The Inflation Reduction Act makes the ITC “transferable”, rendering P-flips, inverted leases, and sale-leasebacks expendable. This is good news (for most of us) — by David Riester


A little over a year ago, I wrote an article espousing the merits of “direct pay”. It was, essentially, a plea to politicians and stakeholders to prioritize direct pay and not let it become the “sacrificial lamb” of Capitol Hill compromise. Oddly enough, my plea didn’t alter the course of the most important bill in the history of climate change and clean energy. Manchin didn’t like direct pay, (for reasons that were never well articulated and largely remain a mystery, even to his staff) so it was, indeed, largely sacrificed. The result is a very narrow direct pay provision, where the concept was left intact, but the universe of stakeholders allowed to elect the direct pay option was whittled down to non-profits, the Tennessee Valley Authority, First Nations, and a few similar applicant classes. Bummer.

But not all was/is lost! In a dramatic, unexpected twist, the IRA rendered the Section 48 and Section 45 tax credits (the ITC and the PTC, respectively) “transferable”. This feature doesn’t leap off the pages of the bill, and probably won’t anchor the plot of a juicy Hollywood drama any time soon, but it’s one of the most important nuggets in that entire, wonderful bill. It, alone, will change the way we conduct business in the renewable energy and storage sector.

Every law firm, accounting firm, investment bank, and gas station attendant in America has, by now, produced a bill summary with supporting commentary, so I will focus on the implications of the provisions instead of the technicalities. 

But, to explain what “transferable” means in this context, we do need to set the stage a little bit. As most of us know, since the Energy Policy Act of 2005, the main subsidies for solar and wind projects are the Section 48 Investment Tax Credit (“ITC”) and Section 45 Production Tax Credit (“PTC”). Crucially, that law dictated that tax credits generated by qualified facilities could only be taken by the true economic owner of the assets – the credits were not fungible, sellable, or transferable generally. Not all tax credits are like this. Low-income housing, historic rehabilitation, and film production credits are transferable, meaning the owner of the qualified facility/activity can sell the tax credits to an entirely unrelated party for cash. But solar and wind? Nope. For those assets, only the true owner could use the credit. The problem with this is that most classes of would-be solar/wind power plant owners can’t absorb the credit for either structural or “tax appetite” reasons. To address this problem, we used primarily three different “structures” to monetize the tax credits. In the early years (2005 – 2011) the simplest of the structures, the “sale-leaseback” (“SLB”), dominated the scene. Then, along came the “partnership flip” (“P-flip”) and, shortly thereafter, the “lease pass-through” (A.K.A. an “inverted lease” or “LPT”). The primary purpose of each of these structures was to allocate the ITC to the “tax investor” and the cash to the “cash investor”[1] as efficiently as possible, without tripping over IRS lines that would risk a “recapture” of the tax credit. 

Like many professionals, I built a career around those structures. They can be very complicated, tedious, inflexible, and fickle. But if you were able (and, more importantly, willing) to develop and apply the expertise, you were in a relatively small group of masochists with mission critical skills/knowledge who enjoyed the commensurate opportunity and earning-power tailwinds that come with being a scarce, important resource.

But boy did they slow the rate of solar and wind penetration. Not only that, they introduced “rents” (in the economic sense) in the form of brutal legal, accounting, and consultant bills, as well as “leakage” of cash to the tax investor that they don’t really pay for (we had to do this just to make them look like the real owner). 

This isn’t really anyone’s fault. Tax attorneys and accountants made a killing off these structures, but we needed them to pave a path for the subsidies to have their intended effect; and, in any event, they’ve just been doing their jobs and using their skills to make the best of a clumsy subsidy. Tax investors themselves have been at the center of this racket, sure, but what would you have them do… breach their fiduciary duty to shareholders and take worse risk-adjusted returns than the market affords? Nah, that’s not how this whole capitalism thing works. Everyone in the renewable energy sector – hell, every human in the world – would be worse off if the stakeholders who benefited most from the old tax equity game took their ball and went home. When an “impact-motivated” source of money asks me how to make the biggest impact in renewable energy, my first thought is if they could be a tax investor. A reporter working on an article about corporate sustainability recently asked me which American companies have done the most to support clean energy: I answered “US Bank” without hesitation based solely on their “CDC” group’s ~15 year role as tax equity’s “lead blocker.” This is truly a “hate the game, not the player” situation.   

Having said all that, I expect many parties with entrenched interests to resist this policy-driven market evolution out of self-preservation. We already saw this manifest itself in the form of “Don’t Get Too Excited About Direct Pay” articles last year. Now that there’s an even more disruptive mechanism in an existing law, we should all brace ourselves as stakeholders rage against the dying of the light.

The arguments for continuing to use the tax equity structures seem to be:

  1. Depreciation! While the credits are now transferable, the accelerated depreciation is not. A structure is still necessary to monetize accelerated depreciation
  2. Basis step-up! Tax equity ("TE") structures offer opportunities to make the basis higher than what it’s likely to be for credits just sold
  3. The inertia of existing “funds” and partnerships will cause folks to stay the course

The analysis below takes the same cost/benefit approach I applied in the direct pay article last year, to assess the merits of those arguments balanced against the benefits of casting aside the TE structures.

The Numbers

Let’s do a side-by-side focusing on the project – or “unit economics” – level. On one side we have an ITC deal with back-leverage debt sitting behind a lease pass-through[2] tax equity structure. On the other we simply sell the tax credit, carry forward losses from depreciation (“self-shelter”), use normal[3] project-level debt, and sell project equity to a single, tax inefficient cash investor. 

Cost/Benefit Framework[4]

The essential question: “can you gain enough in avoided soft costs and/or lower weighted-average cost-of-capital (“WACC”) to make up for the ITC buyer discount plus lost MACRS[5] and step-up value?” (You might read that last sentence a few times until it clicks – it’s sort of the “boiled down” framework of this whole thing.)

For less financially savvy readers, “WACC” is your all-in, combined, weighted cost-of-capital. If you raise $50 of 5% debt, and $50 of equity targeting a 10% IRR, your WACC is 7.5%. If you raise $80 of 5% debt, and $20 of that 10% equity, your WACC is 6.0%. 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 40 – 60 bps delta in WACC hits the “breakeven point”.

By now you can probably surmise that I consider that WACC improvement well within reach.

“Control”/Baseline Assumptions

The assumptions shown below serve as a sort of “control” for the analysis – essentially finding the “point of indifference” while holding as many variables constant between the two “views” as possible. This is not what I think is “right”, but rather is the jumping off point that allows us to answer the question “what do I need to believe for the unstructured approach to land better economically?” If you think any of these assumptions are “wrong”, please relax in knowing they are wrong for both scenarios.I should call out two particularly important assumptions here – i) the “cents-on-the-dollar” (Cash Price Per $1 ITC) assumption for what credit buyers pay for tax credits in straight purchase/sale transactions, and ii) the ITC basis upside you get by doing a full tax equity structure. Not only are these both very sensitive assumptions, but both could (and will) fall within a wide range. 

As for the “cents-on-the-dollar” assumption, I don’t expect $0.959/ITC pricing in the transfer scenario – again, this scenario is here to establish equivalency between the cases by changing as few factors as possible. In this case we float the transfer pricing such that margins are equal, and now move on to checking what other variables need to be with a more realistic transfer pricing assumption.

So, what do we think sold tax credits will sell for? The obvious “comp” is the Low-Income Housing Tax Credit (“LIHTC”) market. LIHTC is the largest and longest-running transferable credit market. Novogradac keeps great data on LIHTC pricing over time:

Source: Novogradac (; pulled 8/31/2022

Every tax investor, syndicator, consultant, accountant, or tax attorney I’ve spoken with wholeheartedly declined to predict whether IRA-derived credits will trade at a premium or discount to LIHTC. Like most of us, I have a lot to learn about the way investors assess risk/return in transferable credit markets. Were I more qualified to do so, I’d probably have framed this entire discussion as how we can (or cannot) extrapolate characteristics of the LIHTC market to IRA-based credits. Frankly, I’m surprised there isn’t such an in-depth white paper on this floating around yet; perhaps it’s time to move on from the obligatory summaries and get down to business! In the meantime, here are some considerations vis-à-vis where IRA credits might trade relative to LIHTC:

  1. LIHTC is paid out over 10 years (longer time horizon, time-value-of-money)
  2. LIHTC payments are linked to vacancy/utilization (extra risk)
  3. LIHTC investors do get losses from accelerated depreciation (IRA credit investors would not)
  4. A significant portion of the LIHTC investor community is also motivated by Community Reinvestment Act (“CRA”) compliance requirements (lower return sensitivity in aggregate)
  5. IRA credits are new, exciting… though less familiar

You can see why folks are reticent to offer a prediction. Based on that list (and surely a couple I’m missing), I could make an argument in either direction. The “control” case uses $0.959/credit, but most of the analysis cases assume $0.87/credit – a ~5% discount to most recent LIHTC price-per-credit, and a far more realistic assumption.

As for the added “step-up” assumed for a LPT tax equity structure, the “control” case assumes an extra 10% step-up beyond the cost + 20% methodology our industry (somewhat arbitrarily) latched onto in 2009 and clutched like a safety blanket ever since. 30% is a humble LPT step-up in context of my own experience set, but I’m told it’s about par in the broader universe of LPTs. But if you’re jacking up your LPTs to something meaningfully north of a 30% step-up (and lord knows I’m in no position to throw stones at such an approach) you should certainly be running your own cost/benefit analysis. Directionally, the takeaways are the same, but the cost/benefit findings will be scalar-shifted such that the breakeven/indifference point will favor using a TE structure in more circumstances on a relative basis.

The “Control” Case is one “indifference point” where the economic outcome is equal whether you do a TE structure or just sell the credit. From there, we can stress test different factors that might change and how those circumstantial changes would impact the developer’s economic result. 

*Numbers in table with negative signs are expressed relative to "Control" Case; e.g. the "Sponsor IRR" case has a cash equity IRR that is 0.62% less than the cash equity IRR in the Control Case

**  "---" indicates the assumption is the same as in the "Control" Case

There’s a lot to unpack in there, so let’s go line by line:

“Control” Case – Covered above

Credit Pricing to $0.87/credit – This case isolates the shift of the credit pricing down to $0.87/credit. This results in a margin that is $0.0287/W lower than the structured “Control” Case. Said another way: if you get absolutely no help from anywhere else, and IRA credits trade at 87 cents-on-the-dollar, you’d be 2.87 cent/W better off (economically) by doing a full TE structure.

Debt Interest Rate Change to Breakeven – With 92 bps improvement to the senior debt interest rate (and nothing else), you would be economically indifferent to using a TE structure. Is this achievable? No, but you should expect some help here. These days, most non-recourse solar project debt is back-levered, where CFADS (“cashflow available for debt service”) is subordinated behind the tax investor’s preferred cash distribution. (As a quick aside: there’s no better way to illustrate the negotiating power tax investors have enjoyed than to let that reality sink in. Senior lenders in our space subordinate themselves to the tax investor’s preferred cash distribution, even though tax investors barely need a dollar of cash to achieve good risk/adjusted returns. It’s icing on their cake, yet they’ve still been able to compel senior lenders to sit behind them!) Eliminate the tax equity structure and everything that comes with it – subordination, SNDAs, intercreditor agreements, cash-traps, TE buyouts, etc. – and the lenders are finally able to lend like real grownups in a normal industry. In a debt market already experiencing comically tight spreads, 92 bps is way off the table, but if I’m a lender I am definitely leaning-in a little extra on interest rate for TE structure-free deals; debt interest rate will contribute to transferability upside.

Debt DSCR Change to Breakeven – With a 0.31 change to the debt service coverage ratio (“DSCR”) – e.g. a 1.50 for a back-levered loan is a 1.19 DSCR in a simpler transaction where the tax credits are just sold off – you would be economically indifferent to doing a tax equity structure vs. a straight credit sale. Is this achievable? Very doubtful. The delta I would be comfortable with if I were a lender, based on some stress tests and sharpe-ratio[6] arithmetic, is in the 0.10 – 0.15 range. So, again, transferability should experience meaningful upside from DSCR, but won’t close the gap alone. 

Sponsor IRR Target Change To Breakeven – With a 0.62% reduction in the cash investor IRR target – and nothing else – you would be economically indifferent to doing a tax equity structure vs. a straight credit sale. Is this achievable? I believe it is. Factors to consider include: the degree of equity subordination (less), check size (larger), and contingent liabilities (e.g. indemnifying tax investor and basically guaranteeing their return). If someone approached me and said: “For the same project you can either get a 9.5% return against cashflows spitting out the back end of an LPT structure with TE prefs, indemnities up the wazoo, and back-leverage… or an 8.88% return against cashflows distributed straight from a project SPV after paying a senior lender,” I’d take the latter. Again, that doesn’t necessarily mean that’s how the market will behave, but this magnitude of cash equity cost-of-capital upside is well within the realm of possibility.

The previous three changes all contribute to WACC. Remember our essential question: “Can you gain enough in avoided soft costs and/or lower weighted-average cost-of-capital (WACC) to make up for the ITC buyer’s discount plus lost MACRS and ITC step-up value?” I’ve just argued that any one of the three sources of WACC upside could, offer meaningful contributions toward making the benefits of eschewing a TE structure outweigh the costs. Getting enough out of a combination of the three seems highly probable. And we haven’t even touched on the soft cost savings.

Soft Cost Savings To Breakeven – This one is easy. After adjusting our credit pricing to $0.87/credit and changing nothing else, the unstructured straight sale of tax credits was about $0.0287/W worse for a 100 MW project. Well, that’s easy arithmetic: that means with $2.87m in soft cost savings – and nothing else – you would be economically indifferent to using a TE structure or not. 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. Would it cost a full $2.87m less to put together the capital stack of an unstructured financing? No, that's a bit outlandish, but again it's a meaningful advantage for transferability cases. 

(Permit me a moment to cut one criticism off at the pass. While reading that last paragraph, approximately 10,000 tax attorneys began foaming at the mouth, leaping out of their chair to make the point that tax credit sellers will still need to indemnify the buyers against recapture events, including the assumed basis, and that these transactions will still have wrinkles and require finesse. Relax… we get it. Please don’t conflate “easier/cheaper” with “easy/cheap” or confuse optimism and excitement for naivete. I’m not saying a straight ITC sale has zero complexity and/or risk, or that tax investors will close without performing some due diligence. I’m saying [PSA/Assignment] + [Indemnity] + [Tax Opinion] + [Somewhat Lighter Due Diligence]… still wildly cheaper/faster/easier than how we’ve been doing this for 17 years.)

“Best Guess” Case – This is my personal swag case. For a 100 MW project I’m predicting about 25 bps of debt interest rate upside, 0.10 improvement (reduction) to the DSCR, a 0.50% drop in cash investor return target, and half a million in soft cost savings. In the aggregate, that produces a margin $0.0143/W higher than the “Control” Case. Almost a cent and a half! That’s a solid margin bump, and that’s without considering all the intangible benefits of operating a business untethered from tax equity structures.

“Best Guess” Case Project Size To Breakeven – This case is meant to answer the question “well how big does a project need to be before a full TE structure becomes accretive?” If we hold all my assumptions from the “Best Guess” Case constant, there’s actually no crossover point. Which is pretty incredible. As projects get very large, however, I think I’d tweak my “Best Guess” assumptions for debt interest rate and cash equity IRR target. Why? At a certain scale (somewhere in the 250 – 500 MW range?) developers/sellers can access a class of lenders and cash investors with lower costs of capital. Some banks, private equity funds, pension funds, IPPs, etc. are so large that they can only capitalize very, very large renewable energy projects. When those opportunities arise, these parties know they must be very aggressive – regardless of tax equity structure or lack thereof – because opportunities at such scale are few and far between. We ran an alternate “Best Guess” case for large projects to check for a crossover point with those assumptions. In doing so, a breakeven point emerges around a 200 MWdc project size.

Transferability vs. Full TE Structure Spectrum

Looking no further than the spectrum above, transferability’s importance is obvious. The total capacity that falls in the part of that spectrum that leans toward eschewing a full TE structure is approximately 75% of the installed capacity in 2019 – 2020. [7]

The Bigger Point

(this section is largely a re-print of the same section in my direct pay article, but just as relevant, and worth hammering home)

All of the above analysis is important and relevant, but it’s almost secondary. 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. Transferability will 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).
    All but engineering, procurement, construction (EPC) risk is potentially binary in nature. And Interconnection (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 bottleneck that governs the pace of renewables penetration. 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.

    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 – in the old, pre-IRA world, tax equity was frequently unobtainable. Reasons included “unbankable” components[8], electricity buyers without an investment grade credit rating, a project that is too small and not worth folks’ time, lack of an acceptable “sponsor”, 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 could never be sure they would have access to tax equity for a project, and for smaller and/or less pristine projects, that risk was elevated. Transferability will reduce the risk of ITC monetization in two ways: i) in a simpler market with simpler transactions, the universe of tax investors will dramatically expand, and ii) because the burden of demonstrating economic substance is gone, underwriting standards should (and I believe will) be meaningfully lowered. With that, every dollar invested earlier in the project life cycle is exposed to less risk, which will make development capital more accessible, and probably a little cheaper.

  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.

    A transferability option diffuses this problem wonderfully. Construction lenders will underwrite loans without a hard TE commit with a more liquid, simpler tax equity market. 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. 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 benefited enormously from transferability being there as a fallback along the way.
  1. 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 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 fewer specialized individuals is required. An owner/executive of a developer who intends to turn a business profit ought to deem this pertinent, even if my thesis on unit economics cost/benefit is rejected out of hand.

Other Positives. Those are the most significant intangible benefits, but it’s not the full list. A few more:

  • With transferability, it’s easier to have multiple tax investors for one project. While you can only sell a tax credit once, you can split up a project’s tax credits and sell them to as many parties as you’d like. Historically, the process of matching tax equity demand (tax investors) with tax credit supply (power plants) was brutal. Syndication relieved some of the pressure to perfectly match tax appetite with ITC basis, but syndicating within a full tax equity structure is quite difficult. 3 – 6 party transactions (developer, cash equity, tax equity, construction lender, permanent lender, offtaker) are hard enough as it is; bringing in additional tax investors “upstairs” only adds to an already imposing degree of difficulty. Syndication will persist in a transferability-dominated market – and that’s a good thing – but the marginal difficulty introduced via syndication or pursuing multiple tax equity sale transactions is substantially reduced.
  • With transferability, that whole “don’t place the power plant in service until we close with the tax investor” dance is unnecessary. Bottom of page 524: “An election… to transfer any portion of an eligible credit shall be made not later than the due date (including extensions of time) for the return of tax for the taxable year for which the credit is determined.” This means a developer/owner planning to monetize the credit with a transfer can let the EPC Gantt chart play out unimpeded by the ragged cadence of finance folks like me arguing over inane legal points in an ivory tower across the country. This is a great example of a point that will never show up in someone’s quantitative cost/benefit analysis with regards to using a TE structure – but talk to a few experienced EPC guys and ask them how much smoother and more profitable their business unit would operate if they never again had to call off work for a day because the project finance team didn’t close. Just because you can’t quantify a cost doesn’t mean it isn’t there.    
  • The IRA is unclear on whether or not a change of project ownership during the “recapture period” would cause a recapture in the case of where the tax credits were sold (or who would be on the hook with the IRS). But it would be very odd and illogical for the IRS (in their process of converting the new law to actionable code/PLRs/safe-harbors) to be handed a new law with a clause severing the credit from the eligible facility owner… yet deem it the lawmakers’ intent to preserve a change-of-ownership recapture event. Not that every law or line of tax code in our great nation is 100% rational/logical, but that would be truly odd. I may end up wrong here, but I predict that there will be no material tax ramifications for selling a project for which the tax credits were previously sold to a “transferee”. Why does this matter? How many asset classes do you know where upon investing in a physical asset, practically speaking you have a five year “lock-up” on that asset? I can’t think of another. Many owners (or would-be owners) of a solar/wind/storage plant are limited partnerships (of the private equity fund variety) that have a 6 – 12 year life. In that structure, buying an asset with no liquidity for 5 years is awkward. This keeps many potential project owners out of the sector. If that class of investors enters the market, the capital supply will grow, and with it, competitive pressure and cost-of-capital reductions.
  • For developers of small projects – especially C&I projects – transferability may smooth cashflow lumpiness challenges caused by the need to accumulate a “critical mass” of projects before it’s big enough to pull in outside money. During those accumulation windows, development and construction carrying costs add up, making these very tough businesses to run smoothly and profitably. Directionally, that challenge will remain – it’s not as though an unstructured tax credit sale require zero costs/time/hassle – but I expect the challenge to shrink a bit with lower transaction-scale needed to justify closing a financing deal.

There are still a handful more, which I’ll spare you from. But, suffice it to say: the list of reasons to re-orient a project financing strategy to unstructured tax credit sales is very long. So many solar companies fail because the business is just too complicated. There are too many moving pieces. Too many stars must align. Too many groups must be in sync. Too many ways a project can die or a margin evaporate. The source of the complexity is extremely varied, and, as mentioned, it can be hard to quantify the costs. A few of you good readers have probably heard my “cost of chaos” diatribe on this topic. For those that haven’t, the punchline is: “when you see a chance to make your clean energy business simpler, don’t think twice.” This is the biggest such chance any of us have had in years.  


Tax credits have been hugely important to the renewable energy industry for 15+ years, and we’ve learned to wield TE structures 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 challenges TE structures impose. But, so too have these structures been a governor on renewable energy penetration. Transferability will materially relax that governor and allow the renewable energy and energy storage industries to reach a velocity not yet experienced. For most projects, transferability will lead to margin expansion, and even where a full TE structure still makes sense, the transferability option will embolden developers and their investors in ways that go far beyond project profitability.

[1] “Sponsor,” if you absolutely insist. They mean the same thing. The difference is that one of them makes sense and the other one is an offensive misnomer that has contributed to the problematic power imbalance between tax and cash investors for 17 years.

[2] Using a LPT is the most conservative, “structure-friendly” methodology; e.g. if transferability looks good next to an LPT, it will look good next to a P-flip or SLB.

[3] Yes, “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.

[4] Those who read my direct pay article last year will note that this is the exact same list of deltas, and generally this analysis boils down to the same questions.

[5] It’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 just OK.

[6] Look it up. It’s an extremely useful investment/risk concept to understand.

[7] EIA Preliminary Monthly Electric Generator Inventory (

[8] Which 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?