Managing Energy Costs During Summer 2025 Peak Demand

Spring may still be in full effect, but some commercial and industrial energy managers are bracing for what could be another record-breaking summer. Energy costs for the summer of 2025 face a perfect storm of surging demand from electrification and data centers colliding with shrinking reserve margins and delayed renewable integration.

The 2025 forecast paints a dire picture – PJM projects a 3.1% annual summer peak load growth, driven by data centers adding ~7 GW annually, while ERCOT warns of supply deficits reaching 32.4% by 2029 under aggressive demand scenarios. Even historically stable regions like ISO-NE anticipate tighter summer margins, with peak demand revisions up 1% year-over-year amid rising behind-the-meter solar adoption.

For energy procurement teams in PJM, ERCOT, and ISO-NE states, these trends translate into unprecedented financial risks. PJM’s 2025 summer peak is forecast at 151,000+ MW – up from 147,000 MW in 2023 – with reserve margins thinning due to coal retirements and slower battery deployments. Meanwhile, ERCOT’s evening ramp periods will see heightened volatility as solar generation drops and industrial demand from crypto mines and electrified oil operations spikes.

But within this volatility lies opportunity. Market redesigns in 2025, including ERCOT and ISO-NE’s co-optimization of energy and ancillary services, will enable smarter bidding strategies and real-time load flexibility. Forward-thinking businesses can use AI-driven procurement platforms, behind-the-meter storage, and demand response 2.0 tactics to find energy savings.

Let’s explore how leading businesses are future-proofing operations against $1,000+/MWh price spikes, leveraging state-specific incentives, and navigating the new era of co-optimized markets where every megawatt flex translates to bottom-line resilience.

Practical strategies for managing 2025 summer peak energy costs

As energy markets face unprecedented demand volatility driven by grid strain, regulatory shifts, and extreme weather, commercial and industrial businesses must adopt a multi-pronged approach to mitigate risks. 

Four proven strategies exist to reduce exposure during peak periods. They combine advanced technology, financial hedging, and grid-responsiveness solutions to help businesses rein in energy costs without sacrificing sustainability goals.

AI-driven procurement

AI-powered energy procurement platforms integrate real-time grid data, weather forecasts, and consumption patterns to anticipate price spikes and optimize purchasing strategies. Key applications include:

• Peak-hour forecasting. Tools like Hitachi Energy’s Nostradamus AI analyze historical ISO data to predict 2025’s critical periods with greater than 90% accuracy.
• Automated load adjustments. Integrate with EMS systems to preemptively shed non-critical loads such as HVAC cycling during forecasted peaks, reducing demand charges by 15 to 25%.
• Risk modeling. Simulate market scenarios like ERCOT’s ECRS-induced price spikes to lock in rates before volatility hits.

Hybrid energy contracts

Hybrid energy contracts merge fixed-rate security with renewable PPAs to hedge against volatility. Using a fixed-rate backbone, commercial and industrial businesses can lock in 60 to 80% of consumption at stable rates, insulating against projected annual demand growth.

Renewable arbitrage, paired with solar or wind PPAs at $20 to $30/MWh can offset spot-market purchases.

Behind-the-meter solutions

Solar storage systems reduce grid dependency during ISO snapshot periods. Discharging stored energy during the typical 4 to 7 p.m. peaks cuts charges by 20 to 40%. Combining federal ITC with state credits can achieve payback periods in as little as 3 to 5 years.

Implementation matters to achieve maximum efficiency from this solution. Size storage to cover 90% of monthly peak loads, avoiding oversizing. Use modular systems for scalable deployment.

Demand response 2.0

As grid operators face tighter summer margins, demand response has become a critical revenue stream for energy managers. In PJM’s constrained zones like BGE and Dominion, capacity payments now reach $200–400/MW-day under the Emergency Load Response Program (ELRP), driven by record-high 2025/2026 auction prices.

Meanwhile, ERCOT’s ECRS program offers dual benefits: offsetting $1,000+/MWh price spikes while earning payments for load reductions through aggregators like Enel. Automated curtailment platforms, such as GridPoint, enable businesses to participate without operational disruptions, transforming load flexibility into a strategic asset.

State-by-state energy procurement strategies

As grid dynamics diverge across regions – shaped by climate risks, market reforms, and infrastructure constraints – energy procurement managers must adopt hyper-localized strategies to mitigate peak demand risks.

The summer of 2025 introduces unprecedented challenges: 

• PJM faces 3.1% annual load growth driven by data center sprawl.
• ERCOT grapples with ECRS-driven price spikes exceeding $1,000/MWh.
• ISO-NE confronts dual-peak strain as electrified heating collides with legacy grid limitations.

Below, we break down actionable tactics for PJM, ERCOT, and ISO-NE states, addressing unique regulatory frameworks, market structures, and demand patterns that define each region’s risk landscape.

PJM states: prioritize capacity market participation

The 2025/2026 PJM capacity auction saw an 800% price surge to $14.7 billion annually, driven by coal retirements, RMR designations, and data center load growth.

For businesses in Pennsylvania, New Jersey, and Maryland:

• Enroll in ELRP. Target $200 to $400/MW-day payments in constrained zones like BGE and Dominion by automating 2-to-4-hour load curtailments during peak dispatches.
• Rely on state incentives. Maryland’s 20% storage adder and New Jersey’s Clean Energy Program rebates offset behind-the-meter system costs by 30 to 50%.
• Monitor RMR reforms. PJM’s June 2025 auction may allow RMR plants to participate, potentially lowering capacity prices. Adjust your bidding strategies accordingly.

ERCOT states: combat ECRS-driven price spikes with storage

ERCOT’s ECRS charge amplifies congestion costs during evening ramps, with prices exceeding $1,000/MWh. Tactics for Texas businesses include:

• Deploy 4-hour storage systems. Discharge during 6 to 9 p.m. solar drop-off periods to avoid ECRS pass-through costs and earn revenue via ECRS load reductions.
• Stack incentives. Combine federal ITC with Texas’ property tax exemptions for storage to achieve 3-to-4-year paybacks.
• Partner with aggregators. Platforms like Enel automate ECRS participation, converting 10 to 15% load reductions into bill credits.

ISO-NE: navigate dual-peak challenges

ISO-NE forecasts 24,553 MW summer peaks and rising winter demand due to heating electrification. Recommended strategies for New England states include:

• Dual-season storage. Deploy systems with 6+ hours of discharge to cover summer cooling spikes and winter heating surges.
• Demand response. Enroll in ISO-NE’s forward capacity market (FCM) to earn $50 to $100/kW-year for load reductions during peak seasons.
• Efficiency upgrades. Retrofit HVAC systems with IoT controls to manage dual-peak loads and qualify for mass save incentives.

Implementation checklist

To ensure businesses capitalize on 2025’s peak-demand strategies, this checklist outlines critical steps for vendor partnerships, contract optimization, and incentive compliance. Aligning procurement timelines with regulatory deadlines and market cycles is essential to maximize cost savings and operational resilience.

This structured approach ensures readiness for 2025’s most critical peak periods while maximizing financial incentives.

Tame summer energy costs proactively

As grids brace for another record-breaking summer, the strategies outlined here – from AI-driven procurement to state-specific storage deployments – are no longer optional. They’re imperative. Energy procurement managers who delay risk exposure to $1,000+/MWh price spikes, capacity penalties, and missed incentive deadlines.

Energy procurement managers don’t have to navigate this alone. Partner with a seasoned energy procurement consultant to:

• Optimize hybrid contracts with fixed-rate security and renewable arbitrage.
• Secure state and federal incentives before the 2025 deadlines.
• Automate demand response via FERC-compliant platforms.

Schedule time with one of our energy auditors today to lock in rates, deploy storage, and transform peak demand from a liability into a profit center.