Tech Insights

Mixing It Up: Grid Reliability Needs Multiple Solutions

May 24, 2024 by Shannon Cuthrell

A mix of multiple resource portfolios, grid-enhancing technology, and energy storage could provide grid reliability while reducing emissions. 

Several practical obstacles impede the federal government’s goal of cutting 50–52% of greenhouse gas emissions by 2030 and reaching net-zero status by 2050. With more fossil fuel plants retiring, less firm capacity is available to manage sudden spikes in supply and demand from variable wind and solar generation. Energy storage deployment is not growing fast enough to support the increasingly renewable grid. Reliability is another concern, as much of the nation’s transmission and distribution infrastructure approaches the end of its 50- to 80-year life. 

The Department of Energy (DOE) recognized these gaps in a report assessing the grid’s ability to support widespread electrification in an era of rising electric vehicle adoption, advanced computing power in data centers, and a manufacturing boom prompted by federal tax incentives. Regional transmission system operators report a sharp rise in annual and peak energy demand. PJM Interconnection, which oversees 13 eastern states, increased its 10-year net energy load growth projection from 1.4% annually in 2023 to 2.3% in 2024. 


Electric poles.

Electric poles. Image used courtesy of Pexels/by Krea


The DOE has identified several issues threatening resource adequacy. This metric gauges a bulk power system’s ability to meet demand at all times, depending on generator fuel supply limits, long-term load uncertainty, outages, and weather-related load variability. The DOE argued that depending on additional fossil fuel resources to cover reliability needs is risky, as fuel availability issues may limit the grid’s response in extreme weather. At the same time, continuing business as usual cannot accommodate the rapid energy transition already underway. 

The DOE emphasized that no one-size-fits-all technological or operational solution exists, but a mix of approaches can unlock long-term benefits. 


Tapping Natural Gas to Support the Energy Transition

Natural gas is a pillar of today’s grid, generating more than 40% of the nation’s electricity in 2023. According to the DOE’s report, new natural gas capacity can be designed to support a renewable electricity system. For example, generators could operate at lower capacity factors, unlocking more flexibility. Modular plant designs can boost ramping capabilities and operating reserves while reducing stranded assets. Some natural gas operators are now mixing green hydrogen into their supplies, produced through surplus solar or wind electrolyzers. 

Plants can also retrofit carbon capture and sequestration/storage (CCS) technologies to offset emissions. CCS deployments will likely expand in the coming years, anticipating the Environmental Protection Agency’s upcoming requirement that coal- and gas-fired generators reduce 90% of their carbon emissions


Carbon capture and sequestration.

Carbon capture and sequestration. Image used courtesy of Congressional Budget Office


The CCS market remains nascent, with just 15 facilities operating nationwide at the end of 2023, primarily at natural gas processing or ethanol plants. The Congressional Budget Office estimates those installations have enough capacity to capture over 20 million metric tons of carbon dioxide annually, about 0.4% of U.S. emissions. 

Facing more emissions regulations and competition from lower-cost renewables, plant operators have retired more than 177 GW of fossil fuel and nuclear resources over the last ten years. Over 12 GW of coal and natural gas capacity came offline in 2023 alone, though this pace is expected to slow by 62% in 2024. 

Meanwhile, developers plan to add 36.4 GW of utility-scale solar generation in 2024, double last year’s count, alongside 8.2 GW of wind. Only 2.5 GW of natural gas capacity will come online—the least in 25 years—primarily through simple-cycle natural gas turbine plants capable of ramping up or down quickly for grid support. Continued investments in existing hydropower, nuclear, and geothermal plants can also provide firm capacity with zero emissions. 


Energy Storage Opportunities 

Energy storage technologies like batteries support resource adequacy with extended backup power and the ability to discharge during peak demand. Battery energy storage systems typically last one to four hours. Generally, storage gets closer to meeting peaks as the course reaches four hours. 

Utility-scale battery storage systems provide other functional advantages, such as frequency regulation, arbitrage, ramping/spinning reserves, voltage or reactive power support, and load management. This is one reason why battery capacity growth is expected to nearly double this year, adding 14.3 GW to the existing 15.5, compared to only 6.4 GW in 2023. 


Long-duration energy storage archetypes (orange circles) relative to storage design.

Long-duration energy storage archetypes (orange circles) relative to storage design. Image used courtesy of California Energy Commission (Page 22, Figure 3)


Hybrid solar-plus-storage projects are increasingly popular, representing most of the 525 GW of battery capacity waiting in interconnection queues at the end of 2023. Another 503 GW is standalone storage, distinct from hybrid plants that can be deployed faster when combined with existing generators. 

Long-duration energy storage technologies lend additional support with 10 hours or more of dispatch. Pumped storage hydropower (PSH) lasts eight to 16 hours and is the grid’s leading energy storage resource, claiming 70% of utility-scale storage capacity. The nation’s 43 existing PSH plants total 22 GW of generation and 553 GWh of storage. Another 91 GW is under development, mainly in closed-loop configurations

Other long-duration storage technologies are being explored across the U.S. The longest announced to date is a 5 MW/500 MWh iron-air battery that can discharge energy for 100 hours based on a reverse rusting process. Each module comprises a 50-cell stack with air and iron electrodes and water-based electrolytes. Form Energy is expected to bring the system online in California by 2025. 


Iron air battery process.

Iron air battery process. Image used courtesy of Form Energy


Upgrades and Grid-Enhancing Technologies

Transmission systems can incorporate advanced hardware and software into their infrastructure relatively quickly. The DOE estimates nearly one-fifth of U.S. transmission lines could be good candidates for advanced reconductoring, which involves swapping composite core conductors for enhanced steel cores with higher capacity and efficiency. Companies can do this without needing to secure new rights of way. 

The resource adequacy report cited one example where American Electric Power unlocked a 2x capacity increase in Texas by replacing over 200 miles of aging conductors with advanced composite cores. 


Regional transmission needs

Regional transmission needs. Image used courtesy of DOE (Figure V-17, Page 128)


Grid-enhancing technologies like sensors, control devices, and analytics software are designed to maximize resource use along existing lines. Advanced power flow controls can redirect power from overloaded lines to those with free capacity. Topology optimization software works similarly, rerouting loads from congested lines. 

More operators are adopting dynamic line rating (DLR) technology, which adjusts transmission ratings based on real conditions, such as wind speed, to determine how much power can be carried through the line. In one example, Pennsylvania Power and Light deployed DLR to boost its average capacity ratings by 18–19% and avoid $50 million in reconductoring and rebuilding. The DLR approach is gaining traction over conventional static ratings that rely on conservative assumptions. 

According to the DOE, these low-cost technologies can be deployed individually or combined in under three years without planned outages.