Much has been made of the expected impacts of the ‘One Big Beautiful Bill’ Act on the energy industry in the US. Others have already done the yeoman’s work of articulating the specific changes from the OBBBA (here, here, and here for starters), so I’ll focus on the so what.
For decades now, renewable energy has been subsidized in one way or another, in one market or another1, while it has progressively reached scale and seen costs tumble down. The era of subsidies is now ending, and solar PV and wind energy in particular will need to compete on their own merits.
Fortunately, it is likely that solar PV and onshore wind2 in particular have already reached escape velocity3 in key markets and applications. While the future pace and specific types of deployment will matter desperately to many existing companies (some of whom will fail), the overall trajectory is clear.
Renewables are staying in the US energy mix, and the coming shakeout will create opportunities for those positioned to thrive in this altered context.
So what is going to happen?
Solar PV and wind energy deployments will reset
The phaseout of the 48E / 45Y tax credits for solar PV and wind has been accelerated to qualify only systems ‘in construction’ by July 4, 2026 or in service by the end of 2027. These in-service dates are tight for large projects which often sit at the mercy of interconnection queues and permitting for their specific construction and in-service dates. Big projects that will qualify in time are already in-flight.
Safe harboring could extend the ‘in-construction’ path somewhat, but recent Treasury guidance has sought to clamp down on this practice by requiring ‘physical work’ to claim the beginning of construction. Previously, purchasing ~5% of the project’s value in e.g. equipment upfront was sufficient to safe-harbor a project for years and still receive tax credits. With these changes, this approach is riskier and more expensive, focusing on actual site specific work (like laying foundations) that often comes after permitting and interconnection approvals.
As a result, over the next ~18-24 months the project pipelines will likely soften in key segments. This will put pressure on developers and technology / service providers that are leveraged operationally to a certain rate of deployment. There will be cancelled projects and likely layoffs as participants adjust to the new shape of the market.
The only silver lining is that this will happen relatively quickly. If the safe harbor provision were kept as before, there would be an overhang of projects waiting to get built through the early 2030’s (advantaging those developers with the capital now to invest in safe harboring their pipeline).
As it stands, pricing and project pipelines will reset more quickly, keeping everyone on a more level playing field.
Residential solar will shift to third-party ownership
Residential solar is generally bought in one of three ways: outright in cash, with the proceeds of a loan the homeowner takes out, or not at all (with the system owned by a third party and leased to the homeowner). Residential solar purchased with cash or loans fall under a different tax credit (25D) than third-party owned systems (48E), with the former phasing out at the end of this year (2025), two years ahead of the 48E credit.
This difference in treatment will mostly hurt the independent installers that form the long tail of the solar industry, the ‘mom and pop’ shops of the residential solar world. Big players like Sunrun4 already deploy primarily ‘third-party owned’ systems (TPO) that will continue to receive tax credits through 2027 (or beyond with safe harboring5). They will be at an advantage and likely gain share at the expense of smaller installers.
The securitization and support infrastructure that underpins third-party ownership is non-trivial to spool up quickly, but I expect to see more installers shifting in this direction (alongside a large-ish contraction in the industry as installers exit rather than adapt).
Software and financial partners able to facilitate this shift should see demand.
Battery deployment will continue to accelerate
The tax credits for energy storage have been maintained, and the boom in batteries will continue. Particularly as the pipeline of new generation from solar and wind slows (and all the gas turbines go to data centers), batteries of all scales will be increasingly valuable in shifting energy around demand peaks.
More tactically, the differential treatment between storage and generation will create interesting project-level design dynamics. For example, most solar PV systems today are actually solar + storage with batteries co-located to shift energy to higher value evening hours.
It is not yet obvious how balance of system costs and soft costs (e.g., sales, design) will be allocated across the two, with the potential to shield much of the overall system costs under the energy storage tax credit. We already see companies like Sunrun repositioning themselves as energy storage companies (that also happen to deploy solar PV).
The wild card here will be the Trump administration’s ramp up of Foreign Entity of Concern (FEOC) requirements in tracing the provenance of system components. Given how reliant the global battery supply chain is on China (even for cells and modules assembled in the US), this could create pockets of tightness in the market as supply chains are reworkd.
Batteries, energy storage developers, and the software to manage them all will see increased demand over the coming years.
Software (broadly defined) will become more important
Because we’re making it harder and more expensive to add new generating capacity, we will have to get more out of the assets we already have.
This will mean investments in software to better orchestrate and maintain those assets, and refined market design and rate structures to incentivize grid-compatible behavior.
This will take many forms, from virtual power plant (VPP) and demand response (DR) platforms to vegetation and asset management tools to new tariffs focused on peak load. Market changes will be slower, and unfortunately no region will look like Texas any time soon, but expect continued plodding improvement.
These trends are already very much underway on all fronts (it’s not like it was easy to build infrastructure before), but it will get a boost relative to the counterfactual of IRA continuation.
Where does that leave us?
Perhaps surprisingly given the rhetoric on all sides, we find ourselves with mostly the same trends as last year, just weakened in spots.
Renewable energy, and solar in particular, will continue to be deployed. Batteries will continue to be deployed. Software will continue to be necessary to make the whole, increasingly decentralized system work. Nuclear and geothermal will get their chance. Coal is not coming back in any sustained way.
To quote Churchill6, “this is not the end. It is not even the beginning of the end. But it is, perhaps, the end of the beginning.”
“How Solar Energy Became Cheap” provides a good overview of how the action shifted around the world over time between the US, Japan, Germany, and ultimately China (in roughly that order) as subsidies and production advances opened progressively more mainstream markets.
Skepticism of renewable energy isn’t new. It goes back at least as far as the 1980’s and Reagan’s defunding of the Department of Energy as the oil crises of the 1970’s abated. But this time is different, for two reasons:
Prices have already dropped far enough that renewables like solar PV will still make sense for many deployments. Co-locating solar and gas-fired generation still offers compelling economics and time-to-power for datacenter developers (key drivers of load growth). High distribution charges make residential solar + storage and commercial-scale microgrids attractive in key markets (particularly given the continuation of battery-focused tax credits). State-level drivers like Renewable Portfolio Standards (RPS) and community solar programs will carry on supporting the market where they apply.
Learning curves will continue, with or without the US. The US is not driving global demand (or supply) for solar PV and energy storage equipment. In 2024, the US accounted for only ~8% of solar capacity additions (~50GW of ~600GW globally). While US suppliers will likely be harmed by any slowdown in local deployment, don’t expect global deployments (and concomitant learning rates) to slow down at all. This will likely drive further cost declines in equipment, even if US buyers aren’t able to realize them.
In this piece, I’m mostly focused on technologies with the potential to generate electricity at scale in the next few years. Geothermal, nuclear, and other more nascent technologies will follow their own trajectories (and have seen their credits maintained). The ending of EV credits will slow but not reverse the switchover from IC vehicles. High electricity prices and middling US models are probably a bigger issue for EVs medium term. Hydrogen is small and likely to remain so with their credits expiring in 2028. The extension of the 45Z biofuel credit is just a sop to farmers and existing refiners. Because it only rewards fuel production in-year, a few extra years won’t move the needle on getting new capacity built.
The big players that don’t do this have already gone bankrupt (see: Sunpower, Sunnova).
Sunrun itself forecasts safe-harbored credits through 2030 in its Q2 2025 earnings report. This was realeased just prior to revised guidance from Treasury, though it appears that small solar installations like those Sunrun specializes in can still use the 5% test as before.
Don’t ask me who the Nazi’s are in this metaphor