In less than two years since the Inflation Reduction Act (IRA) was passed, USD 282 billion worth of low-carbon energy projects have been announced across 44 U.S. states.[1] U.S. utilities with ambitious plans to generate more low-carbon power can benefit from tailwinds created by IRA tax credits as well as an increase in energy demand from data centers.[2] On the other hand, those utilities with more carbon-intensive expansion plans may now face increasing compliance costs from new Environmental Protection Agency (EPA) rules on particulate emissions targeting existing coal and new natural-gas plants.[3] The forward-looking nature of these plans means that investors who only examine factors like past performance on carbon emissions may miss an opportunity to analyze a utilities’ exact ambitions for the future.
Utilities’ plans point to more installed capacity from low-carbon assets than gas by 2030
Our analysis of 39 U.S. power-generating utilities’ integrated resource plans (IRPs) found that the aggregate installed capacity of low-carbon energy sources would exceed natural gas by 2030.[4] This represents a sharp growth from 2023, when the sum of battery storage, hydropower, solar and wind capacity was 28% of total installed natural-gas capacity.
According to the utilities’ IRPs, by 2030:
- Wind and solar could grow to five and two-and-a-half times of 2023 capacity, respectively, buoyed by expectations of further cost declines, advances in commercial adoptability and availability of tax credits.
- Utility-scale battery storage and geothermal assets could see significantly more deployment from their nascent stage today at 10 and nine times 2023 levels, respectively.
- Natural gas, nuclear and hydropower are likely to stay close to current levels.
- Some coal (35% less than 2023 levels) and oil (20% less) are expected to be phased out from the grid.
Meeting energy demand from data centers with natural gas may result in new compliance costs
As new natural-gas plants fall under the EPA’s April 2024 emissions rules, utilities pursuing an “all of the above” energy transition approach involving gas face additional compliance costs.[5] The rule mandates a 90% capture of carbon emissions from gas plants if they will be relied upon as a main source, or baseload, for generation energy. Operating carbon-capture technology itself can reduce the net energy generation of a power plant by up to 30% (commonly referred to as “parasitic load”), and upfront costs to install the technology can start at around USD 750 million per power plant.[6] Although perceived reliability concerns around renewables may make natural gas seem like the most viable option to power data centers, expanding gas capacity may now come with a hefty price tag.[7]
Identifying IRA production vs. investment tax-credit opportunities
Utilities that already operate low-carbon-generation infrastructure or begin construction before 2025 stand to take advantage of the IRA’s production tax credit.[8] Driven by a robust operating fleet of hydropower and nuclear assets, utilities like Tennessee Valley Authority, Duke Energy Corp. and Southern Company may have the largest operations for generating production tax credits. Xcel Energy Inc., NextEra Energy Inc and Entergy also led other utilities by focusing more on wind, solar and nuclear, respectively.
Energy generation sources for 2023 may offer insights to IRA production-tax credit eligibility
Source: MSCI ESG Research and RMI Engage & Act, as of Feb. 12, 2024.
Utilities with strategies focused on renewables only (e.g., CenterPoint Energy Inc., American Electric Power Company Inc., Edison International) or developing both renewables and battery storage (e.g., Berkshire Hathaway Energy, Hawaiian Electric, IDACORP Inc.) are better positioned to take advantage of the IRA’s investment tax incentives supporting the construction and development of new low-carbon-generation projects.
Planned installed-capacity changes by 2030 indicate varying ambitions for low-carbon growth
Source: MSCI ESG Research and RMI Engage & Act, as of Feb. 12, 2024.
Historical and projected emissions levels can offer an initial assessment of a company’s exposure to energy-transition risks, but other helpful signals are available for utilities. In markets like the U.S. where there is no federal-level carbon price on the horizon and stranded-asset risks from EPA rules affect specific types of power plants, IRPs offer a direct view of which utilities are most exposed to additional compliance costs. Furthermore, current emissions levels offer no insight on how a power generator is positioned to capture upside opportunities from incentives like those the IRA offers. Investors that monitor which sources utilities expect to use to meet future power-generation needs may therefore capture a more complete picture of the financial risks and opportunities they face than simply tracking decarbonization rates.
The author would like to acknowledge Ryan Foelske and Jon Rea from RMI for their input on leveraging RMI’s Engage & Act platform.
This information is provided “as is” and does not constitute legal advice or any binding interpretation. Any approach to comply with legal, regulatory or policy initiatives should be discussed with your own legal counsel and/or the relevant competent authority, as needed.