by: David Riester
Our quick-take quantitative analysis (link) isolating the impacts of H.R.1’s clean energy ITC cuts unearthed reactions and questions worthy of discussion. We appreciate the engagement and the focus it puts on this crucial moment for the energy industry, and America at large.
To address a few points that have been raised:
How does your analysis reflect the bill that passed (H.R.1) vs. the original May 15th Ways & Means draft?
Our initial analysis highlights the passed H.R.1 bill compared to the status quo, and does not address the original draft from Ways and Means. The two last-minute provisions that were added to H.R.1 that we are most concerned about are:
- New requirement that projects must commence construction within 60 days of bill enactment
- Removing the three-year phasedown of tax credits from 2029-2031; 30% investment tax credit now turns to zero after December 31, 2028 (based on when a project is completed, or “placed in service” for tax purposes)
Due to the last-minute addition of the “commence construction” requirement, huge swaths of projects slated for 2028, 2027, or even 2026 completion are going to miss out on tax credits due to project slippage or failure to start construction in 60 days. We expect most of those projects to be canceled. Our estimates:
In other words, we expect only 30% of planned 2028 projects to achieve “commencement of construction” prior to the 60-days-post-enactment milestone, and place in service before the end of 2028. We expect this to drive substantial near-term project attrition as many of these projects will not pencil with 30% of their capital stack vanishing. Some will find a way to move ahead – especially those with data center or advanced manufacturing offtake – but the “ITC gauntlet” will be deadly indeed. [The “Why?” of this is further addressed in the next section]
Eliminating the rampdown of tax credits from 30% to 24%, 18%, 12%, then 0% (see table above) is also very chilling for investment, as noted in our previous post.
Segue forecasts the following attrition based on the version of the bill passed vs. the “original” (Ways & Means draft) version of the bill:
In short, although the Ways & Means draft would still lead to over $100b of canceled investment, the impacts of the bill that actually passed are much more severe to the power sector:
The canceled investment would largely be front-loaded for projects that would otherwise begin operations between now and 2030:
Why are industry stakeholders so opposed to the requirement that projects commence construction within 60 days of the bill being enacted?
The 60-day “commence construction” requirement is enormously destructive. If your project was not already on track to commence construction prior to September or October of this year, you now need to move heaven and earth to effectuate that outcome. Development timelines for utility-scale solar, wind, and battery projects are generally 3 – 5 years; in that context, 60 days is barely any time at all. Project owners need a lot of time, resources, and capital to commence construction (for tax purposes) on a development-stage project. Why is this so challenging?
- Complexity: There is a whole body of tax law around what does and does not qualify as “commencement of construction”. Meeting this threshold requires considerable legal support, delicately executed procurement and/or construction, credit, liquidity, relationships, and negotiating leverage. At the tail-end, your financing parties’ tax counsels need to sign off that you did everything properly, otherwise it was all for nothing.
- Financial Risk: Perhaps more importantly, for many projects the 60-day window will fall at a point in the development process when the remaining fatal flaw risk is far too high to support the decision to spend the money to commence construction.
- Execution: Finally, developers willing and able to navigate the complexity and take on the financial risk are still at the mercy of permitting, interconnection and procurement timelines to actually do the work to commence construction. As an example, even if you want to start building early, towns and counties are completely indifferent to your 60-day “shot clock” problem and will get to a permit hearing when they get to it. Manufacturers might be a bit more responsive and begin off-site construction work on major items like transformers, but there is only so much equipment to go around, humans to generate executable purchase orders, capital to go toward signing deposits, etc.
There are always more losers than winners in this safe-harboring game. The only sure winner is the lawyer you’re engaging[1].
If i) there's all this demand out there we have to meet, and ii) a solar/wind/storage portfolio addresses that demand better (and more quickly) than adding more thermal generation (two claims you make), then isn't it clear that the load side will simply absorb the price increases necessary to account for lost tax credits, and the energy transition will carry on just fine?
This is correct in the long-term, but the expectation of near-term cost pass-through presumes we are in an efficient, functioning, free market...which we are not. The power market is inextricably linked to heavily regulated critical paths, such as interconnecting to the electrical grid, regulated attribute markets (capacity, ancillary services), state and federal legislation (e.g. LNG exporting, pipelines, tariffs), permitting, and more. In power, like at a middle school social, the dance of supply and demand is a clumsy, uncoordinated mess rife with awkward gaps, sudden pile-ons, and the occasional chaperone (grid operator) desperately trying to keep the lights on.
We expect it will take several years for the market price of contracts (electricity, capacity, ancillary services, and other attributes) to readjust upwards to fill the 30% gap left by the abrupt removal of the investment tax credit. Most power plants rely on long-term contracts in order to obtain financing; the prices of these contracts are negotiated via RFPs, auctions, and bilaterally. The process to bid, negotiate, and sign these contracts often takes several years and, even once they are signed, you still have to build the power plant.
What we have is a severe sequencing problem.
Let’s say you have an advanced-stage project with a signed PPA / capacity contract / REC contract / tolling agreement, and the forecasted margin abruptly plummets from, for example, +8% to -22% because the tax credit is legislatively erased. The idea that a developer should just accept lower profits, or “find a way to make it work” is absurd. At this point in development, any good developer has already optimized all aspects of the project (procurement, design, financing) to squeeze out that 8% margin with a competitively secured power contract. The day you zero out the tax credit in the project’s valuation model, you send the project deep into “distressed asset” territory. In such instances, we aren’t dealing in shades of grey, we are dealing with black turning to bright, bright red.
It's reasonable to believe in the project’s fundamental value and its ability to attract viable electricity prices at some point. Your old ECON: Micro 101 textbook suggests that whoever is buying the power from the project will make up the difference, by raising the electricity rate to make up for the 30% shortfall in project value. But our situation is neither academic or playing out in an efficient market. The utilities contracting with the power plant for electricity/power are heavily regulated; when you call them and ask for a 30% – 40% change in the contract price, it could easily take them 3 years to say “yes”. They will likely need to restart the contracting process, rather than accept such a substantial change in price. Corporates (data centers, manufacturers, etc.) can perhaps move a bit more quickly but even they will re-evaluate their options if their biggest operating expense increases by 30% – 40%.
In the meantime, for the power plant developer, the bills keep coming. Investors would be confronted with a portfolio of development-stage projects, each one of which has turned deeply unprofitable overnight with the potential to recover value over many years. This is a nightmare scenario for a capital allocator. A massive new risk – “will someone pay for this power at a rate that is ~30% higher than it was before?” – now looms over nearly every stage of development. Mass project cancellations and layoffs will ensue as an unprecedentedly chaotic period of market turmoil drives conservative behavior and hundreds of companies and investors leaving the US energy market altogether.
Markets tend to struggle when its participants are asked to i) take more risk, and ii) expose more capital to that elevated risk. That’s what the 60-day commence construction requirement does, and our electrical grid, economy, and overall strength as a nation will pay a big price if it’s imposed.
How do you know? That sounds like speculation, and I’ve seen articles about large IPPs saying they’ll push ahead.
For hundreds of projects in the market, Segue is actually the party holding the checkbook and facing that conundrum. And, while I'm sure we will "pick our spots", choosing to navigate that minefield for especially well-positioned projects, it is just as certain that we will kill dozens of projects that would otherwise become power plants if the sequence of investment, risk mitigation, and value crystallization were allowed to unfurl without the 60 day bottleneck and the 12/31/2028 100%–to–0% cliff. For example, the Segue team spent much of last week deliberating whether to sign five PPAs we were awarded by a regulated utility under a competitive RFP process. The projects will come online after the H.R.1 sunset, the prices agreed to were calibrated to existing law (30% ITC)[2], and signing the PPAs requires large financial security deposits. This is the exact scenario discussed in the section above: in the end, the utility offtaker may agree (eventually) to renegotiate the prices upwards to render the power plant worth building, if the law changes, but when… and how much? Will the regulators (PUC) allow the utility to adjust the price or will they require the utility to re-run the RFP? How much more capital are we prepared to bet on this potentiality that falls entirely outside of our control? We’re investors, not gamblers.
Yes, some big IPPs are signaling strength and confidence. But what would you have them say? It’s important to project confidence in your most visible and mature projects when investors, utilities, permitting authorities, etc. are watching; but behind the scenes, these groups are seeing the same things in their valuation models as we are: swaths of their project pipeline will be well underwater and on the chopping block if the bill passes. Furthermore, fewer than half of the projects currently in the pipeline are owned by large IPPs, and the balance of this universe is most vulnerable to the “gauntlet” – smaller and/or develop-and-flip shops with liquidity constraints and more concentrated risk to navigate. In the massive, heterogenous, locally-driven, dislocated, ever-evolving renewable energy market of today, that half of the power development market is indispensable. Accepting their demise would be like saying “Google, Apple, Microsoft, and Meta will survive, so it’s fine if the next generation of OpenAI, Stripe, Wiz, and Canva are killed in their infancy”. Maintaining robust competition within the renewables sector keeps electricity prices down for everybody.
"So? A bit of healthy culling can be a good thing. A little Darwinian bottleneck will make the industry stronger!"
Tell that to the 2030 ratepayer (voter) who’s paying twice as much for less reliable power because there isn't enough power supply in the market after price-insensitive data centers and crypto miners have swallowed up half of it. As we flagged in our previous post, 2/3rds of all forecasted grid additions between 2026 and 2033 are solar/wind/storage projects currently banking on the investment tax credit. This bill would be a systemic shock, not a “healthy culling”. The medium-term damage from by the abrupt sunset of the tax credits would be excruciatingly painful for utilities, grid operators, and ultimately anyone who pays electricity bills. A gradual phase-out of tax credits such as in the original (Ways & Means) draft allows a much more organized and less catastrophic transition to a post-ITC world.
"Stop whining and compete."
That has a nice ring to it. Yes, the clean energy sector complains loudly, but we are also very resilient. We kept our lunch through a violent two-decade long roller coaster, and H.R.1 wouldn’t change that if it passed; we’re pretty thick skinned. Our “whining” is not mere self-preservation. Rather, we are desperately trying to avert an avoidable disaster that will affect a huge swath of Americans. An abrupt rug-pull would destabilize not just the renewables industry but the entire electricity sector. A gradual phase-out allows the growth of America’s power grid to continue to meet the challenge of load growth with affordable and reliable power.
Rest assured, Segue is not going to pack up and go home if this bill were passed. We would pick our spots and, having raised the “bar” for investment and seeing bigger wins from the winners (because construction-ready power supply would be an increasingly scarce commodity), probably end up with comparable returns. But our resources will support fewer additions to the grid. The logic:
- Risk-adjusted return targets (the efficient frontier) are inelastic, and risk just went up across the fleet of candidate projects, therefore the cost of development capital would increase.
- Capital providers will be forced to triage. To ensure mission-critical projects survive the ITC Gauntlet, more capital will flow towards those assets. Capital being finite, that leaves less for the balance of the pipeline.
- For some investors this violent whiplash will be the final straw, and they will simply go focus on other energy or infrastructure markets. This is especially true for foreign investors, and it’s not theoretical. We’ve already had multiple overseas investors previously engaged in ongoing financing or acquisition processes withdraw due to fresh mandates from on high – “no more US until further notice.”
The upshot: more abandoned projects, fewer pursued anew.
The stakeholders most affected would be i) retail, commercial, industrial ratepayers, and ii) industries (such as data centers and advanced manufacturing) that are relying heavily on the availability of power, whether reasonably priced or not. Properly sized/calibrated developers and investors will show up and compete just fine regardless of where this reconciliation bill lands.
Herein lies one of the great misconceptions about the renewable energy sector: we aren’t afraid of becoming unsubsidized, we are afraid of a disorganized, abrupt, sloppy transition.
The investment tax credit for solar has been set to expire, and then extended, six times. The production tax credit for wind has been set to expire, and then extended, thirteen times:
Those prior instances of impending sunset have forced the sector to confront imminent change repeatedly, almost to the point of comedy. In each case, the government chose to extend the credits. As was true for other priority American Industries over the years – e.g. oil, natural gas, the rail system, aviation, nuclear energy, and defense – the people spoke and congress deemed it in the nation’s best interest to provide extra support to a burgeoning industry or technology. Through most of that journey, the credits were unquestionably essential for the continued growth of the sector and its progress down the technology cost curve. However, a few years back (2018 – 2020?), the notion of competing in the power/energy sector without significant subsides began to feel within reach. As module prices came down[3], we started hitting “grid parity” in a few geographies, and the prospect of higher natural gas prices indicated grid parity may emerge more widely in the years to come. The big question became not if renewable energy could compete with thermal/fossil generation, but, with an eye on energy dominance and the existential threat of climate change, how fast do we want to transition to clean energy?
The energy and power sector – not just clean energy – has been responding to, and operating within, the conditions set before us. One of the key conditions that has set the trajectory of today’s energy market is the tax credit runway and scheduled sunset. These credits existed before the IRA. They were put in place initially, and further extended by, Republican administrations. They are neither new instruments nor are they unique to solar and wind. They are scheduled to expire, and always have been. Moreover, the clean energy sector has already accepted the reality that the sunset schedule is going to be pulled in during this administration. We don’t love that, but, as always, are prepared to do our part to make America the dominant energy powerhouse of the world regardless of the conditions set before us.
But, importantly, our development strategies, project pipelines, products, and pricing are all calibrated to the circumstances and runway established by current law. No part of the energy ecosystem – clean or otherwise – can pivot on a dime. As such, “ripping the rug out” from under the sector has outsized damage in the near and medium term, especially at a time when the viability of alternative sources of power – namely natural gas – have severely declined. The economic term for this is “dead weight loss.” You don’t want dead weight loss, whatever your political leanings.
So, yes… clean energy will prevail in the long-run, and yes, all of us plan to compete without outsized tax credits. But taking a wrecking ball to the existing subsidy structures will result in electricity/power users around the country bearing the costs. The economy would almost certainly suffer as power costs and shortages hamper growth (or contribute to a recession). In all likelihood, China would leave the US in dust on the first lap of the "AI Arms Race".
And this is all to say absolutely nothing about climate change.
It’s been hard to track what cost/spending math is being used in Washington DC. What is the House expecting to save by eliminating 45Y and 48E? What numbers were the basis for the negotiation that ended with H.R.1?
As of this blog post, the CBO has not issued a report on H.R.1 vs. the original draft bill. However, the Joint Committee on Taxation (JCT) has issued reports comparing the Ways & Means draft[4] and the passed H.R.1[5] bill’s projected savings w/r/t the 45Y (ITC) and 48E tax (PTC) credits[6]:
Yes, you read that right. In other words, the government forecasts that they are saving taxpayers an incremental 10% by adding the new provisions of (a) the 60-day commence construction requirement and (b) the abrupt elimination post-2028 vs. gradual phasedown between 2028-2031. But as you’ve read above, that incremental 10% savings to taxpayers represents the difference between a disappointing downshift and a full-blown catastrophe for the only sectors on pace to add meaningful capacity to the grid over the next five years.
The optimists in us want to believe that this is largely a misunderstanding – that, amidst the fog of reconciliation war, the sleep deprived members of the House who do care about America’s power sector simply failed to register the implications of the 48E deletion, which was probably framed as a minor tweak amidst a rush to vote. The JCT math above offers some evidence supporting this idea.
Indeed, it appears that there is an exceptionally attractive opportunity for America to get a ~13x return on the investment of $18b. If that’s the marginal cost of going back to the Ways & Means draft from May 15th, and the marginal return for America is $233b (or anything remotely close to that) in first-order economic activity[7], then surely all legislators will agree to make that investment in America’s energy dominance and economy. Rep. Garbarino and the pro-energy moderates in the House just temporarily miscalculated the ramifications of a midnight compromise, which is understandable. There’s every opportunity to correct the course.
What about transferability? What about FEOC?
We focused our analysis on trying to quantify what would happen if the 45Y and 48E tax credits disappeared to maintain a digestibly sized report, and stick to matters for which we feel confident in our methodology. The effects of i) the elimination of Section 6418 “transferability” and/or ii) catastrophically vague, sweeping FEOC language, could cause as much damage as the elimination of 45Y and 48E credits – that damage is, however, inherently harder to estimate. That said, we appreciate others in the industry flagging these as critical issues to get right in this bill. Our omission should not be interpreted as a lack of concern. Our friends over at Reunion Infrastructure have a concise write-up on both of these issues that we’d suggest you read; we agree with their analysis and key takeaways.
What should the industry’s ask be on the ITC/PTC?
After reading our initial analysis, many suggested we make a specific recommendation. The reason we didn’t is that our (reality-bound) recommendation is broadly consistent with industry consensus.
Put simply:
- Go back to the May 15th Ways & Means draft, but…
- Change the sunset “threshold” to start of construction instead of placed-in-service
- Leave transferability be
- Fix FEOC[8]
We might note that recommendation contains some bias. For example, the residential sector would obviously prioritize a bit differently. Around the edges there are small disagreements driven by sub-sector (utility vs. resi), vocation (tax attorneys vs. everyone else), place in the supply chain (manufacturers vs. installers/developers), but it seems we are all advocating for similar landing spots.
[1] As such, we suggest any signaling of market behavior conveyed/framed by a tax attorney be seen through a skeptical lens. The more the industry panics to “safe harbor”, the bigger the legal bills. Historically, this incentive structure has combined with an industry-wide action bias to result in systemic “over-grandfathering.”
[2] Any bid priced to a “no subsidies” situation would have been wildly uncompetitive in the RFP
[3] https://www.nrel.gov/news/detail/program/2021/documenting-a-decade-of-cost-declines-for-pv-systems
[4] https://www.jct.gov/getattachment/1bd9dac5-2717-4422-8369-e8d342d57be8/x-22-25R.pdf
[5] https://www.jct.gov/getattachment/c196154d-79b4-4bbf-85ba-feddc22cf422/x-26-25.pdf
[6] Credit to Jason Clark at Power Brief for pointing this out
[7] Our analysis only includes planned PV/wind/storage projects from 2026-2033 (i.e., projects in the interconnection queue), while the JCT’s analysis includes all 45Y/48YE-eligible technologies and includes planned and unplanned projects. So, the multiple is likely meaningfully higher than 13x once you factor in those additional projects we aren’t including. Moreover, this math says nothing about the second- and third-order impacts (to power-intensive industry, inflation, and the economy at large)
[8] Segue has not delved into specifics on FEOC. It is clear that the sweeping, broad, imprecise language used would be a massive problem; what, exactly, to change it to seems well covered by dozens of other qualified law firms and advocacy groups
