Grid Growth, Utilization, and Affordability: A Playbook for States
- 8 hours ago
- 7 min read
A new report from Deploy Action outlines a near-term roadmap for governors and regulators to meet load growth without locking customers into years of rate shock
This is an excerpt of Deploy Action's new whitepaper, Grid Growth, Utilization, and Affordability: A Playbook for States. Download the report in its entirety here.
Executive Summary
The United States electrical grid has entered a period of rapid transformation. Electricity demand is surging at a pace not seen in 25 years, driven by data centers, industrial reshoring, and rising electrification. In parallel, electricity bills have become a major economic and political concern. Retail rates increased roughly ~25% from 2018 to 2024, driven by increasing transmission and distribution costs, and are projected to rise faster than inflation through 2030 absent intervention. If states respond to load growth using the planning models of the past (peak-driven buildout of poles / wires), retail customers will bear an undue cost burden. If modern tools are used, states can increase utilization of existing grid assets to defer near-term costs while harnessing long-term load growth to spread fixed costs over a growing customer base. Together, these actions would stabilize electricity prices and help preserve customer affordability. State leaders will play a critical role in determining the path forward. Proactive leaders will take steps to more intelligently utilize existing infrastructure while securing decade-defining long-term investments in their regional economy.
The Utilization Challenge
Electricity rates have outpaced inflation since 2022, driven by factors that predate the recent surge in demand. Persistent underinvestment in transmission and distribution (poles and wires) has burdened the electricity system with staggering costs to maintain aging, vulnerable infrastructure networks. In addition, the incentive to lean on capital-intensive, new investments - which earn utilities a guaranteed rate of return - embeds additional costs borne by ratepayers.
The United States’ power system plans infrastructure to accommodate the highest demand hours of the year (peak utilization) and rewards utilities for breaking ground on new projects to serve this signal (rather than optimizing assets that have already been paid for). In addition, most state regulators and utilities lack consistent, transparent metrics to understand the percentage of underutilized capacity on the transmission and distribution grid. As a result, customers finance infrastructure that is underutilized most of the year (~50 - 55% average annual network utilization).
If this peak-driven planning model does not change, grid utilization is likely to remain unchanged and rapid electricity demand growth could significantly increase infrastructure costs for all ratepayers. However, emerging evidence suggests that a combination of market reforms and technology deployment would allow states to significantly increase grid utilization, adding substantial loads without increasing system peaks and freeing up ~75 - 100GW of system headroom without capacity expansion.
A Roadmap for States
To stabilize rates, state leaders must pivot their regional electricity system to reward technology deployment, drive higher utilization of existing assets, and increase speed-to-power without cross-subsidizing large, commercial loads.
Near-term (2026 - 2030): Before the end of this decade, states should focus on delivering maximum value from grid infrastructure customers have already paid for, while using new, large loads as a catalyst for accelerated technology adoption and improved interconnection processes.
Scale Virtual Power Plants (VPPs): Virtual power plants (VPPs) - aggregations of distributed energy resources (DERs) including batteries, smart thermostats, and electric vehicles - can provide grid reliability at ~40 - 60% lower cost to traditional alternatives and be deployed in months, not years. The U.S. Department of Energy estimates that scaling VPPs 3 - 5x by 2030 (to ~80 - 160 GW) could serve ~10 - 20% of peak load and save power systems $10 billion annually in grid costs. States looking to rapidly expand their VPP portfolio should default to auto-enrollment of enabled devices, reward utilities that grow their VPP footprint, and set standards that allow for device interoperability. Passed in 2020, the Federal Energy Regulatory Commission’s (FERC) Order 2222 will also help to accelerate VPP adoption by ensuring DERs can aggregate heterogeneous technologies with lower participation barriers (allowing aggregations down to 100 kW). In addition, Order 2222 will provide a national regulatory foundation for VPPs to compete directly with traditional generation assets. California’s Independent System Operator (CAISO) currently operates the largest VPP system nationally with 515 megawatts (MW) of enrolled capacity and offers a playbook for states scaling VPPs in their own regional grids while programs in Texas are aiming for 1GW of VPPs by 2035.
Increase grid utilization to make better use of existing infrastructure: Building new transmission and distribution (T&D) infrastructure is the largest driver of cost increases to ratepayers. Recent evidence suggests that by better utilizing existing T&D assets, state regulators and utilities can defer or right-size new grid investments, reducing unnecessary capital spending and lowering long-term costs. Even modest improvements in utilization, such as identifying underutilized capacity or targeting overloaded circuits at times of peak demand, can produce significant affordability benefits when scaled across the distribution grid. Several states are already leading on this front. For example, legislation passed by the Virginia House of Delegates on a unanimous, bipartisan basis and passed the Virginia Senate in February 2026 (HB 434/SB 621) would give the Virginia State Corporation Commission more tools to evaluate grid utilization metrics, ensuring ratepayers are getting full value from infrastructure they are already paying for.
Prioritize large load flexibility: States should establish flexible / interruptible service classes for large loads and allow sophisticated customers to ‘Bring Your Own Capacity’ (BYOC). Under BYOC, a customer procures a combination of generation, storage, and VPP participation to cover their incremental reliability needs (avoids contributing to annual peaks) in exchange for faster interconnect - improving overall system level utilization and protecting ratepayers from financing peak-driven upgrades. Texas has seen impressive results with its ‘Connect and Manage’ system, an approach where large loads accept fast grid interconnection in exchange for possible curtailment during times of peak stress. Within the Electric Reliability Council of Texas (ERCOT) territory, large loads (10 MW or larger) can interconnect in ~18 - 30 months and small loads (below 10 MW) in ~8 to 12 months. In contrast, congested regions like the mid-Atlantic grid (Pennsylvania-New Jersey-Maryland Interconnection, PJM) have seen average wait times of 8 years for interconnect.
Modernize rate design and contract structures to protect customers: States can isolate large loads within distinct rate classes to protect smaller customers. Grids may pursue a combination of default time-of-use pricing, stronger on-peak/off-peak differentials, and specialized large-load tariffs which can reward load shifting, reduce coincident peaks, and ensure that new demand pays its fair share of system costs. States may also encourage large loads to pay for critical grid upgrades, agree to minimum contract lengths, or sign ‘take or pay’ contracts to reduce the risk of overbuild in response to new demand signals.
Pursue permitting reform: Faster permitting would expand generation, transmission, and distribution capacity across the grid. States can take steps to fast-track permitting through statutory ‘shot clocks’ that mandate permit decisions with fixed periods (e.g., ~12 months for municipal reviews, 15 months for state-level listing). States can also streamline processes by establishing centralized siting authorities that would offer a single, consolidated application process to replace fragmented local approvals. Additionally, states can designate pre-cleared ‘Energy Opportunity Zones’ in areas with low environmental impact, allowing developers to utilize categorical exclusions and programmatic environmental reviews to by-pass years of site-specific litigation.
Medium-term (2030 - 2035): In addition to the steps above, states should begin to take action on initiatives that will benefit regional grids in the early 2030s, including accelerating the deployment of grid-enhancing technologies and expanding clean, firm capacity.
Deploy grid-enhancing technologies (GETs): Grid-enhancing technologies are “commercially available but underutilized” technologies including advanced conductors, power-flow controls, and dynamic line rating (DLR). Studies have shown that reconductoring can increase capacity by more than 100% while DLR systems can increase line capacity as much as 70%. Deploying GETS in capacity-constrained regions can serve as a high-speed, low-cost alternative to building new transmission lines with many solutions that can be deployed in months rather than years.
Deliver incremental generation: Where available, states should encourage new loads to unlock existing firm, low-carbon generation from uprates and restarts of hydropower and nuclear facilities. Uprates have been the primary driver of new US nuclear capacity for decades, with roughly ~8GW of uprates approved to date across the US nuclear fleet. Uprates can take a few years to plan and execute, in part because plants may need to wait until their refueling cycle for more extensive changes to system configurations (e.g., changes to turbines, pumps, or transformers), meaning states looking to see additional capacity from existing nuclear resources in the early 2030s should begin planning for uprates today.
Long-term (2035+): Finally, states should begin laying the groundwork for policy proposals that will speed the construction of clean, firm generation, hasten interconnect, and re-align utility incentives to reward technology adoption and asset utilization for the long-term.
Build the fleet of the future: States will need to scale low-carbon, firm assets including next generation geothermal, utility-scale renewables with battery storage, nuclear (Gen III and Gen IV designs), and carbon capture and utilization systems to meet the electricity needs of the future. The work to originate, fund, and develop these projects has already begun, with hundreds of megawatts of demonstration projects breaking ground across the country. States should take steps to attract the local infrastructure development and high-quality trades jobs that these projects provide. For example, states can ensure that local incentives stack with federal subsidies, siting and permitting processes are streamlined, and state regulations send clear market signals that businesses can plan decades-long infrastructure investments within their jurisdictions.
Reform planning and utility incentives: Finally, states should take steps to better align utility incentives with policy objectives beyond capital spending - including asset utilization, technology adoption, and low-carbon performance.
The United States has repeatedly modernized its energy system to support economic growth - from rural electrification beginning in the 1930s to the shale boom of the 2010s. Today’s challenges call for states to take aggressive steps to deploy proven technologies (VPPs, DERs) while shifting incentives to reward cost-efficient infrastructure expansion. States that act quickly to increase grid utilization, prioritize flexibility, and realign incentives to reward technology deployment can accommodate load growth while protecting retail customers from rising bills.