The State of Utility Planning, 2025 Q2

Utility resource plans in Q2 2025 continued to increase expectations for electricity demand from a variety of sources, focusing on expanding gas power plant capacity to meet that demand.

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. 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 Q2 2025

In the second quarter of 2025, utilities that updated their IRPs increased projected load through 2035 by 2.0 percent and emissions by 4.5 percent.

Changing policy, regulation, and market rules, as well as interconnection queues, limitations to capital deployment, and claims of reliability concerns create a difficult environment for utilities to meet load growth with wind and solar generation. Instead, utilities continue to increase plans to build new gas capacity, and in some cases, also delay retirement of existing fossil capacity.

This quarter’s updates represent a reminder that the sector is not completely homogenous. Regional differences, and even intraregional differences, were apparent and reflect the importance of company-specific evaluation to enrich the sector-wide story. In subsequent sections, we share detailed analysis of recent changes, their underlying causes, and potential directions of opportunity for improvement.

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 Q2 2025 we project to be reduced by just 53 percent by 2035, compared to a 2005 baseline.

Exhibit 1

Load

As of the end of Q2 2025, IRPs across the United States anticipate load to grow 24 percent by 2035 compared to 2023 levels (Exhibit 2). This is up from prior projections — 12 percent at the end of 2023, 8 percent in August 2022, and 6 percent in January 2021.

Load growth continues to be driven in the short term primarily by industrial loads such as data centers, but also comes from increasing adoption of electric vehicles and beneficial electrification. Load changes in Q2 2025 varied widely by utility, ranging from Indiana-Michigan Power Co.’s projection that load will more than double from 2023 to 2030 with data centers becoming 60 percent of total load, to PacifiCorp’s 12.3 percent reduction in projected peak load. PacificCorp’s reduction is due to removing large loads from its forecast because these customers are now expected to provide and pay for their necessary resources and transmission outside of the traditional planning process.

Exhibit 2

Capacity

Current planned capacity in IRPs across the United States (Exhibit 3) includes 258 GW of wind and solar additions, 102 GW of gas additions, and 75 GW of coal retirements between 2023 and 2035.

This reflects 4 GW of additional wind and solar capacity, 52 GW of additional gas capacity, and 3 GW of additional coal retirements since the end of 2023.

With these recent changes, utility resource plans now include 52 GW more gas capacity than wind and solar capacity in 2035. 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.

Capacity needs continue to increase because of load growth, and utilities that updated IRPs in Q2 2025 also cited higher reserve margins required by the Southwest Power Pool as well as a desire to keep resources online to improve reliability during extreme weather events as reasons for delayed retirements and more fossil additions. It is clear that in aggregate, utilities are focusing on additional gas capacity to meet these needs.

Exhibit 3

Emissions

Our latest projections (Exhibit 4) are that emissions planned in IRPs at the end of Q2 2025 will be 53 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 end of 2024 when the figure was 56 percent.

Projected emissions by 2035 remain 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 and 2024 because of increased electricity demand, insufficient zero-carbon capacity additions (in many cases, delays or reductions to plans) to meet all of this demand, and increased use of gas generation to fill the remaining gap.

Exhibit 4

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 from 2023 to 2035 are 4.5 percent higher, cumulative projected load is 2.0 percent higher, and cumulative projected emissions intensity is 2.4 percent higher now at the end of Q2 2025 compared to a year ago at the end of Q2 2024.

Exhibit 5

Exhibit 6 provides an additional view of the direction that IRPs are going, by considering percent change in cumulative projected load and emissions among the set of companies that did update their IRPs each quarter. Utilities that updated IRPs in Q2 2025 increased load by 2.4 percent, emissions by 4.1 percent, and emissions intensity by 1.6 percent.

In our history of tracking IRPs, load projections have never decreased in a quarter, and Q2 2025 makes eight consecutive quarters of at least 2.4 percent load growth among utilities with IRP updates. While emissions decreased in the early 2020s, Q2 2025 also marks six consecutive quarters of at least 2.7 percent increase to projected cumulative emissions among companies with IRP updates.

Exhibit 6

Achieving a climate-aligned future

Our review of IRP updates in Q2 2025 continued many of the themes we’ve discussed in previous quarterly updates. Similar to last quarter, we observed regional and intraregional differences in load growth, particularly from data centers. Utilities need to expand capacity to meet new load, with additional pressures from increasing reserve margin requirements in certain regions. While delayed retirements and more gas additions seem to be the default choice in most plans, there are a range of fast, affordable, flexible alternatives that can meet this moment, especially considering the gas turbine supply crunch.

Emerging topics this quarter included recurring utility comments on gas fuel price volatility risk, as well as impacts of climate change on utility planning: wildfire mitigation creating a limit on investment, variable hydroelectric resources, and keeping plants online due to increasingly frequent extreme weather events. We are also tracking advancements in how utilities effectively connect large loads: Georgia has approved a tariff framework and other states such as Missouri are at various stages of implementation. These new tariffs will continue to develop, making the process of connecting new large load customers more streamlined and limiting impact on existing customers.

It is important to note that all IRPs in our dataset were completed under currently available policies. Recent federal policy changes, including tax credit and domestic content policy, are likely to affect implementation of these plans and may create new barriers to zero-carbon capacity additions.

While the United States electricity sector faces many challenges, progress remains possible. Utilities should continue prioritizing cost to customers, earnings for investors, and reliable electricity service, while simultaneously increasing their focus on the growing risk that the sector is not on track to meet climate goals. Utilities need to fully take advantage of relevant incentives, utilize novel approaches — such as Power Couples — to meet large loads, take advantage of opportunities for clean repowering, and improve their forecasting and modeling methods to plan more comprehensively.

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.