Akshat Kasliwal and Jesse Gilbert are renewable asset valuation experts at PA Consulting.
There was substantial fanfare around several provisions of the Inflation Reduction Act when it was promulgated into law just over a year ago. Near the top of the proverbial “excitement scale” was the production tax credit being newly extended to solar resources, which were historically limited to opting for the investment tax credit. However, roughly 15 months in, there is little evidence yet that would validate this excitement, with only a very small handful of utility-scale solar projects nationwide having opted for the PTC. This “reality check” could have significant impacts for billions of dollars’ worth of energy infrastructure assets, both existing and forthcoming.
Background
For context, at the core of this industry-wide enthusiasm was widespread belief that solar projects having this optionality would enable them to lower their Levelized Costs of Energy, or LCOE. In fact, there was general consensus that most utility-scale solar projects — in all-but-the-sunniest parts of the country — would see lower LCOEs, relative to a world without the IRA, enabled by them now likely opting for the PTC.
This “PTC lean” translated into several industry stakeholders assuming more favorable solar economics — and thus greater solar penetration, among other outcomes associated with mass adoption of the PTC — in their forecasts of what future energy markets could look like. For instance, the U.S. Energy Information Administration, in their post-IRA Annual Energy Outlook, projects almost twice the amount of nationwide solar buildout, or a staggering 200 GW of incremental capacity, relative to their prior view, largely driven by the PTC. In the California Public Utility Commission’s 2023 Integrated Resource Planning study, new solar resources are blanketly assumed to elect the PTC, owing to it being “more advantageous on a present value basis” relative to the ITC. Finally, Lawrence Berkeley Lab’s 2023 annual utility-scale solar outlook mentions that “Starting in 2023, [Power Purchase Agreement] prices could benefit from solar now having access to the PTC… All else equal, many utility-scale PV plants will find the PTC to be more valuable than the ITC.”
Observations to-date
Empirical evidence, however, tells a different story. The overwhelming majority of new utility-scale solar projects that have been financed since the passage of the IRA have continued opting for the ITC. Publicly-announced exceptions appear to be the Appaloosa Solar Project and the Faraday Solar Project in Utah, the Tierra Bonita Project in Texas, the Vikings Project in California, the Oxbow Project in Louisiana, and the Conway Project in Arkansas. It is worthwhile unpacking why that may be the case.
Endogenously, there are a handful of drivers which inform the decision between the PTC and ITC, including: a project’s capital costs; its anticipated annual/lifetime generation volumes; the congestion and curtailment risk it faces; the sponsor’s proclivity for operational risk, or lack thereof; views on inflation and discount rates; the (un)availability of bonus tax credits, including for utilizing domestic content, siting in an energy community, etc.; whether or not the project’s output is contracted with an affiliated counterparty; etc.
However, there are “exogenous” considerations too, beyond a sponsor’s direct control, including: the availability of, and access to, PTC versus ITC investors, given the two alternatives have different risk/reward profiles; varying IRS recapture rules between the PTC and ITC; differences in treatment of depreciable bases and application of fair market value step-ups; uncertainty around future taxable income levels; competition for PTCs with wind resources; etc. Ultimately, it is fair to say that even in regions where solar irradiance is high and development costs are low, there likely will always be some fraction of newbuild solar resources that either chooses not to opt for the PTC, or is unable to elect it based on external factors.
Of course, this is not to say that the death-knell has been sounded for solar PTC — far from it. In many ways, 2023 has been a year in transition for the broader power sector, as industry stakeholders have grappled with a lack of precedent around numerous IRA provisions; Treasury has been slow to issue guidance on certain issues like transferability; and “macro” issues such as supply chain constraints, elevated capital costs, and congested interconnected queues have persisted. As the market internalizes post-IRA practices and procedures, and adjusts to broader structural changes, optimism remains for the solar PTC.
Why this matters
There are meaningful implications for what the future might look like, based on whether/how solar PTC uptake evolves in the next 12-24 months. In a world where the proliferation of solar PTC does meaningfully increase, three noteworthy things could play out.
First, solar projects — particularly in regions like the West and the South — could indeed see lower LCOEs, thereby theoretically lowering PPA prices. This has not yet been observed, as indicated by persistently high PPA prices even post-IRA, as reported by LevelTen Energy. Second, regulated investor-owned utilities could see more accretive returns, owing to the fact that the PTC makes them more cost-competitive with third-party developers — owing to the ITC’s normalization rules — giving them the opportunity to “self-build” versus contracting. Third, all else being equal, a broad swath of solar resources opting for the PTC will result in greater frequencies and levels of negative prices in power markets, which could translate to greater output curtailment and lower energy revenues across most generation asset classes. Moreover, this may subject contracted assets to penalties under their offtake agreements, if potential volumetric obligations are not satisfied.
Case studies
An indication of what this future could look like is observed in the Southwest Power Pool power market, which covers several Great Plains and Midwestern states. SPP has seen a large proliferation of new wind projects over the past five years, with most of the fleet receiving PTC incentives. This has resulted in a meaningful uptick in headwinds to revenues; for instance, from 2018 to 2022, total wind curtailment grew from under 2% to over 12%, while average negative price levels worsened by 80%.
These PTC-driven outcomes are plausible elsewhere too. In the Electric Reliability Council of Texas — the power market encompassing most of Texas — the Panhandle region is comprised almost entirely of wind assets currently on PTC. Pricing data from 2022 would imply nearly 20% curtailment for a non-/off-PTC solar asset.
We need to recalibrate expectations for solar growth
The aforementioned “case studies” demonstrate potential outcomes resulting from deep PTC-resource penetration. While it is too early to infer whether the slow start for the solar PTC is a speedbump in the road to its widespread adoption, or portends longer-term headwinds, it is clear that the outcome has meaningful repercussions.
At minimum, the slow adoption to-date highlights a need for a recalibration of expectations amongst the financial, policy and analytics communities within the energy industry. The promises of solar PTC were higher returns, lower PPA prices for offtakers, new opportunities to site batteries and arbitrage power prices therein, smaller quanta of upfront tax equity commitments, greater investor-owned utility project development and ownership, etc. However, and as is typically the case in the energy industry, the reality has been — and will likely continue being — more nuanced.
