How clean energy economics can benefit from the biggest climate law in US history
At over 700 pages, the Inflation Reduction Act (IRA) is a dense piece of legislation. At the same time, its impact on the energy sector can be summarized succinctly: clean energy economics just got a whole lot better.
The legislation achieves this through a spate of incentives. There are enhancements to the existing production tax credit (PTC) and investment tax credit (ITC), which are now available to new solar and energy storage facilities, respectively; before the IRA, the ITC for solar was being phased down to a terminal level of 10% for facilities beginning construction from 2024 onward, and solar plants that were placed in service after 2006 were eligible for the PTC. Starting in 2025, there are new versions of the PTC and ITC available to all zero-emissions technologies, with phase-outs linked to aggressive emissions reduction targets. The phase-out begins in either 2032 or the year when the U.S. electricity sector emissions are 75% below 2022 levels—whichever is later. And then there are entirely new statutes, including an incentive for existing nuclear plants, which varies based on plants’ average revenues, and hydrogen, which varies inversely with carbon intensity.
We analyzed the cost impacts of the IRA by computing the levelized cost of energy (LCOE)—the average cost of electricity generation over the lifetime of a facility—for various technologies in 2030 with and without the IRA under a range of assumptions (see Figure 1). All of the technologies we analyzed see double-digit percentage declines in their LCOEs relative to their pre-IRA counterparts, with 100% green hydrogen-fueled combined cycle (CCGT) facilities seeing the largest impact. With such LCOE reductions, clean energy projects will, all else equal, be more cost competitive across the U.S.
Mature and emerging technologies see distinct impacts
For mature technologies, such as wind and solar, these incentives have the potential to supercharge an already-rapid pace of development. In our analysis, we estimate that the solar and wind LCOEs in 2030 with the IRA will be lower than those without it by 20%-35% and 38%-49%, respectively. However, despite the economic incentives, the IRA may encounter other development challenges facing renewable energy projects.
Interconnection delays have increased in recent years and may increase further as interest in renewable development grows due to the IRA. Renewable capital and installation costs may begin to swell if investment in manufacturing, mining, and shipping capacity and the training and supply of labor lag demand for renewables. Project siting may become increasingly difficult if available land becomes scarce and “not in my backyard” sentiments intensify.
An acceleration of renewable development will also put downward pressure on energy prices, as renewables have the lowest marginal costs among generation sources. Furthermore, the extension of the PTC to solar facilities will boost the share of negative-price bids in solar-generating hours, thereby increasing the frequency of negative energy prices. These factors could accelerate retirements of fossil-fuel units. While this would help decarbonize the grid, there could be reliability issues if clean firm capacity does not scale up rapidly enough to provide a replacement.
Despite having higher costs than wind and solar facilities and no standalone tax credit, the development of grid-scale batteries has grown at a brisk pace in recent years. This growth has been driven by a combination of state mandates, such as California’s 2013 energy storage procurement target of 1,325 MW by 2020, and merchant economics, such as in ERCOT. By reducing the LCOE of grid-scale lithium-ion battery facilities by 18% to 20%, as per our analysis, the IRA could both spur merchant development and make state mandates less costly. Moreover, the IRA’s broad definition of energy storage for the ITC should help emerging alternatives to lithium-ion batteries come to market. Increasing the diversity of energy storage options could mitigate the possibility that supply chain bottlenecks will counter the benefits of the IRA’s incentives.
The IRA could make other emerging technologies, such as green hydrogen and carbon capture and sequestration (CCS) for power applications, economic for the first time. Green hydrogen has the potential to receive the greatest support, as electricity produced using it can receive three incentives simultaneously. First, renewable facilities used to produce green hydrogen will be eligible for either the PTC or ITC, reducing production costs. Second, being zero emissions, green hydrogen production facilities will qualify for the full value of the 45V hydrogen tax credit. Finally, electricity produced using green hydrogen will qualify for the PTC or ITC. The combined effect of these incentives in our analysis reduces the LCOE of green hydrogen-fueled CCGTs in 2030 by 52% to 67% relative to projects without incentives. (Note that all of the tax credits do not need to be captured by a single entity, as the benefits of credits earlier in the supply chain can be passed forward to later stages through reduced prices. However, for simplicity, in our calculations, we assumed a single entity that includes the CCGT and electrolyzer facilities.)
Our analysis also indicates that with $3/kg green hydrogen prices in 2030, projects capturing these incentives would be cost-competitive with new natural gas-powered CCGTs. With prices above $3/kg, however, green hydrogen-powered CCGTs will have higher LCOEs than new gas-powered CCGTs. The cost premium might not be prohibitive in regions with strong clean electricity mandates; firm capacity will be needed to meet the mandates, and additional development of unabated gas power generators is unlikely. In regions without such policies, green hydrogen facilities may still be viable despite the premium, as LSEs with ESG goals may be willing to pay it to ensure reliability.
The total value of the credits allocated to green hydrogen projects could be significant; a green hydrogen facility supplying a CCGT with parameters assumed for our analysis would receive around $5.8 billion from the 45V credit over 10 years. (This CCGT is a 600 MW facility running at a 50% average capacity factor. At lower capacity factors, the total payout will be proportionately lower.) These large incentives could make the total credits for green hydrogen facilities a substantial share of the total incentives paid out by the federal government, perhaps greater than the share for mature technologies. It remains to be seen whether there will be sufficient tax equity to capture credits of this magnitude.
The incentives for CCS for power applications are less supportive than those for green hydrogen. Part of the reason for this is that the IRA disallows the stacking of the 45Q CCS credit and other credits. In our analysis, 45Q reduces the LCOE for CCGTs with CCS by 20% to 23% in 2030, but these plants remain at a roughly $20/MWh premium to new CCGTs without CCS. LSEs with ESG goals or in states with strong clean electricity mandates may be willing to pay this premium for reliability and diversity of supply.
Unlike the PTC and ITC, 45Q and 45V have a firm expiry date; facilities must begin construction before 2033. If the credits are not renewed, the green hydrogen and CCS LCOEs for new facilities would revert to the levels without incentives (see the light blue bars in Figure 1). This could cause a deceleration in new green hydrogen and CCS development for power applications in the U.S. However, by stimulating investment, the credits will have helped reduce the costs for CCS and green hydrogen, thereby shifting them down their learning curves. Further learning could occur after credit expiration in industrial applications in the U.S. or power sector applications in Europe or Asia, which have higher natural gas prices than in the U.S. As costs continue to decline, U.S. power sector investment in these technologies could begin again in the 2040s.
Project economics can be further improved with credit bonuses
The credits in the IRA can be augmented with several bonuses (see Figure 2). There is a labor bonus, which multiplies the base credits by five for projects that pay prevailing wages and meet certain apprenticeship requirements. (This is the only bonus assumed for the calculations in Figure 1.) There is a sourcing bonus available to projects procuring 100% of steel and iron and certain percentages of manufactured content from domestic sources. There is a siting bonus available to projects constructed in “energy communities”—that is, regions with high unemployment that have been dependent on traditional energy projects. Finally, for the ITC, there are two “energy justice” bonuses provided to small projects—one 10% bonus for those sited in low-income areas or tribal regions and one 20% for projects that are part of low-income housing units or economic benefit projects; the energy justice bonuses are limited to 1.8 GW in each of 2023, 2024, and 2025 and require explicit allocations by the IRS.
Given that these credits are stackable, they provide additional improvements to project economics. The difficulties developers will have in meeting the requirements will vary. The labor bonus will likely be the easiest to meet, whereas the domestic content bonus will be the most difficult due to limited domestic manufacturing of renewable energy components; this may change over time, particularly due to incentives in the IRA for investment in domestic capacity to manufacture these components. The energy communities bonus is somewhere in the middle. Based on the criteria in the IRA, we created a map of energy communities (see Figure 3) and found that projects in large areas of the country, particularly in Appalachia and the West, will qualify for the bonus.
In a future paper, we plan on expanding this work using ICF’s proprietary greenfield siting tool for grid-scale renewable and storage projects. This tool integrates data on nodal pricing, policies, environmental conditions, interconnection queues, and permitting to assess project viability across the U.S. Incorporating the data underlying Figure 3 into this tool will provide an additional dimension in assessing the viability and attractiveness of potential project sites.
We will also evaluate the extent to which transmission constraints will offset the benefits from the IRA. For example, without reform to transmission cost allocation, some project owners may see their incentives absorbed by the costs of transmission expansion; the IRA only allows transmission costs for small generators to be covered by the ITC. However, various efforts, such as FERC’s interconnection and transmission notices of approved rulemaking, are underway that could help alleviate transmission constraints.
The power sector is poised for a rapid transformation
Incentives for clean energy in the U.S. are not new. The PTC and ITC have been present in some form for decades and have been renewed nearly a dozen times—often with bipartisan support. What is new is the scale of the support in the IRA, providing potentially trillions of dollars of federal support over the next few decades, and its timing, coming during a period of strong momentum for clean energy and decarbonization.
The IRA has the potential to increase that momentum by boosting clean energy project economics, including for projects with strong reliability attributes, such as storage, hydrogen, and CCS facilities. The IRA’s effects will differ across technology types; it has the potential to supercharge the rapid development of mature technologies seen in recent years and make some emerging technologies economically viable for the first time. The bonuses that can be layered onto the IRA tax credits will increase the magnitude of their impacts and may alter the regional profile of development.
There are uncertainties. The constraints imposed by interconnection delays, slow transmission build-out, supply chain bottlenecks, and labor availability will become more relevant going forward. At the same time, the IRA alleviates regulatory uncertainty for investors and developers by extending tax credits for decades.
That being said, this much is clear: the U.S. power sector is evolving rapidly. The IRA has strong potential to accelerate that transformation. Learn more about how your utility can navigate this transformation in our paper, "5 actions for utilites to prepare for IRA impacts."
Appendix: LCOE Assumptions
 All values are in nominal dollars.
 “Hydrogen” refers to 600 MW CCGTs fueled by 100% green hydrogen. “CCS” refers to 600 MW CCGTs with 90% carbon capture and geological storage. “Battery” refers to lithium-ion grid-scale facilities. “Wind” refers to onshore facilities. “Solar” refers to grid-scale facilities. “Gas” refers to 600 MW CCGTs.
 Tax credits: 30% ITC for batteries; the larger of the PTC and 30% ITC for solar and wind; 45Q for CCS; for hydrogen-fueled CCGTs, the PTC is applied to the output power and the 45V production credit is applied to the green hydrogen input. All credits include the labor requirement multiplier. The PTC, 45Q, and 45V are calculated in net present value terms with an 8% discount rate.
 Annual capital charge rates: 8% for wind, solar, green hydrogen-fueled CCGT, and CCS; 10% for gas and batteries
 Hydrogen prices range from $3-$5/kg. Gas prices range from $4-$6/MMBtu. These prices are not ICF’s official forecasts but rather illustrative of the range of potential prices. Higher or lower prices will increase or decrease the LCOEs proportionately.
 CCS storage and transportation costs are assumed to be $17.5/ton, and the facility is assumed to be 75 miles from the storage site.
 VOM, FOM, CAPEX, and heat rate data from NREL 2022 ATB.
 Capacity factors: 20%-30% for solar; 35%-45% for wind; 50% for gas, CCS, and hydrogen; 17% for batteries (4-hr duration, 1 cycle/day).
 The variation in the battery LCOE is based on the range of capital and fixed O&M costs from NREL 2022 ATB (i.e., conservative, moderate, and advanced).