This article is one of a series in our review of all integrated resource plans (IRPs) for electric utilities across the United States. We provide analysis of expected load, planned capacity, modeled generation and emissions, and comparison to targets and decarbonization scenarios to evaluate progress toward a zero-carbon energy future.

Every month, RMI’s Engage & Act team quantitatively reviews integrated resource plans (IRPs) to identify which US electric utilities are on track to achieve adequate progress on emissions reductions, and which utilities have plans that do not move quickly enough. IRPs do not provide a fully accurate prediction of the future, but we focus on them because they reflect the direction that utilities are currently striving for and a set of proposed actions to get there.

Updates in Q4 2024

In our previous review of utility IRPs in the third quarter of 2024, few major utilities made updates to their IRPs, so we did not observe drastic changes in aggregate projections. However, we did see a continuation of major qualitative trends among the many smaller utilities that updated their IRPs. As a group, these utilities increased their load projections by 3 percent, planned higher use of gas plants, and increased projected emissions by 3 percent compared to their previous IRPs.

In this most recent fourth quarter of 2024, utilities that updated their IRPs in aggregate made a small downward adjustment to projected load, but increased projected emissions by 8 percent. Higher projected emissions were a consequence of increases to planned gas plants (+12 GW by 2035) and reduction in planned wind and solar capacity (-20 GW by 2035).

For this review of Q4 2024, we also made an update to include historical data through 2023 following publication of input datasets from the Energy Information Administration (EIA). Total electricity demand and emissions for utilities in the United States with publicly available IRPs were 3 percent and 10 percent lower in 2023 than in 2022, respectively (while total United States generation and emissions reductions were 1 percent and 7 percent). This led to similar reductions in our future projections.

The progress made in 2023 was an important step toward climate alignment, but changes to utility IRPs in 2024 provide an even more important indication of the future direction of the sector. In the past year, cumulative projected emissions in IRPs from 2023 to 2035 increased by 5 percent, or 370 million metric tons (MMT). Several individual utilities have been able to meet recent increases in electricity demand and reliability requirements while simultaneously controlling costs for customers and reducing projected emissions. But more work needs to be done across the sector, and we still need many more utilities to increase their climate ambitions, become climate leaders, and capture the upsides of the growth opportunity that the clean energy transition presents for the US electricity sector.

The current state of IRPs

In our current snapshot of IRPs (Exhibit 1), we continue to see a gap between projected emissions, target emissions, and decarbonization pathways such as the International Energy Agency’s Net Zero Emissions by 2050 Scenario (IEA NZE).

Most decarbonization pathways, including the IEA NZE, find that the electricity sector needs to reach net-zero emissions by 2035. Unfortunately, utility company targets often aim for net-zero emissions by 2050, and often do not comprehensively cover emissions from both owned (Scope 1) and purchased (Scope 3) emissions. If all companies in our coverage meet their targets, they will only reduce their emissions 64 percent by 2035, compared to a 2005 baseline. We also find a gap between these targets and projected emissions based on IRPs, which as of the end of 2024 we project to be reduced by just 56 percent by 2035, compared to a 2005 baseline.

Load

As of the end of 2024, IRPs across the United States anticipate load to grow 20 percent by 2035 compared to 2021 levels (Exhibit 2). This is up from prior projections — 12 percent at the end of 2023, 9 percent in August 2022, and 7 percent in January 2021.

Load growth continues to be a critical concern for many utilities, as current load projections are much higher than they were a year ago. However, Q4 2024 is the first quarter (since our data coverage begins in 2021) in which we observe a decrease rather than increase in projected load in IRPs. This is partly due to a modest reduction in projections from companies who had previously expected large load increases from data centers, and otherwise due to a lack of major changes to expected demand from other companies.

Though they did not increase projections compared to previous plans, utilities that updated their IRPs in Q4 2024 do still anticipate increased electricity demand. This is driven primarily by demand from data centers and industrial manufacturing from just a couple of utilities, rather than a widespread common trend across all utilities. Emerging electricity demand from electric vehicles and space heating continue to be monitored and discussed in IRPs but are still generally a smaller source of load growth in the near term.

Capacity

Current planned capacity in IRPs across the United States (Exhibit 3) includes 260 GW of wind and solar additions, 84 GW of gas additions, and 74 GW of coal retirements between 2023 and 2035.

Updates to capacity plans in Q4 2024 continue the trend of the past several quarters of increasing planned gas additions. Current plans for 84 GW of additions by 2035 are 12 GW higher than was planned at the end of Q3 2024, and 32 GW higher than was planned at the end of 2023.

Possibly more concerning is that nearly every company that updated its IRP in Q4 2024 scaled down its planned wind and solar capacity additions, with a total reduction of 20 GW of planned wind and solar capacity by 2035.

With these recent changes, the difference between planned gas compared to wind and solar in 2035 is now 30 GW. This is a stark contrast to our Q2 2024 IRP review, in which planned wind and solar capacity in 2035 nearly exceeded planned gas capacity.

Utilities that reduced planned wind and solar capacity in Q4 2024 cited several reasons for their changes. These included interconnection difficulties, changing capacity accreditation rules and reserve margins in MISO and SPP, and strict reliability needs of data centers or other customers. However, numerous studies have also demonstrated that a cost-effective, reliable grid is ideally made up primarily of zero-carbon energy sources, with gas acting in a minor secondary role. There remains a large opportunity for utilities to invest more in clean energy for the benefit of their customers, investors, and the climate.

Emissions

Our latest projections (Exhibit 4) are that emissions planned in IRPs at the end of 2024 will be 56 percent lower than 2005 levels by 2035. This is a smaller reduction than we projected from IRPs at the end of 2023, when emissions planned in IRPs showed a 60 percent reduction, and the same as the end of Q3 2024 when the figure was also 56 percent.

Projected emissions are now lower than they were at the beginning of 2021 because of increased overall plans to build zero-carbon capacity. However, projected emissions are higher now than at the end of 2023 because of delays or reductions to planned zero-carbon capacity additions and increased use of gas.

Cumulative metrics

When considering climate alignment of the US electricity sector, or individual utilities, the key metric that RMI’s Engage & Act platform focuses on is cumulative emissions through 2035. Cumulative emissions, or the total amount of greenhouse gases put into the atmosphere, is what directly influences climate change, so this metric gives us clear insight into whether we are on track to meet climate goals. We also find value in metrics of cumulative projected load, to know whether the task of reducing emissions is becoming easier or more difficult for utilities, and cumulative projected emissions intensity, to know if consumers are increasing or decreasing emissions associated with their electricity consumption.

Exhibit 5 shows that across all IRPs in the United States, cumulative projected emissions are 5 percent higher, cumulative projected load is 3 percent higher, and cumulative projected emissions intensity is 2 percent higher now at the end of 2024 compared to the end of 2023.

Utilities that were more successful at limiting or reducing future emissions often did so by taking full advantage of incentives from the Inflation Reduction Act and considering a complete set of options for providing reliable electricity to customers, including demand-side management and energy storage as a complement to wind and solar power.

Exhibit 6 provides an additional view of the direction that IRPs are going, by considering the percent change in cumulative projected load and emissions among the set of companies that did update their IRPs each quarter. These utilities still expect load growth in their service territories, but in contrast to previous quarterly updates, they did not increase these expectations in Q4 2024. However, they did increase projected emissions (and emissions intensity) by 8 percent, a result of updates to IRPs that reduced planned wind and solar capacity and increased planned gas capacity and generation.

Achieving a climate-aligned future

Our review of IRP updates in Q4 2024 revealed individual utility success stories, but also concerning recent trends in how utilities are navigating this critical moment of the clean energy transition. Even without load growth, many utilities reduced their near-term plans to build wind and solar capacity, due to interconnection difficulties, changing capacity accreditation rules in MISO and SPP, and strict reliability needs for new electricity demand. Because of these both real and perceived barriers to zero-carbon energy deployment, we observed an increase in planned gas capacity and generation, resulting in an 8 percent increase in cumulated projected emissions from 2023 through 2035.

We will continue to monitor the trends that emerge as IRPs are updated in 2025. Regional variations and company-specific choices will continue to play an important role in progress of the sector, as will broader economy-wide policy, regulation, and market trends. RMI’s docket opportunity tracker provides insight into key upcoming proceedings where important planning decisions will be made.

With this view to the future, we still see a significant opportunity for more utilities to become leaders in the clean energy transition. By fully taking advantage of IRA incentives, utilizing novel approaches such as clean repowering, and planning more comprehensively, utilities can reduce emissions, provide reliable and low-cost electricity to customers, and generate increasing earnings for investors. 

RMI’s Engage & Act Platform: Data and Insights for Real Climate Impact

RMI’s Engage & Act Platform provides data and insights for real climate impact. To learn how you can access and use this targeted resource to uncover recent trends and clean energy growth opportunities — and accelerate the pace of electric utility carbon emissions reductions — please visit the Engage & Act website.

Methodology

Historical data in this article comes from the RMI Utility Transition Hub. Projected capacity and total generation (load) is based on data collected manually from IRPs by EQ Research, combined with historical data. Generation by technology is calculated with assumed continuation of trends in capacity factor for each company and technology, and converted to emissions by using average US emissions factors by technology.