The State of Utility Planning, 2025 Q4

US electric utilities that updated their IRPs in 2025 Q4 cut planned wind and solar capacity additions by 2035 in half (23 GW), but made progress implementing emerging solutions for fast, affordable, flexible growth.

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 2025 Q4

In the final quarter of 2025, the 15 utilities that updated their IRPs (representing 10 percent of total US electricity generation in 2024) cut planned wind and solar capacity additions by 2035 in half, to 23 GW, a drastic reduction from the previously planned 46 GW.

This reduction occurred while utilities made only minor adjustments to projected load through 2035 — an increase of 0.6 percent. As a result, the net impact in projections for companies that updated their IRPs in 2025 Q4 is an increase in cumulative emissions through 2035 of 9.4 percent.

Changing resource adequacy rules in the Midcontinent Independent System Operator (MISO) and Southwest Power Pool (SPP) regions, phase out of federal tax credits for wind and solar, anticipated repeal of greenhouse gas regulation by the Environmental Protection Agency (EPA), and changes to state policy were all factors influencing this reduction in planned wind and solar build discussed by utilities in their IRPs.

This quarterly IRP update coincides with an annual update to include 2024 historical data. In 2024, US regulated electricity sector emissions slightly increased. Consequently, the annual data update also increased projected emissions compared to previous reviews in 2025 Q3 and Q2, widening the gap between utility plans and the science-based emissions pathways necessary to avoid the worst impacts of climate change.

In this article, we dive into current utility resource plans, how they changed in the past quarter and year, and solutions utilities are implementing to make progress.

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. However, if all companies in our coverage meet their company targets, they are currently projected to reduce emissions by 63 percent by 2035, compared to a 2005 baseline. To close this gap, utilities will need to more comprehensively cover emissions from both owned (Scope 1) and purchased (Scope 3) generation. There is also a gap between both decarbonization and corporate targets and projected emissions based on IRPs representing utilities’ planned investments. As of 2025 Q4, IRPs project emissions to be reduced by just 45 percent by 2035, compared to a 2005 baseline.

Exhibit 1

Load

As of the end of 2025 Q4, IRPs across the United States anticipate load will grow 25 percent by 2035 compared to 2023 levels (Exhibit 2). This is a 0.1 percent increase compared to the end of Q3.

Expectations of electricity demand grew drastically in 2024, as utilities added new load from data centers, manufacturing, electric vehicles, and electrification of residential and commercial end uses to their projections. This slowed in 2025, in part because some of this newly anticipated load was already established, but also because of regulatory changes and revisions to load projection methodologies. Some utilities took speculative new large load projections out of their base case projections, and others updated methodologies closer to best practices for large load forecasting.

Exhibit 2

Capacity

Current planned capacity in IRPs across the United States (Exhibit 3) includes 226 GW of wind and solar additions, 100 GW of gas additions, and 73 GW of coal retirements from the end of 2024 to the end of 2035.

This reflects 18 GW less wind and solar capacity, 26 GW of additional gas capacity, and 5 GW more coal retirements compared to utility plans a year ago at the end of 2024.

Changing resource adequacy rules by major grid operators have had a significant impact on planned wind and solar capacity. For example, Centerpoint Energy Indiana South and AES Indiana each cited MISO resource adequacy and capacity accreditation rules as major factors in their planning, and took 1.8 and 3.1 GW of solar and wind capacity additions by 2035 out of their resource plans, respectively. Removal of federal tax incentives, clean energy legislation in North Carolina, and the EPA’s proposed repeal of greenhouse gas emission regulation, are all also significant factors that have shifted utility plans away from wind and solar and toward coal and gas.

Plans to build batteries have also held or increased in most cases, as batteries retain future tax incentives under recent federal policy. In aggregate, our projections include 68 GW of planned battery capacity additions from the end of 2024 to the end of 2035, a 7 GW increase from the end of 2024.

Exhibit 3

Emissions

Our latest projections (Exhibit 4) from IRPs at the end of 2025 are that carbon dioxide emissions will be 45 percent lower than 2005 levels by 2035. This is higher than we projected a year ago at 47 percent, and two years ago at 52 percent.

Compared to today, the future grid of 2035 will have lower emissions because of planned coal retirements and wind and solar capacity additions. However, major changes to utility plans of increased load in 2024, decreases to planned wind and solar capacity in 2025, and increases to planned gas capacity, have led our current projected emissions to be higher than they have been since the end of 2021.

Exhibit 4

Cumulative metrics

When considering climate alignment of the US electricity sector, or individual utilities, RMI’s Engage & Act platform’s key metric is cumulative emissions through 2035. RMI also finds 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, projected load has increased consistently since early 2021 but has leveled off in recent months. Projected emissions fell from early 2021 to mid-2023 but have increased significantly since then. Projected emissions intensity has also increased in recent months.

Cumulative projected emissions from 2023 to 2035 are 3.2 percent higher, cumulative projected load is 1.1 percent higher, and cumulative projected emissions intensity is 2.1 percent higher now at the end of 2025 than they were a year ago at the end of 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 2025 Q4 increased load by 0.6 percent, emissions by 9.4 percent, and emissions intensity by 8.8 percent.

Exhibit 6

Solutions that can scale

Recent utility plans have taken several steps to improve processes and methods to solve for utility priorities of cost, reliability, and climate impact with fast, affordable, flexible solutions.

Load forecasting, particularly for new large loads, is improving in many cases. Most utilities with updated IRPs in 2025 Q4 included scenario-based load forecasting, including specific plans on how they will meet energy and reliability needs of large loads in cases where these loads are uncertain.

Clean repowering opportunities appeared in multiple IRPs this 2025 Q4. Centerpoint Energy Indiana South plans to use interconnection rights at the site of a retiring coal unit to fast-track a battery storage addition, and Duke Energy Carolinas/Progress is studying use of surplus interconnection to add storage capacity. These examples add to utilities from 2025 Q3 of Santee Cooper and Cleco Power who each also propose re-use of retired fossil plant sites for solar and/or batteries.

Virtual power plants (VPPs) are also an emerging solution: Dominion Energy Virginia is preparing to pilot a VPP program up to 450 MW, and Centerpoint Energy Indiana South’s IRP includes a contract for a demand response aggregation program.

However, these solutions need to scale and additional revisions to planning processes are needed to enable progress toward a reliable, affordable, low-carbon electric grid. Modern methods for modeling grid reliability, rather than focusing on individual power plant dispatchability, are necessary to enable wind and solar to receive appropriate credit for their grid services. Building more of the lowest-cost electricity generation technologies will help keep electricity affordable, as will using updated costs and constraints of available technologies.

Improved planning processes and methods, with supporting policy and regulation, are critical in this moment for electric utilities to more effectively transition toward a low-cost, zero-carbon future.

 

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, with RMI corrections, combined with historical data. Generation by technology is calculated with assumed continuation of trends in capacity factor for each company and technology, and is converted to emissions using utility-specific emissions factors by technology.