The Inflation Reduction Act (IRA) of 2022 is poised to energize development of solar, storage and wind projects like nothing we’ve seen before. As a result, interesting questions are coming into focus. Answering them correctly can maximize benefits that are on the table.
Certainty Means Everything
After several years of uncertainty over federal tax benefits, import risks and supply chain volatility, the renewables market seems to be entering an era of greater stability. Generous tax benefits and associated incentives are now available until at least 2032. Until passage of the IRA, investors, regulated utilities and independent power producers were understandably nervous about pulling the trigger on significant new project investments. As a result, we’ve seen many projects stall or even be canceled over the past couple of years.
Market stability is the tonic the industry needed. Even with the new tax benefits and other incentives, these projects will still take years to develop in most cases. Depending on the geographic region, some projects could be looking at a five-year plus process before construction teams can mobilize to a site, requiring a significant long-term commitment of resources and money.
The biggest variable will continue to be the interconnection queue administered by regional transmission organizations and independent system operators (RTOs/ISOs). The backlog of applications for every RTO/ISO in North America can mean years of delays. Another aspect of a congested grid is that each project needs to be considered more carefully before submitting an interconnect application. As a result, developers are spending more time conducting due diligence on sites before moving forward, which takes time and financial investment.
The certainty that favorable tax incentives will be available through 2032 — plus the possibility of them stretching beyond — gives investors and utilities the assurance they need to move portfolios forward.
ITC or PTC?
Solar developers in particular will now have some interesting decisions regarding whether it will be more beneficial to take an investment tax credit (ITC) or a production tax credit (PTC). Different answers are likely to emerge for different regions. Considerations will be based around regional irradiance, array design and spacing, cost of capital, and total installed cost for the project.
The ITC is now structured to allow owners to claim 30% of their total relevant construction costs as an upfront one-time credit. Additionally, owners who can meet requirements for sourcing domestic components and materials and siting projects in designated energy communities can qualify for an additional 20%, resulting in a total potential project ITC of 50%.
The PTC offers a different set of considerations for developers and owners. It offers a credit of $26 for every megawatt-hour of electricity produced over a 10-year period. For renewable projects that can achieve a high capacity factor, this will be a more advantageous option than taking the ITC. For many projects this decision will be easy, but for others this will require careful consideration to determine whether the ITC or PTC is the most economically advantageous route.
Solar projects that aim to take the PTC will face different strategic decisions than those using the ITC. Different design considerations around ground coverage ratio, inverter loading ratio, and even how storage is coupled and sized would need to be optimized for a PTC plant. A focus on reliability will be critical as tax benefits would be associated with generation, not just the initial capital spend.
Which pathway will pencil out as the better deal? The answer will depend on many variables, including normalization rules, capacity factor, construction costs and cost of capital. This is a crucial consideration but not necessarily a simple one.
Direct Pay and Transferability
As a result of the IRA, nontaxable entities like cooperatives, municipal utilities, and federal power agencies like the Tennessee Valley Authority are now evaluating entering the renewables market as owners, not merely offtakers. This is a result of the direct pay feature available to nontaxable entities. However, these entities haven’t necessarily been planning for this development, and as a result typically do not have “shovel ready” sites with interconnections available for construction. Because of this, expect these nontaxable entities to start evaluating and selecting some development transfers and build/own transfers moving forward.
For taxable entities like independent power producers and investor-owned utilities, tax credits are now transferable. This opens another avenue for owners that do not have sufficient tax liabilities to fully monetize their tax credits. Rather than using a tax equity partnership, taxable owners can now elect the transfer option and sell their tax credits. This raises a key question: What will be the going market rate for transferable tax credits? Will it be 85 cents on the dollar, or perhaps 95 cents? The answer to this may factor into which monetization approach is selected.
Outlook Is Full Go
We’ve entered a new era that will require owners and developers to spend more time in thoughtful upfront planning and due diligence, scoping out potential direction and strategic considerations for bringing new renewable projects to market. With the certainty that the IRA provides the market, we should expect to see an exceptionally strong decade in renewable deployment.
Those that begin strategically planning now stand the best chance of frontloading some considerations and investigations to make the most informed decisions. The IRA offers new opportunities for those that are able to optimize around it.
Navigating the way forward in this new era of tax and financial incentives includes evaluating new technology as well as other options.
