​A 1 MW, 4-hour battery could have earned $51/kW-month in March 2026, stacking Regulation ($35/kW-month), Real-Time energy arbitrage ($11/kW-month), and capacity payments ($5/kW-month). That is down from $56/kW-month in February, when elevated winter TB spreads drove higher arbitrage value.

​RT TB4 spreads averaged $341/MW-day, 70% above March 2025's $201. That average was skewed by a handful of extreme spike days; the median day was $257, still a meaningful 28% improvement over last year.

Key takeaways

• Total BESS revenue potential fell to $51/kW-month from $56 in February, driven by lower RT arbitrage as TB4 spreads narrowed from $510 to $341/MW-day.
• Baltimore (BGE), Washington DC (PEPCO), and Virginia (DOM) zones offered the highest RT TB4 spreads. DA spreads showed less zonal variation.
• Winter Storm Iona hit the PJM region in mid-March, producing 74 mph wind gusts, followed by a cold snap..
• Planned generation outages surged from 2 GW in early February to nearly 40 GW by late March, reducing available capacity during the storm period.
• ​Regulation prices eased to $105/MWh from February's 4-year high of $194/MWh, but remained nearly 3x March 2025 levels following the October market redesign.

Zonal spreads varied sharply, with Mid-Atlantic zones pulling further ahead

​Not all batteries saw the same revenue opportunities in March. The highest Real-Time TB4 spreads were concentrated in the Mid-Atlantic corridor running from Virginia through Maryland. Baltimore (BGE) led at $532/MW-day, followed by the Washington DC area (PEPCO) at $487/MW-day and Virginia (DOM) at $428/MW-day. Further west, zones in Ohio, Illinois, and Pennsylvania saw spreads closer to $300-370/MW-day.

This geographic pattern is consistent with January and February. Persistent transmission constraints between eastern load centers and western generation continue to drive price separation during ramp hours.

​In comparison, DA TB4 spreads were less differentiated across zones and showed less year-over-year movement. Parts of New Jersey, eastern Pennsylvania, and Delaware were essentially flat or down in DA, even as their RT spreads rose significantly. Batteries that only participated in Day-Ahead would have seen far less differentiation.

At the asset level, the same regional ranking holds. Both operating and planned batteries in the Mid-Atlantic corridor would capture roughly double the spreads of those in the Midwest.

TB4 spreads declined from February but remain elevated year-over-year

RT TB4 spreads averaged $341/MW-day in March, down from $510 in February.

​The average was skewed higher by three days maintaining a TB4 above $900/MW-day. The median day was only $257/MW-day versus $201/MW-day in March 2025, with most days following a similar hourly shape.

The spikes get the attention, but the lows matter just as much for TB spreads. March 2026 had 108 hours below $20/MWh, compared to just 13 in March 2025. Batteries profit from the gap between cheap and expensive hours in the same day, and March 2026 delivered wider gaps on both ends.

Two distinct price events stand out. On March 12-13, Real-Time prices spiked to $882 and $1,252/MWh while Day-Ahead was only $91 and $113. On March 17-19, the pattern reversed: Day-Ahead peaked at $272/MWh while Real-Time came in lower.

Higher load, elevated outages, and Winter Storm Iona drove March volatility

Three factors combined to keep March volatile despite the seasonal transition.

Demand was higher YoY. Mean hourly load reached 90 GW, up from 87 GW in March 2025. PJM saw 101 hours above 100 GW, more than double last year. This is visible in the fuel mix chart, where net exports fell to roughly 2.5 GW from about 4 GW in 2025.

On the other side, spring maintenance season tightened supply. Planned outages surged from around 2 GW in early February to nearly 40 GW by late March. Total outages peaked at 57 GW.

Then Winter Storm Iona hit. On March 15-16, severe winds gusted to 74 mph across the PJM footprint and over 500,000 customers lost power. On March 17-19, an Arctic cold snap followed with temperatures 20-30 degrees below mid-March norms. Day-Ahead markets saw the cold coming and priced it in aggressively, with DA peaking at $272/MWh on March 18. Real-Time prices for those same hours came in much lower, as the cold broke faster than expected and recalled maintenance capacity returned to the grid.

Regulation prices eased but remain elevated following the October redesign

Regulation cleared at $105/MW/h in March, down from February's 4-year high of $194. But $105 is still nearly 3x March 2025's $36, reflecting the structural shift from PJM's October 2025 Regulation market redesign.

Morning and evening ramp hours still produced sharp price spikes, though less extreme than February's peaks above $750/MWh. PJM also raised the non-ramp Regulation requirement from 525 MW to 750 MW year-over-year.

What does March tell us?

March 2026 was a transitional month. The typical day was moderately higher-earning than last year. The exceptional days were driven by a storm colliding with spring maintenance season.

Regulation revenues remain structurally elevated. Arbitrage upside is real but concentrated in a few high-volatility days that require Real-Time market participation and favorable nodal positioning to capture.