What’s the State of Utility Planning Halfway through 2024?
Our most recent review of utility planning finds significant load growth, increases to planned gas capacity, and higher projected emissions for the US electricity sector.
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 growth, planned capacity, modeled generation and emissions, and comparison to decarbonization scenarios to evaluate progress toward a zero-carbon energy future.
Every month, our 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. Where we find an IRP that does not include significant ambition to transition to a zero-carbon future, we see an opportunity for investors and other stakeholders to engage with a utility and find profitable ways to reduce emissions while minimizing customer costs and maintaining reliability.
When we published our review of IRPs in December 2023, we found that utilities were increasing their expectations of electricity load growth, planning to meet much of this new load with wind and solar resources, and had reduced their projected emissions despite more power demand. We attributed a significant portion of this progress to the Inflation Reduction Act (IRA), which provided the incentives necessary to adjust IRPs toward a climate-aligned future.
Through the first half of 2024, we now find that some trends have continued, and some have changed. We’ve continued to see increases in projected electricity demand. We still see most capacity additions coming from wind and solar resources. However, a new trend is that many utilities have recently updated their IRPs to include additional gas capacity. Our modeling then shows that higher load, and higher use of gas plants, have increased projected emissions to levels higher than we projected before the passage of the IRA.
A climate-aligned future requires significant electrification and an increased role of the electricity sector, so much of the load growth utilities are now including in IRPs is an indication of progress. But to meet climate goals, the electricity sector also needs to reduce emissions from today’s levels by 70 percent by 2030. More progress still needs to be made to meet both of these goals simultaneously, and there remains an exciting opportunity to deploy staggering amounts of capital in the transition toward the zero-carbon electricity system of the future.
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, their emissions will only decrease 62 percent by 2035, compared to a 2005 baseline. Then, we also find a gap between these targets and projected emissions based on their IRPs, which as of the end of June 2024, we project to be 50 percent reduced by 2035, compared to a 2005 baseline.
Exhibit 1: Projected emissions from IRPs, targets, and the IEA NZE scenario
Load
As of the end of June 2024, IRPs across the nation in aggregate anticipate load to grow 23.9 percent by 2035 compared to 2021 levels (Exhibit 2). This is up from prior projections — 15.0 percent in December 2023, 10.3 percent in August 2022, and 8.2 percent in January 2021.
The sources of this new additional load vary by region, but electrification of buildings and electric vehicles, expansion of domestic manufacturing, and local economic growth are significant contributing factors. Recent headline-grabbing growth in data centers to power artificial intelligence is also a major source of anticipated near-term load in some regions, especially the Southeast and upper Midwest.
This trend of significantly increasing load projections, which has accelerated over the past several months, is a shift from the past decade of generally flat electricity demand in the United States. In this time of transition, utilities need to put additional effort into load forecasting -- including the timeline, flexibility, operational characteristics, and certainty associated with new loads. Considering data centers, we have observed cases of "load shopping", in which companies ask multiple utilities to meet their electricity demand before deciding the location for their operations. Regardless, once we have enough certainty in load expectations, we expect to continue to see this shift toward an increasing role of the electricity sector in meeting US energy needs over the next decade and beyond.
Exhibit 2: Projected electricity demand (load) from IRPs
Capacity
Current planned capacity from IRPs across the United States (Exhibit 3) includes 273 GW of wind and solar additions, 70 GW of gas additions, and 69 GW of coal retirements between 2023 and 2035. This compares to the 250 GW of wind and solar additions, 50 GW of gas additions, and 72 GW of coal retirements over the same time period that we previously saw in December.
Utility responses to increased load and the passage of the IRA included significant additions of wind and solar capacity — a continuation of the signal that these will be the leading electricity generation technologies of the future. However, another important trend that began last year and continues now is a near-term delay in installing wind and solar due to issues such as supply chain disruptions, inflation, and long grid interconnection queues. These are important issues to overcome, through clean repowering or other innovative solutions, as climate success depends on immediate action and progress.
Utilities have also responded to increased near-term load projections by proposing more gas capacity in their IRPs, often citing reliability or urgency as justification for these plants. However, in RMI’s own analysis, as well as our review of scenario modeling by other groups, we find that a clean, reliable grid can be built without gas additions, and with gas plants being used at very low capacity factors. Gas plants built today, but rarely used in the future, create stranded asset risk, and are likely a much more expensive option than the alternatives of wind, solar, storage, energy efficiency, and demand-side resources. Zero-carbon resources typically have higher capital but lower operating costs, which also makes them particularly attractive to investors looking to maximize earnings on capital investments.
Exhibit 3: Planned capacity in IRPs
Emissions
Our latest projections (Exhibit 4) show emissions planned in IRPs will be 50 percent lower than 2005 levels by 2035. In our December update, we projected emissions would be down 51 percent over the same period.
As explained in the Load and Capacity sections of this article, IRPs have recently increased expectations for load, and are planning to build and use more gas than in previous months. Here, we see this reaction results in increased emissions.
Higher emissions projections are a concerning trend, making this a critical moment for the US electricity sector to reconsider its future path and how it can best transition to a zero-carbon system. But even if the sector in aggregate appears to be searching for solutions, not all utilities are following the same trend. Investors and other stakeholders should be particularly interested in utilities that have been able to update IRPs with lower projected emissions through significant investment in zero-carbon generation from wind and solar.
Exhibit 4: Projected emissions from IRPs
Cumulative metrics
When considering climate alignment of the US electricity sector, or individual utilities, the key metric that we focus 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, 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 now 3.7 percent higher, cumulative projected load is now 4.3 percent higher, and cumulative projected emissions intensity is now 0.5 percent higher than it was in December 2023.
Because of the link between load and emissions, not all new load and associated emissions necessarily indicate a lack of progress. Some new load comes from beneficial electrification, which means avoided fossil fuel use and reduced emissions in other sectors. Still, increasing emissions and a lack of recent progress in reducing emissions intensity demonstrate that current IRPs are not on track for climate success. With engagement from investors and improved planning processes, updates to IRPs in the near future could include higher levels of investment in zero-carbon generation resources and reduced emissions across the entire planning horizon.
Exhibit 5. Cumulative projected emissions, load, and emissions intensity
Achieving a climate-aligned future
All told, our most recent review of IRPs shows many positive signs for the energy transition, which requires that we double our use of electricity while significantly reducing emissions associated with that electricity generation. Load growth spurred by the IRA in everything from accelerated adoption of electric vehicles to increases in domestic clean energy manufacturing, and the broader energy transition, represent the biggest opportunity for investor-owned utilities in our lifetimes. Many utilities have updated their IRPs to capture this opportunity through investment in zero-carbon resources such as wind and solar; many others still have work to do to leverage solutions available to them.
By fully taking advantage of IRA incentives, utilizing novel approaches such as Clean Repowering, and planning more comprehensively, utilities can deliver on their emissions targets and align with scenarios such as IEA NZE, provide reliable and low-cost electricity to customers, and generate increasing earnings for investors. To track progress of utilities taking advantage of these opportunities, RMI’s Engage & Act platform can provide the insights necessary to review and engage with utilities to reach climate alignment at the speed necessary to address the climate crisis.
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.