A problematic consensus

Over the past two years, a consensus has emerged that US electricity prices will rise, primarily driven by new data center development. Bloomberg, EESI, Harvard Law Today, and many more have amplified this narrative.

This consensus has two problems. First, it washes away important nuances about our electricity markets, by (among other things) failing to recognize regional variability and conflating wholesale prices and retail prices. Second, and more importantly, there’s a reasonable chance it’s wrong.

In this article, we explore the factors driving electricity prices, the mechanisms by which they could fall, startups that could help bend prices down, and the business models positioned to win if they do. 

Key takeaways 

• The widely-held consensus that US electricity prices will rise is an oversimplification, as pricing is determined by a complex interaction of regional factors, wholesale costs, and policy decisions, not just rising demand.

• Falling wholesale prices—which account for up to two-thirds of a bill in restructured markets—can be achieved through stable or declining natural gas prices, continued cost declines and deployments of renewables and storage, and expansion of transmission capacity.

• Transmission & Distribution (T&D) costs can be materially driven down by increasing grid utilization as well as lowering construction and operating and maintenance (O&M) costs.

• Should prices fall, the two sectors most positioned to win are Industrial Electrification and Fleet Electrification, as lower electricity costs directly reduce costs and accelerate adoption.

If you’re a seed-stage founder developing digital solutions that help us get more out of our electric grid, or if you’ve been looking at electricity price trends, we’d love to hear from you!

How electricity is priced

US electricity markets are divided into two structures, and that split determines how prices are set in different parts of the country:

• Vertically Integrated: a single utility owns and operates the full electricity supply chain (generation, transmission, and distribution). If it’s an investor-owned utility (IOU) a Public Utility Commission (PUC) sets rates to guarantee cost recovery plus a specified rate of return. Examples of these include Xcel-Colorado and Florida Power and Light.  

• Restructured (also known as “deregulated”): generation (and sometimes retail delivery) is open to competition, while transmission and distribution remain under the control of a monopoly. Prices reflect competitive bidding tied to supply and demand.

About two-thirds of US electric consumers live in an area with a restructured wholesale electric market, and 19 locations (18 states and Washington D.C.) offer retail choice to electricity customers.

Every electricity market has its own nuance which we won’t cover here, but these definitions provide a framework for analyzing how prices move.

In restructured markets, two cost buckets drive up to 80-90% of the bill:

• Wholesale: costs associated with the generation of the electricity, often accounting for around 60% of a customer’s bill. 

• Transmission & Distribution (T&D): costs associated with delivering the electricity to customers, often accounting for around 30% of a customer’s bill.

The final 10-20% covers taxes, energy efficiency programs, retailer margin (restructured markets only), and equity and access programs (in some markets). 

Source: Electric Choice breakdown of a $150 bill in Texas for customer using 1,000 kWh

What drives electricity prices? Five factors that will determine the next five years

While many factors influence wholesale and T&D prices, we’ve prioritized the five factors that are most likely to drive changes over the next five years: 

Wholesale prices

1. Fuel Costs: natural gas generators often set the marginal price at auction, so changes in gas prices flow directly into wholesale electricity prices.

2. Supply & Demand Balance: as in any commodity market, prices rise when demand exceeds supply. In “energy only” restructured markets like ERCOT, prices are mostly determined by day-ahead and real-time auctions to ensure supply meets demand. In restructured markets with a capacity component like PJM, an additional set of auctions is used to match planned supply with projected future peak demand.   

3. Grid Congestion: when transmission constraints prevent electrons from reaching end users, nodal prices diverge; with lower prices near excess supply, and higher prices near unmet demand. For example, the map below from GridStatus.io shows a summer afternoon in which excess supply in northwest Texas couldn’t reach demand in the southeast part of the state. This led to negative nodal prices in parts of west Texas even as areas near Houston were seeing prices around $100/MWh.

Screenshot from Gridstatus.io

Transmission & Distribution Prices

4. T&D Utilization: Fundamentally, the transmission and distribution costs customers face are a function of the costs to build and maintain the grid divided by the total number of electrons that pass over the grid. While national-level numbers are difficult to find, researchers at Stanford University found that the Western Electricity Coordinating Council (WECC) territory only used up to 52% of the capacity of its transmission lines even on peak days. They believe they’ll find similar utilization in the eastern interconnect. The grid won’t ever reach 100% utilization because the grid must be built for the most demand-intensive days. However, higher utilization during non-peak times spreads fixed T&D costs across more kWh, pulling per-kWh prices down. 

5. Building and Maintaining T&D Infrastructure: grid upgrades, weather hardening, and wildfire mitigation have become major fixed cost drivers that pass through to customers. Additionally, capital investments must be made to serve new loads and connect new generation with areas of demand. Reducing these costs relative to the total number of kWh’s delivered on the system would put downward pressure on per kWh prices. 

How have prices changed lately?

Conversations about affordability often lump electricity prices in with the rising cost of other basic necessities like housing, groceries, and healthcare. This claim is largely unfounded for electricity prices. There are a few notable exceptions (California, Maine, and Hawaii, for example), but over the last ten years most states have had flat or falling real retail electricity prices. Our analysis of EIA data shows that electricity customers in 42 states had lower electricity costs in 2024 than they did in 2015 after adjusting for inflation. Toggle the start and end dates on the map to explore how prices have changed since 2000.

*Note: This map reflects the “All Sector” prices, a weighted average across all tariffs and customer segments. Residential rates will typically be a few cents higher than what is shown here, while commercial and industrial rates may be slightly lower. 

How electricity prices could fall

With the fundamentals covered, we can now explore the falling electricity prices counternarrative. None of these scenarios are certain, but each represents a mechanism by which customer bills could realistically come down over the next five years. We will, again, focus on restructured markets, though most dynamics apply to vertically integrated markets as well. 

Wholesale prices

Since the wholesale price of electricity accounts for two-thirds of the final bill in a restructured market, a meaningful wholesale decline can pull down the total electric bills. 

Stable or falling natural gas prices

Stable or falling natural gas prices would lead to a decline in wholesale electricity prices in most regions, given how often the fuel remains the marginal producer. 

Because the US is a net exporter of natural gas and because there are infrastructure constraints that cap how much gas the US is able to export, its market currently is insulated from global supply shocks such as those that have impacted much of Asia and Europe in the aftermath of recent geopolitical conflict. However, domestic prices can be volatile as the market balances variations in production against domestic consumption (driven primarily by weather, industrial activity, and natural gas power generation) and rapidly increasing export capacity. 

ICF research projects domestic supply of natural gas to increase by 24% by 2030 compared to 2024 levels and total demand (including exports) to increase by 25% over the same period. With supply and demand so closely matched, multiple factors could tip the market into oversupply and depress prices including: large loads failing to come online, a spell of abnormally warm winters, depressed industrial demand, an unexpected increase in domestic production, or a major export hub being delayed. 

Continued expansion of renewable generation and energy storage

Continued renewable penetration, combined with energy storage, can pull average wholesale prices down while also reducing total system natural gas demand. 

Solar and wind remain the cheapest form of energy on a per kWh basis, and in many cases solar remains the fastest generation source to deploy. At the same time, lithium-ion battery storage has proliferated due to cost declines. Production costs have dropped 85% over the past decade, with an estimated 43.5%-52.5% of additional reduction possible by 2030. As additional energy storage and load flexibility helps match intermittent supply with demands, adding low marginal cost renewable capacity shifts the supply curve outward over more hours, lowering the clearing price and reducing gas demand in parallel.

However, adding capacity at scale is challenging. A number of innovative startups are helping to accelerate deployment. For example, Powerhouse Ventures portfolio company Terabase speeds up construction and reduces costs for massive utility-scale solar deployments. Several companies are working to help developers, ISO/RTOs, and utilities navigate the interconnection queue, which at the end of 2024, reached nearly 2,300 GW of total requested capacity. These include Powerhouse Ventures portfolio company Pearl Street Technologies (acquired by Enverus), Nira, GridVAR, and Piq Energy. Additionally, platforms like Blumen, Prevolt, and PermitPal help developers navigate permitting, regulation, and local community sentiment.  

Load growth vs supply

Load growth is difficult to project, particularly as it relates to AI-driven data center buildouts. It’s unclear how many projects in the queue will be built or on what timeline, and Heatmap recently reported a record number of project cancellations in the face of community opposition. At the same time, some forecasters like Semianalysis project that over 50% of new data centers could be powered by behind-the-meter generation, primarily powered by natural gas. This would further muddy load growth’s impact on electricity prices, as these behind-the-meter data centers wouldn’t directly draw from the grid but would drive up natural gas consumption, which as we noted above is a key driver of electricity prices. A recession or other macroeconomic shock could also soften demand outside of datacenters.

Policy decisions matter immensely if supply is built with the expectation of load that never materializes. In restructured markets, oversupply should lead to lower wholesale prices, with generators who hold merchant risk left as the losers. In regulated markets where generation can earn a guaranteed rate of return, end-customers would traditionally be left paying a higher per kWh rate. To combat this, utilities like AEP Ohio are requiring large data center customers to pay for 85% of subscribed energy, regardless of usage. 

Pragmatic transmission network expansion

Well designed expansion of the transmission network can relieve grid congestion, which in turn reduces generation curtailment and makes it easier and less expensive to site new generation. 

Building out new transmission will be one component of an expanded transmission network. However, new transmission projects are slow and expensive. Reconductoring is more immediate and potentially more cost effective. A UC Berkeley & GridLab study found that upgrading existing transmission lines within existing right-of-way could double transmission capacity at substantially lower cost. T&D charges would rise, but total bills would fall as customers gain access to cheaper generation. Innovative startups like TS Conductor and AssetCool offer compelling pathways to reconductor transmission lines at scale.   

How these factors could combine to drive change

Powerhouse Ventures portfolio company Distill Energy simulates how the combination of factors like commodity prices, generation capacity, transmission, and demand propagate through the grid's physical constraints to drive nodal wholesale prices. Because these factors are intertwined and uncertain, they lead to a distribution of potential outcomes. 

The Distill Energy team recently ran over 6,000 future scenarios of the ERCOT grid and compared the average hub wholesale prices to today’s. While the scenarios weren’t weighted based on their likelihood and therefore aren’t intended as a forecast of where prices are most likely to land, it does provide insights into the combination of events that would drive moderate or extreme changes in wholesale electricity prices. For example, scenarios where new load is sufficiently flexible or scenarios where renewable development is complemented by new transmission and storage see significantly lower prices, whereas scenarios with higher natural gas prices and limited new generation lead to large or even extreme price increases. 

You can read the full results of their analysis in their blog The Future Isn’t One Price, It’s a Distribution. 

T&D prices

T&D is a smaller share of the bill than wholesale prices, but nonetheless can materially impact electricity costs for end users. There are three primary levers that can bring down T&D prices: improved utilization, more cost-effective O&M, and lower new construction costs. 

Increased T&D utilization

As noted above, there’s ample room to improve T&D utilization. Improving this utilization can meaningfully lower electricity prices. A recent Brattle analysis showed that status quo load growth will likely lead to a 1.4% average increase in electricity rates, but implementing utilization measures in conjunction with the same load growth would drive rates down by 3.4%. 

Demand response and load flexibility is one underappreciated pathway for improving utilization. Typically, load flexibility has been primarily used as an alternative to new generation. However, it can also be leveraged to improve grid utilization by reducing the infrastructure required to meet peak demands. A 2025 Duke study found that if large load customers like data centers were willing to accept “modest, short-duration reductions in usage,” nearly 100 GW of large new loads could be integrated into the grid with minimal impact to existing customers or infrastructure. Powerhouse Ventures portfolio company Mercury Computing has built the commercial and technical interface the study envisioned. Mercury gives utilities and data centers a platform to negotiate and automate flexible scheduling agreements that allow new load to integrate quickly, without costly infrastructure buildout. Another emerging lever for using load flexibility to improve grid utilization is hyper-local asset dispatch, based not on wholesale prices but on real time transformer or feeder load. WeaveGrid’s DISCO platform aims to do just that.  

Improvements in grid management and implementation of strategies like dynamic line rating can also have a profound effect. Software platforms can allow grid operators to better dispatch and improve electricity allocation on existing transmission infrastructure. This therefore lets them deliver more electricity across the same infrastructure. Powerhouse Ventures portfolio company ThinkLabs provides grid operators with the AI-powered digital twin and real-time scenario modeling needed to safely and precisely operate the grid. Splight and LineVision help utilities avoid transmission bottlenecks and extract more capacity from existing transmission assets.

Improved O&M cost-effectiveness

There are also opportunities to reduce O&M costs for T&D infrastructure. O&M costs are passed directly to customers, so decreasing these leads to bill savings. A number of innovative companies are offering utilities tools to reduce these costs. Powerhouse Ventures portfolio company Overstory uses satellite data and AI models to provide utilities with predictive, risk-driven operations that maximize impact within existing budgets. Companies like Percepto, ESmart Systems, Buzz Solutions, ThreeV, Voltair, and Sees are supporting the replacement of expensive manned inspections with various forms of lower cost, AI-analyzed drone inspections. 

Lower new construction costs

Finally, bringing down the time and cost of building new T&D infrastructure can help push consumer prices lower, even as the grid expands. Policy measures, such as permitting reform and improved community engagement processes are one important layer. However, there are also technology innovations which can help. A number of software platforms are working to pull “soft costs” out of construction processes by improving communications and project management. RecordLens’ platform is specifically geared towards utility contractors. And while the use of drones is more limited in T&D construction than O&M, Infravision is using drones to help more quickly string new transmission lines. 

Potential “Winners” if Prices Fall

Like most commodities, the benefits of lower prices are generally distributed - small and spread across a large set of consumers. The benefits of high prices, on the other hand, are concentrated with a few suppliers. That said, we believe there are certain sectors that stand to gain an outsized benefit from falling prices. Two of these are:

• Industrial Electrification: falling prices make electric industrial equipment like electric arc furnaces, boilers, grinding mills, dryers, and forklifts more attractive. Electrification also unlocks flexibility; dynamic load management becomes a value driver. Powerhouse Ventures portfolio company CVector connects live plant controls to real-time market signals, letting electrified facilities optimize operational and commercial decisions in sync.

• Fleet Electrification: fleet operators are primarily driven by the total cost of ownership (TCO), and fuel costs represent 60% of OpEx. Falling electricity prices pull down TCO, further justifying vehicle electrification across more use cases. Powerhouse Ventures portfolio company Presto helps operationalize EV fleets by providing streamlined access to the public charging network for mid-route charging.

The Bottom Line

Assuming that higher electricity prices are inevitable is dangerous for investors, innovators, developers, and policy makers. Even setting aside important regional nuances, average electricity prices will be driven by a wide range of uncertain market factors, policy decisions, and technological innovations. 

If you’re a seed-stage founder building digital solutions for a cleaner, more affordable, and more resilient electric grid, we’d love to hear from you!