TOPIC #5
Grid Flexibility
The portfolio of tools and approaches for an evolving U.S. electric system is expanding.
Powering Load Growth and Grid Reliability amid Evolving Market Demands
Grid flexibility—the ability to dynamically shift demand or supply in response to changing system needs—is now central to both real-time operations and long-term strategic planning for U.S. electricity markets.
Utilities and grid operators are leveraging flexible resources to address rising loads and the integration of variable renewable resources, driving more dynamic electricity network operations.
The resources—and impacts—are diverse. The large-scale deployment of battery energy storage is improving operational capabilities. Meanwhile, distributed energy resources (DERs) and flexible loads are being considered for reliability support.
With accelerating load growth, market participants will need to continue to balance economic, technical, and regulatory priorities when evaluating solutions for long-term grid reliability and resilience.
Key Takeaways
Grid flexibility is essential for managing rising electricity demand and variable renewable energy, driving the need for better grid controls and new business approaches.
Key developments include California and Texas deployment of large-scale battery energy storage, expanding market opportunities to aggregate and dispatch distributed energy resources, and increasing interest in market designs that encourage flexible loads.
Ensuring reliability and capturing economic value from flexible resources will depend on proactive market reforms, collaborative planning, and investments in grid modernization to manage increasing system complexity.
Grid Flexibility Enables Load Growth While Bolstering Reliability
Grid flexibility is becoming a critical adaptation strategy for the power sector. Flexible resources include demand response programs, battery energy storage, DERs, and advanced grid management systems.
Enhancing grid flexibility has proven important for strengthening both grid operations and reliability. For example, the significant deployment of battery storage capacity in California and Texas (see Figure 1) has facilitated the integration of variable renewables and provided invaluable support during extreme weather events.
Beyond operational benefits, flexible grid solutions can help electric utilities defer major infrastructure investments. In New York, a recent study found that a portfolio of grid flexibility measures could avoid $2.9 billion in annual power system costs by 2040, primarily by reducing the need for new generation capacity. By including a broad range of technologies and flexibility options, the report identified 8.5 GW of grid flexibility potential which could meet 24% of the NYISO’s forecasted summer peak load.
Meanwhile, regulatory frameworks, such as FERC Order 2222, continue to evolve and will support additional grid flexibility over the long term. Market incentives also increasingly reward flexibility providers, accelerating adoption of innovative grid flexibility solutions. However, interconnection delays and technology standardization remain significant challenges. In addition, misalignment between program objectives and rate tariffs create obstacles in some jurisdictions.
Utilities are addressing this through contractual and up-front financial arrangements, so for the time being, the industry will have to prepare for these loads.
FIGURE 1
Operating Battery Energy Storage Capacity for Top 10 States (as of December 2024) (MW)
Sources: EIA; ScottMadden analysis
FERC Order 2222
The Federal Energy Regulatory Commission (FERC) issued Order 2222 in September 2020. The order is designed to enable DERs to participate in organized energy markets operated by U.S. regional transmission organizations/independent system operators.
The order mandates that these grid operators revise their tariffs to allow DER aggregators (third-party entities that bundle multiple small-scale DERs like rooftop solar, battery storage, electric vehicles, and demand response) to compete on a level playing field with traditional power generators in capacity, energy, and ancillary services markets.
Market Growth Drives Focus on Battery Performance in California
Rapid capacity growth is transforming California’s battery storage landscape, but declining revenues signal market maturation as operators shift from volume-driven expansion to performance-optimized strategies amid intensifying competition.
California’s battery storage capacity surged from 237 MW in 2019 to 11,720 MW in December 2024 (see Figure 2). Battery storage now accounts for 12% of the state’s operating nameplate capacity.
As a flexible resource, battery storage serves a dual purpose on the CAISO system. During midday solar peak hours, battery charging represents 15% of total system load, helping absorb surplus renewable generation. During evening peak demand, battery storage delivers 9% of CAISO’s energy needs (see Figure 3).
The operational profile directly responds to California’s “duck curve”—a daily pattern in which solar generation sharply reduces midday demand for dispatchable power followed by a steep evening surge as solar output declines and electricity use rises.
However, the economics of battery storage have shifted over time. Net market revenues declined sharply from $78/kW-year in 2023 to $53/kW-year in 2024, driven by lower peak energy prices and reduced system loads. This 32% revenue drop reflects the effects of market saturation as battery supply growth outpaces demand for traditional energy arbitrage.
As a result, market dynamics now favor disciplined operators with advanced controls or locational advantages. Performance differentiation—rather than continued capacity additions—is becoming the key source of competitive advantage.
FIGURE 2
Operating Battery Storage Capacity in California (2019–2024) (MW)
Note: Figures above rounded to nearest MW.
Sources: EIA; ScottMadden analysis
FIGURE 3
Average 5-Minute Battery Energy Schedules*
Note: *Schedules are the actual charging and discharging of batteries based upon CAISO’s 5-minute real-time dispatch instructions.
Source: CAISO
Texas Battery Storage Market Matures amid Record Expansion and Revenue Model Evolution
Unprecedented capacity growth has established Texas as a leader in battery energy storage.
Battery storage nameplate capacity surged from 107 MW at the end of 2019 to 7,456 MW by the end of 2024 (see Figure 4). Texas is now the nation’s second-largest battery storage market after California.
Revenue streams are shifting as market competition intensifies. In 2024, battery operators experienced a transition from reliance on ancillary services to increased dependence on energy arbitrage. Additional capacity entering ancillary services markets drove down per-megawatt revenues and forced operators across the sector to adjust their strategies.
The growing battery energy storage fleet is making valuable contributions to grid reliability.
- During extreme weather events, Texas batteries provided essential grid stabilization—deploying 1.8 GW during the August 2023 heat waves and reducing energy prices by nearly 50%.
- Battery performance during Winter Storm Heather in January 2024 further demonstrated these capabilities, with storage systems earning 74% of their January and February revenues in just three days.
Future battery storage growth will face both economic and technical challenges. Although ERCOT’s interconnection queue contains substantial proposed battery capacity, declining revenue per kilowatt in 2024 highlights concerns about market maturation. Technical issues surrounding the integration of inverter-based resources and the need for advanced grid-forming capabilities will require continued focus as deployment accelerates.
FIGURE 4
Operating Battery Storage Capacity in Texas (2019–2024) (MW)
Note: Figures above rounded to nearest MW.
Sources: EIA; ScottMadden analysis
DERs Increase Supply and Avoid Grid Costs
DERs are increasingly being aggregated and coordinated to function as single, dispatchable entities capable of providing grid flexibility comparable to traditional power plants.
Relevant DERs include rooftop solar, battery energy storage, electric vehicles (EVs), and demand response.
As of January 2025, the Department of Energy estimated approximately 30 GW of DER capacity in operation, with the potential to increase to 80 GW to 160 GW by 2030. This expansion could serve about 10%–20% of peak demand and yield $10 billion annually in avoided capacity costs. However, DER deployment will vary significantly between states (see Figure 5).
As mentioned earlier, FERC issued Order 2222 to facilitate DER participation in wholesale electricity markets. CAISO and ISO-NE have fully implemented Order 2222, while other markets are partially compliant (see Figure 6).
States and utilities are also encouraging the use of DERs to enhance grid flexibility. A 2024 report from the Smart Electric Power Alliance identified 105 such actions across 38 jurisdictions, including:
- 68 utility-led programs focused on technologies that can shift load, mitigate peaks, and provide fast-ramping capabilities, including energy storage, demand response, and managed EV charging, and multiple technology programs.
- 37 state-level regulatory actions, supporting alignment of state incentives with grid needs through the development of DER aggregation frameworks, statewide policy road maps, and reforms to net metering structures.
As regulatory frameworks mature and market access for DERs expands, these technologies are poised to become beneficials tools for managing peak demand, reducing system costs, and enhancing grid flexibility for states and utilities.
FIGURE 5
Forecasted Dispatchable DER Capacity in 2030 (GW)
Notes: 2030 total dispatchable capacity is estimated by taking a proportion of total 2030 capacity and applying simplifying assumptions on the proportion that is dispatchable. For solar, batteries, heat pumps, smart thermostats, and water heaters, Ohm Analytics estimated 2030 total capacity by state. For EVs and EV charging, NREL’s base scenario estimated 2030 total capacity by state. For commercial & industrial loads (or building automation systems) and distributed fuel generation, national level estimates from Wood Mackenzie’s U.S. DER Market Report were extrapolated to 2030 and allocated to states based on 2022 metering data from EIA.
Source: DOE
FIGURE 6
FERC Order 2222 Compliance Status (as of January 2025)
Source: DOE
Flexible Loads May Reduce Demand and Cut Costs While Supporting Grid Reliability
Flexible load resources are electricity-consuming assets—ranging from industrial operations to smart thermostats—that can shift, curtail, or modulate usage in response to grid signals, pricing, or operator instructions.Flexible loads present considerable opportunities. A recent study found that curtailing electricity use for 0.25% to 1.0% of annual hours could allow the grid to absorb 76 to 126 GW of new flexible loads (particularly data centers) without requiring additional generation capacity. In August 2024, Google signed data center demand response agreements with Indiana Michigan Power and Tennessee Valley Authority.
Flexible loads present considerable opportunities. A recent study found that curtailing electricity use for 0.25% to 1.0% of annual hours could allow the grid to absorb 76 to 126 GW of new flexible loads (particularly data centers) without requiring additional generation capacity. In August 2024, Google signed data center demand response agreements with Indiana Michigan Power and Tennessee Valley Authority.
In addition, several states have recently enacted laws to promote flexible load resources:
- Texas SB 6 (June 2025): Mobilizes ≥75 MW flexible loads as grid assets, requiring emergency curtailment and a day-ahead demand response program.
- Maryland SB 937 (May 2025): Sets oversight for ≥100 MW loads, integrating planning, cost recovery, and curtailment for enhanced grid reliability.
- Oregon HB 3546 (June 2025): Requires long-term contracts and grid funding from ≥20 MW users, supporting planned curtailment and coordination.
- Utah SB 132 (May 2025): Permits direct-supply contracts with large users, including optional curtailment for grid stability.
Implications
Grid flexibility represents a marked shift in how utilities and grid operators approach system planning and operations. It requires moving from traditional supply-following-demand models to dynamic resource optimization. The economic case could be compelling—New York’s analysis demonstrating potential annual savings of $2.9 billion by 2040 through flexibility measures.
This economic advantage becomes increasingly critical as new data centers drive historical load growth and renewable integration creates operational complexity. The maturation of flexibility markets, evidenced by California’s battery energy storage sector shift from capacity expansion to performance optimization, signals an evolution toward more sophisticated and competitive resource deployment. As market dynamics increasingly reward operational excellence over simple capacity additions, utilities and independent operators must develop advanced control capabilities and strategic positioning to capture value.
The convergence of flexible demand resources, distributed generation, and large-scale storage creates new opportunities for system optimization but also demands enhanced coordination mechanisms and standardized interconnection processes. The uneven implementation of enabling policies like FERC Order 2222 across market regions highlights the regulatory and technical challenges that must be addressed to fully realize these benefits. Success in this environment will require proactive market design, collaborative planning between stakeholders, and sustained investment in grid modernization technologies that can effectively orchestrate a diverse portfolio of flexible resources.
CONTACT OUR EXPERTS
On Grid Flexibility
Kevin Hernandez
PARTNER
klhernandez@scottmadden.com 919.781.4191
Chris Sturgill
PARTNER
csturgill@scottmadden.com 919.781.4191
Josh Kmiec
PARTNER
joshuakmiec@scottmadden.com 919.781.4191
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