A quantitative and qualitative look at the prospect of taking the ITC as cash or a tax refund — by Dave Riester


Most of us in the renewable energy and energy storage industry were probably at least a bit disappointed to see the late June infrastructure bill compromise include nothing with respect to the investment tax credit (ITC) and production tax credit (PTC) extensions, energy storage credits, or the introduction of a “direct pay” option for taking the subsidies. Those close to the policy “rooms” seem to think this is more a kicking-of-the-can than an indication that mission-critical climate change mitigation measures were sold out for some bridge upgrades. Let’s hope so. In any event, the pause in affairs offers an opportunity to consider and rethink what’s really most important to the renewable energy industry in the legislative realm.

Arguably the most important (and, thankfully, the most likely) things in draft house or senate bills are:

  1. ITC/PTC extensions (H.R. 848, S. 985)
  2. Energy Storage ITC (H.R. 848, H.R. 1684, S. 627)
  3. Direct Pay (H.R. 848, S. 985)

Each would be massively impactful to the industry. All together they would catalyze things in a way not yet experienced. Which, to be clear, is necessary. While the sustained rapid growth of renewable energy in the last 15 years is unique and something for which we should be proud, we are still well off the pace required from a climate change perspective. Our pace to date has been set, at least in part, by an evolving federal policy regime which has been directionally right, but ultimately anemic in light of the task at hand. With that context in mind, an odd narrative related to #3 – which would allow developers to monetize credits as cash refunds from Treasury1 - is beginning to stand out. It goes something like this: “Mostly I just want the ITC extension; frankly I’m not even sure direct pay is that important.”

The argument is usually that i) the direct pay concept might incorporate a discount (e.g. get $0.85 cash on the $1.00 credit as proposed in H.R. 848), ii) there’s still accelerated depreciation to monetize, and iii) we’ve gotten so slick at doing tax equity deals that switching things up comes at some nebulous cost.

The primary flaw in this argument is that it’s myopic. It ignores the mitigating effect a direct pay option2 would have on one of the biggest existential risks for any project relying on a tax credit – the mere availability of – or access to - tax equity.

I will humbly submit that I’ve closed more tax equity than most. I have crossed that finish line for rooftops, ground-mounts, AAA credits, junk credits, merchant projects, community solar, pre-paid PPAs, sale leasebacks, partnership flips, lease passthroughs, projects with state tax credits, levered deals, unlevered deals, projects with batteries, fixed-tilt, trackers, even a “mixed tilt” project that I would rather not talk about…. you name it. But go back 18 months before placed-in-service for any single one of those projects, and 250/250 times there was at least some risk of i) tax equity being available at all, ii) what structure it would come through, iii) at what point the tax investor would close, iv) at what terms, and v) what impact i-iv would have on the other components of the capital stack. For some projects this risk is not existential at all, but rather quite acute - usually as the result of having at least one feature which may be deemed “unbankable” by the tax investor community. The uncertainty – sometimes just a sliver, sometimes far more – has a profound impact on the business of profitably developing and building renewable power plants.

But let’s come back to that, because even within the myopic frame it’s hard to see how direct pay is unimportant.

The Numbers (at project level)

Lets do a side-by-side focusing i) only at the project – or “unit economics” - level, and ii) only from construction forward (this is the myopic frame to be criticized later). On one side we have a 30% ITC deal with back-leverage debt sitting behind a partnership flip tax equity structure. On the other we will model a 25.5% direct pay in-lieu-of-credit, with normal3 project-level debt and a single equity owner without any offsetable tax appetite.

How does the value stack change when you switch from an ITC to a direct pay capital stack? The following table lists out the main deltas4 , organized by “steps forward” (net positives for direct pay), and “steps backward” (net negatives for direct pay):

5 Steps Forward…and 2 Steps Back

Table: Five Steps Forward

The essential question: “can you gain enough in avoided soft costs and lower weighted-average cost-of-capital (WACC) to make up for the subsidy reduction and lost MACRS value?”

Given that all but the soft costs are linear (or materially so) with respect to project size, to a large extent we can isolate WACC and figure out what WACC improvement we would need if there were no soft cost savings. This “bounds” the analysis, if you will, and isolates the more objective changes from the one that takes more guesswork (soft costs savings).

The analysis reveals that a 10% delta in equity/debt WACC hits the “breakeven point”

In our analysis case (key assumptions shown below) a 60 basis point (bps) delta reflected a ~10% reduction to the cost of capital. This may change marginally from one project to the next, or based on other assumptions in the model, but it is reasonably accurate and applicable to many different flavors of projects.

Analysis Case Assumptions6

Table: Analysis Case Assumptions

Is that upside achievable merely by taking the tax equity structures – and tax investors – out of the picture? Is there any way to answer that question based on data and experience? Well, we can review anecdotal evidence and make an educated guess. The obvious place to look for “comps” is a few years ago when 1603 treasury grant deals with no tax investor were common. But this is probably a false precision trap: there are too many variables, including economic environment, project sizes, industry maturity, interest rates, data availability/depth. Personally, I have to reach all the way back to 2012 to find an apples-to-apples data point in my own experience set. There were a couple of tax inefficient (cash) investors at the time who tried to entice SunEdison to sell them projects without structuring tax equity by offering levered equity IRR targets around 11.5-12.0% at a time when cash equity for fully structured deals was usually seeking a 13-14% IRR. That gets close to a 10% reduction to WACC, though a little short. And, now that yields are considerably more compressed than they were back then, investors won’t likely lean-in with the same aplomb. The belt is already awfully tight. When I think of equity investors reading this, I go to that image of John Candy in The Great Outdoors staring at the last few bites of “the Old ‘96er” steak in horror – no…. come on….don’t make me do it…that’s asking too much. A 10% WACC reduction feels like a bridge too far, but the debt and equity markets’ appetite for renewable power plant cash flows has made fools of pessimists for a decade running, so one hesitates to rule it out.

What’s left is the soft cost savings. Anyone who has been in or around any renewable energy project finance transactions will appreciate that this category should not be underappreciated. The added negotiating, modeling, documenting, and underwriting imposed by tax investors and their structure of choice is staggering. The costs associated do scale, however. The soft costs for closing a tax equity capital stack for a 10 MW project is probably still 50-75% as much as the same costs for closing a 100MW project. Importantly, this means the smaller the deal, the more likely it is a direct pay option is value accretive.

So, if we believe that the WACC upside gets us some – but not all – of the way to breakeven, then we need to make some assumptions about soft costs at different project size ranges to figure out where the point of indifference is between a 30% ITC deal and a 25.5% direct pay deal. To oversimply it, this would be the “line in the sand” below which the simplicity of direct pay would be preferred, and above which it would be “worth it” to pursue a fully structured tax equity ITC deal. The analysis above lands on a line around $30-35M project value. If direct pay ever passes, everyone should be performing their own version of this analysis.

Diagram: Direct Pay (Stacked Bars)

The subjectivity here is i) where and how much one thinks the yield (or interest rate) compression will be, and ii) estimated reduction to soft costs. The breakeven point snapshot shown above implicitly anticipates about 35 bps of WACC improvement, and about half a million dollars in soft cost savings. With different subjective soft cost assumptions, the breakeven point would be different. If you think the WACC upside is less and/or your soft costs are closer to linear relative to transaction size, then your breakeven point shifts to smaller transactions (or maybe doesn’t exist at the extreme). If you are more optimistic on WACC upside and/or a realist with regards to transaction costs, then your breakeven point shifts higher.

ITC vs. Direct Pay Spectrum by Project Size

Diagram: ITC vs Direct Pay Spectrum by Project Size

Looking no further than the spectrum above, it’s hard to fathom how direct pay could be considered expendable in the legislative realm. The total capacity that falls in the part of that spectrum that leans direct pay is approximately half of the installed capacity in 2019-2020.8

The Bigger Point

All of the above analysis is important and relevant, but it’s not really the point. Or at least it shouldn’t be. The renewable energy sector suffers a fascinating tendency to obsess over unit economics while ignoring enterprise economics and the basic notion of creating a business profit. The introduction of a direct pay option would positively impact businesses developing, financing, building, and monetizing renewable energy/storage power plants in a few ways; here are the 3 that jump out:

  1. The existential risk of “takeout” capital. Renewable power and/or energy storage plants don’t come to exist unless they receive capital investment to support development stage value creation. This is the riskiest capital investment in the game, because the range of possible outcomes is extremely wide and includes “dead project”. Finding capital that can tolerate this kind of risk is often the biggest challenge in project development, and a major governor on industry growth and renewable energy penetration. Broadly speaking, development stage risk falls into six categories, shown here (in an extremely subjective and illustrative manner that we should not bother debating too much for the purposes of this article).

    Diagram: Development Risk

    All but engineering, procurement, construction (EPC) risk is potentially binary in nature. And IX, EPC, Offtake, and Financing are also the primary determinants of project value for those projects which do “make it”. That is a lot of risk to underwrite – hence the scarcity and cost of development capital. Any measures taken which have the effect of reducing or eliminating any of these risks have a direct impact on the availability and cost of the “keystone” capital in the renewable energy penetration game – development capital. As I have argued at length elsewhere, this is the capital that is currently governing the pace of renewables deployment. If the objective of a government subsidy is to speed up renewables’ deployment, any measure that opens the spigot of development capital is serving that objective well.

    Without direct pay, tax equity is a linchpin piece of the capital stack. If it is not there, there is no capital stack, and there is no project. And make no mistake about it – tax equity is frequently unobtainable. Reasons include “unbankable” components9 , electricity buyers without an investment grade credit rating, a project that is too small and not worth folks’ time, lack of an acceptable “sponsor”10 , or - and this may sound a little crazy - a pandemic-induced plethora of project delays and a subsequent piling-up of demand for tax equity occurring concurrent with the universe of tax investors shrinking amidst an economic recession obliterating corporate profitability. You know…things like that. The point is one can never be sure they will have access to tax equity for a project, and for smaller and/or less pristine projects, that risk is palpable. If tax equity is no longer a binary risk, every dollar invested earlier in the project life cycle is exposed to less risk.

  2. Chickens and Eggs. A tax investor will not hard commit to a project until they are nearly certain they will have tax “appetite” (taxable income they would like to offset) in the year the project would generate a tax credit. And you cannot get construction financing for a project until the lender sees a hard commitment from all the parties relied upon to take out their loan. And most developers cannot start constructing a project until they have construction financing. Back in the good old days - when most projects were on Kohl’s department store rooftops (or the like) - this wasn’t much of an issue because i) you could put a system on a Kohl’s roof in about a month or two, and ii) you didn’t need construction financing for that size and time horizon. However, as projects get bigger, the capital intensity grows, and the construction timeline extends. These days 18-month construction windows are common. This means that hard commitments from tax investors are often required at least a year and a half before a tax investor knows if they will have taxable income to offset. This boxes out many tax investors from making such commitments, and for those that are still willing to do so, their risk increases, their negotiating leverage increases, and consequently so do their return expectations.

    Diagram: Chicke and Egg

    A direct pay option diffuses this problem wonderfully. Construction lenders will underwrite loans without a hard TE commit. Maybe not all of them at first, but the smart ones will; and those who don’t will lose deals and eventually follow suit as they watch their competitors’ loans get taken out as underwritten by the (very liquid) cash equity markets. And remember: an option doesn’t need to be used to be of value. A developer could choose to go the fully structured tax equity route further down the road while still having benefitted enormously from the direct pay option along the way.

  3. Overhead. [Apologizing in advance to every tax equity guru out there. Please know this hurts me just as much as it hurts you]. Maintaining a project financing apparatus within a developer or independent power producer is a very expensive SG&A line item. I recently had the privilege of managing such a team at Cypress Creek Renewables and can assure you it is not cheap. As with so many things, this is a function of simple supply/demand. Tax equity being as important as it is, the demand for individuals with the experience and skills to successfully close tax equity transactions is very high. The supply of such folks, however, is very limited. Anyone wondering why probably hasn’t worked on a tax equity transaction before - at least not from the “sponsor” side of the table. It’s not exactly a hoot. A smart and experienced professional with options (and no notable sado-masochism issues) might reasonably choose instead to go work for, say, an “app” company with no vowels trying to solve the last nanometer of some first-world problem. So, the masochists among us who voluntarily work on tax equity transactions (from the weak side of the table, moreover) have tended to be in rather high demand… and are understandably expensive.

    Now, a simple senior debt + equity infrastructure project financing deal? That is a considerably more commoditized skillset, and a less time-intensive undertaking generally. The net result is that a smaller team full of less specialized individuals is required. An owner/executive of a developer who intends to turn a business profit ought to deem this pertinent.


The direct pay option feels undervalued and at risk of being a sacrificial lamb of sorts. While ITC/PTC extensions and storage ITCs are obviously important, I think it is a mistake to consider direct pay expendable. Tax credits have been hugely important to the renewable energy industry for 15+ years, and we’ve learned to absorb this subsidy with resilience and creativity. It works imperfectly, but it does work – thanks to the community of tax investors, attorneys, accountants, and project finance folks who have all confronted the challenge of fitting a Rhombicosidodecahedron peg into a round hole. But so too have tax equity structures been a governor on renewable energy penetration. Introducing a direct pay option would remove the governor and allow the renewable energy and energy storage industries to reach a velocity not yet experienced. This political environment might be our best (or only) opportunity to be uncompromising…. even greedy (in a good way). As evidenced by the June 21 letter to congress, the industry and its supporters appreciate this. But after that failed to generate an immediate win, we should keep the pressure on and not make the mistake of “settling”, especially if based on flawed reasoning derived from the myopic frame of unit economics. A direct pay option will embolden developers and their investors in ways that go far beyond project profitability.


1While similar to the 1603 Cash Grant Program from the 2009 stimulus bill that allowed developers to receive a cash grant in lieu of applying for a tax credit, direct pay doesn’t rely on Congress to authorize a grant program. Direct pay works within existing IRS processes, namely annual tax filings.

2Just because an option exists, doesn’t mean you must use it, or – if you don’t - that the unused option never had value

3Yes, “normal.” Believe it or not senior debt usually sits right with the cashflow generating assets and stands first in line in every respect. That is…in normal industries not forced to contort to the demands of byzantine tax equity structures thrust upon capital stacks that have no choice but to abide by the wishes of the all-powerful party gifted incredible negotiating leverage through the federal government’s selection of a breathtakingly clumsy subsidy instrument. [sigh]. And don’t blame the tax investors – they are just doing their jobs and serving their shareholders. It’s the game, not the players.

4Certainly not an exhaustive list

5It’s remarkably common for folks to overestimate MACRS value, usually confusing the theoretical value with what tax investors will actually “pay” for the pulled-forward losses. Academically, its huge… in practice, it’s meaningful but overrated.

6Not meant to be an exhaustive list; these are the most important assumptions only. If you are spending any energy poking holes in these assumptions, you are focusing on the wrong thing. The relative is what matters, not the absolute.

7Or, to be more precise, “transaction” size ranges

8EIA Preliminary Monthly Electric Generator Inventory (

9Which are often “unbankable” simply because they are new; and new technologies are often the advanced technologies which we must implement to make progress at the required pace. So they can’t get capitalized until they are no longer “unproven”, but they can’t get past being “unproven” until they are capitalized, so… well you see the problem, right?

10I despise the term “sponsor”. It almost perfectly captures all that is wrong with our tax credit subsidy regime. What am I sponsoring…your risk and your return? Don’t answer that.