitted to sell its credits annually. The purchaser of the credits may not sell the credits again. Note that only credits may be transferred – not depreciation, which typically forms a meaningful portion of the investment return for a tax equity investor (and is often inefficient if stranded with the sponsor).
This implies that sponsors selling tax credits will, if they want to finance the depreciation on their project, have to structure a tax equity investment based primarily on depreciation and cash and not the more meaningful ITC or PTC. This would seem to portend increased transaction costs relative to value realised. Additionally, the purchaser, unlike a tax equity investor, may not deduct any portion of the purchase price paid for the credit (the tax equity investor is permitted to deduct a portion of its investment). Our hypothetical solar-plus-storage project could – if a market existed – take healthy advantage of several of these opportunities.
It is axiomatic that everyone has their price. We imagine there is a point on the curve where willing buyer and willing seller will meet. In a vacuum, not considering other bolt-on value a purchaser or investor may provide, it would seem that those instances may be rare in today’s world. Perhaps sponsors who are offered a healthy price and can themselves take advantage of the depreciation of their project. Other opportunists might be smaller projects (or smaller sponsors) or new technologies that could not hurdle the diligence required by a traditional investor.
But, in all events, in a world where there was an established platform and structure for wide access to tax credits, the instance of buyer and seller finding each other would increase. Transaction costs incurred at the outset will, at some point, be absorbed and an efficient market could develop. We can envision certain structures that would allow for an investor to purchase credits and accommodate additional investors under certain circumstances. We can also envision the possibility of leverage – both for the project (recognising a future cash stream of purchase payments) and such an acquiring fund (recognising a future stream of investments). However, much work remains to be done to identify correct risk allocation, indemnities, documentation and diligence burdens before anything significant can be done. All of these issues are, of course, already well-trodden ground for a tax equity transaction.
Significantly, the idea that traditional tax equity structures would be fundamentally altered (or replaced) opens the door to increased market participation by traditional project finance lenders who have never been comfortable being junior to tax equity. Most of the project finance world outside the US (indeed, outside US renewables) operates on an assumption that operational phase debt sits at the project level. Not so in the US renewables market. Opening this door would accommodate additional bank investment, insurance company and bond investments, and (theoretically) impact pricing of that debt. Sponsors who are otherwise having difficulty achieving a desired leverage on a project would do well to consider these options.
As we said at the beginning of this piece, the Inflation Reduction Act brought many presents for the US renewables industry. It offers increased support for new technologies. It teases with the option to simply transfer tax credits. It offers an opportunity for new market participants and new (potentially simpler) structures. But it also brings increased burdens. Labour costs will themselves almost certainly rise.
Satisfying prevailing wage and apprenticeship rules (more accurately satisfying the record-keeping requirements of those rules) will be no easy task. Combined with increasing costs of capital, the very near term may experience some friction relative to a year ago. But the longer term outlook trends up. Like a good, high-quality train-set, the IRA should last quite some time.
The authors would like to thank Patrick Montgomery and Jason Pham for help with this article
1 - For the purposes of this article, please note that we have only provided a high-level overview of the structure and transaction documents. Among other things, we have left out certain structuring details and options (for example, most ITC tax equity transactions include a “DevCo” sale to the tax equity partnership, which has been omitted here for purposes of simplification).
2 - A developer that is able to utilise the tax credits itself may have different preferences; our article focuses on structuring for third-party tax equity investments.
3 - In most transactions, the majority (or, in some cases, all) of the PAYGO payments that a tax equity investor is required to make will be attributable to PTCs that are generated after the investor has achieved its agreed rate of return.
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