IRA of 2022 - Some Possible Implications of Turbocharged Fiscal Support

SUMMARY

The Inflation Reduction Act of 2022 (IRA) provides significant, long-term funding for non-GHG-emitting energy technologies. The amount of money and the breadth of potential projects potentially benefiting from that funding could provide a significant tailwind to new infrastructure development. But questions remain about how the IRA will affect energy and utility companies in project planning, development, and construction. And many details of IRA-related program implementation, such as regulations regarding tax credits, are still to be determined.

AN EMBARRASSMENT OF RICHES

The IRA, enacted in August, authorizes $369 billion to ensure energy security, reduce greenhouse gas (GHG) emissions, and increase energy innovation in the United States. This figure does not include the IRA’s approximately $100 billion increase in loan authority under existing programs and new lending authority of $250 billion under a new Energy Infrastructure Reinvestment Program, all managed by the DOE Loan Program Office.[1]

The IRA climate-related spending dwarfs previous federal spending on climate-related initiatives, including 2021’s Infrastructure Investment & Jobs Act (IIJA), and is intended to dramatically lower projected U.S. greenhouse gas emissions through 2030.

The IRA has many provisions, particularly production and investment tax credits (PTC and ITC, respectively) for electric generation from and manufacturing of certain favored technologies (and technology-neutral, emissions-based clean technologies). Some activities, including domestic content thresholds, prevailing wage requirements, qualified apprenticeship requirements, and project location incentives (“energy communities,” low-income communities), can enhance levels of tax credits.

Also noteworthy is that tax credits are eligible for direct pay for non-taxable entities (e.g., state, local, or tribal governments; Tennessee Valley Authority; etc.) and transferability to other entities with corporate tax liability. This will provide a significant additional direct constituency for these funds. And given the tax credits’ transferability, one would expect a significant secondary market for IRA credits.

The interplay of tax credits and loan guarantees affords opportunities for clean energy infrastructure developers and owners to combine available project tax and financial support (see Figure 1).

Figure 1. Selected Illustrative Projects and Potential Post-IRA Enhancements to Project Economics

One area of interest still to be resolved is how IRA tax credits interact with minimum tax liabilities. A revenue “pay-for” for the IRA is the minimum tax for companies with financial net income in excess of $1 billion. Many companies that might avail themselves of tax credits—e.g., banks, investment banks, private equity firms, and utilities—have significant net income, so they will be interested in how these credits might help reduce tax liabilities. Still to be determined through Treasury regulations is whether IRA clean energy tax credits can offset minimum tax liabilities and to what extent.

POTENTIAL IMPLICATIONS OF THE IRA

What Happens to Integrated Resource Plans (IRP)?

Given the potential significant impact of federal investment support for utilities for low- or no-emissions resources, many utilities will be considering when they will need to revisit and potentially significantly revamp assumptions and resource options.

For many, the integrated resource planning schedule runs in a refresh cycle of two to three years. For IRPs that are in process or have been recently issued, there is a question of whether to update the IRP now or wait until the next cycle and more definition about the IRA and its implications. Another alternative may be for planners to develop a side case assuming IRA applicability and related funding and potential resource options and costs.

Several factors may drive regulatory and utility interest in updated IRP or side cases. System characteristics play a role. For example, is the utility close to building new fossil-fired units? Is there already a high penetration of renewables such that incremental renewable resources may affect system performance? Then utilities may need to consider sooner the implications of additions of less expensive (from the utility’s perspective) IRA-supported assets.

Other considerations are the policy and regulatory preferences of the utilities commission. Regardless of when IRA impacts are factored into IRPs, there will be more complexity in modeling, as the economics of various options and associated customer effects may have changed significantly.

What Are the Implications for Utility Investment?

With more than $600 billion in government support available (including loan guarantees), significant amounts of capital will be deployed. With tax credits, effective costs to customers of some projects could be reduced significantly. Some more expensive technologies may become more feasible for development.

Despite the IRA’s moniker, a wild card for investment requirements will be inflation. With the level of expected activity driven by policy support, a key question is how much labor and materials will be available for all of this anticipated construction? With so much capital chasing fewer workers (see Figure 2), potential supply chain, labor availability, and materials availability issues may arise. These could be particularly acute with already bottlenecked raw materials for clean technologies such as batteries.

Figure 2. Civilian Labor Force Participation Rate (Seasonally Adjusted)[2]

Even before the IRA, wage rates for craft labor were steadily rising and have spiked in 2022.[3] Thus, one possible unintended consequence could be increasing costs for capital projects, which has the potential to offset some of the cost savings contemplated by ITCs.

In its analysis of the IRA, however, Penn Wharton found that the act could slightly increase inflation until 2024 and decrease inflation thereafter, indicating low confidence that the law will have any impact on inflation.[4]

Over the long-term, IRA investments could improve worker skills and productivity. A novel apprenticeship provision tied to the ITC and PTC could train the next generation of craft labor. To qualify for the 30% ITC noted in Figure 1, a certain percentage of a project’s labor hours must come from apprentices participating in the U.S. Department of Labor's Registered Apprenticeship program or a state equivalent. The apprenticeship requirement is currently 10% of labor hours and incrementally increases to 15% in 2024 and beyond.

Interest rates are a potential factor to watch with increased capital investment, as the Federal Reserve and other central banks continue their tightening cycle. Will higher rates offset low capital costs? How long will rising rates last? How will loan guarantees help?

Finally, while the IRA can reduce capital costs for qualifying projects, there has been little discussion about the long-term effect on operating and maintenance costs of an increasing number of assets. However, it should be noted that the IRA requires that projects seeking PTCs or ITCs must meet prevailing wage requirements during the construction, alteration, and repair of the facility for ten years after being placed in service for PTCs and for five years after being placed in service for ITCs.[5]

Are Permitting and Interconnection Processes Ready?

Pre-IRA, a steady wave of solar, wind, and storage project development had been growing over the past 10 years, accelerating in the past few years. This has led to large backlogs in interconnection queues in many regions (see Figure 3), particularly as interconnecting generation is smaller, dispersed, and renewable.

Figure 3. Power Plants Seeking Transmission Connection by Type and Mapped to Region (as of Year-End 2021)[6]

In fact, in June 2022, the Federal Energy Regulatory Commission issued a notice of proposed rulemaking with a view to expedite processes.[7] While some regions have proposed queue reforms, those new processes have involved freezing the existing queue and working through the current backlog of proposed projects.[8]

While improved interconnection processes are being worked out, permitting of large infrastructure projects—especially pipelines and bulk power transmission—remains difficult across all regions of the country. To achieve emissions reduction goals envisioned by the IRA, transmission from renewable-rich zones to demand centers and pipelines for hydrogen and renewable natural gas will be needed. However, permitting reform envisioned in a much-discussed Manchin-Schumer side deal has been deferred for now. So even with “unstuck” queues, projects may still have long runways for development.

A key question, then: will supply resources enabled by the IRA be constrained or unconstrained by other infrastructure? Will constraints be eased? Will backstop siting authority be resuscitated? Will transmission remain balkanized?

With transmission constrained, other paths of lesser resistance may lead to interest in other more local solutions that have policy support. This may be resources that are more easily sited near demand centers or easier to interconnect. Some examples:

• Offshore wind: It may be easier, at least from a permitting and siting perspective, to build transmission offshore rather than onshore, with fewer landowners and jurisdictions to contend with.
• Long-duration storage: This might provide a smaller, more modular solution nearer to load, assuming this technology can get to commercial scale in the near term.
• Small modular reactors: The ability to redeploy sites of retired coal-fired power plants for SMRs could be easier as both brownfield development and location-specific potential grid support.

SOME CLOSING THOUGHTS

With the enactment of the IRA, utilities may need to reconsider their historical assumptions and paradigms regarding the level, type, and timing of resources and grid infrastructure they may wish to consider in their supply portfolio.

With so much federal largesse, there will be a “land rush,” with lots of capital chasing lots of projects. The breadth of project types eligible for support likely means there will be some winners and some losers. Successful technologies will be able to scale-up, which is the intent of this support. But what about losing “bets”? How will prudency be determined? Will that increase risk and how should utilities manage that risk?

New business models will emerge as IRA-favored technology value chains grow. Firms will position themselves in areas that provide growth and for whom the value chain element favors the firm’s technologies and competencies. To that end, there is potential for more acquisition activity to increase skills and capabilities to build low-emissions energy projects. For example, the IRA was a key driver for RWE Renewables Americas’ October 1 purchase of Consolidated Edison’s clean energy business. As RWE’s CEO Krebber said, “The Inflation Reduction Act provides a stable, long-term investment framework that makes this acquisition even more attractive for us.” From Con Edison’s perspective, the sale allows focus on its core utility business and its activities within New York’s energy transition.[9]

Finally, as discussed earlier, a key variable in the post-IRA environment is whether the United States will be transmission “constrained or unconstrained.” In a constrained world, more firms and communities could be interested in microgrids or other local solutions. Given the breadth of potential recipients of IRA incentives, large commercial and industrial firms and process industries could look more closely at self-generation with more generous incentives (e.g., solar + hydrogen).

Meanwhile, energy and utility companies will watch closely as programs and regulations promulgated under the IRA take shape over the coming months.