​Winter Storm Fern defined battery revenues in January 2026. The late-month polar vortex triggered forced outages, price spikes, and the highest Day-Ahead arbitrage spread in the past 12-months.

A 1 MW, 4-hour battery could have earned $35/kW-month in January, stacking value across Real-Time arbitrage ($13/kW-month), Regulation ($17/kW-month), and capacity markets ($5/kW-month). That compares to $28/kW-month for the same proxy battery in December 2025.

Day-Ahead TB1 spreads hit $181/MW/day, up $112/MW/day from December. Regulation prices averaged $139/MW/h, with 5-minute prices spiking above $1,700/MW/h during evening ramp hours.

The storm exposed familiar vulnerabilities. Constrained pipeline flows sent gas spot prices to $30/MMBtu. Gas-fired plants faced both fuel shortages and frozen equipment, doubling forced outages. With less capacity available, oil and peaking units set prices. The combination of spiking fuel costs and generation outages pushed electricity prices to extremes.

For more insight on December 2025, read last month's report here.

For any questions, reach out to aaron@modoenergy.com.

Post-storm prices consistently reached $500/MWh

January 2026 was divided into two distinct periods by the storm. Before the storm, price profiles tracked January 2025 closely. After the storm, Real-Time prices regularly breached $500/MWh.

The volatility was concentrated in the final week. From January 23-31, average daily Real-Time prices were 7x higher than the first three weeks of the month.

This pattern differed from December's cold snap. December's price spikes were isolated events. January's were sustained by a prolonged polar vortex.

How did this volatility translate to arbitrage opportunity?

Day-Ahead TB1 spreads averaged $181/MW/day in January. Real-Time spreads reached $141/MW/day.

These were the highest spreads since June 2025's summer peak. But the nature of the opportunity differed.

Unusually, Day-Ahead prices were often more volatile than Real-Time prices. System operators tend to forecast conservatively during cold weather, as demand becomes harder to predict at extreme low temperatures. School and business closures during the storm likely compounded forecast errors. On January 27, PJM's forecasted load exceeded actual load by 10 GW during the morning peak. These aggressive load forecasts pushed Day-Ahead prices higher than Real-Time, as the market priced in scarcity that did not always materialize.

On several days from January 26-29, Day-Ahead prices exceeded Real-Time. Batteries that committed in the Day-Ahead market would have captured higher spreads than those relying on Real-Time alone.

This is the opposite of the typical pattern. In most months, Real-Time volatility exceeds Day-Ahead. January 2026 rewarded batteries with Day-Ahead market participation.

Regulation prices were especially high and volatile

Regulation continued to clear far higher than other ancillary services. Monthly average Regulation prices reached $139/MW/h, compared to $4/MW/h for synchronized and primary reserves.

The spread between Regulation and energy widened in January too. Regulation cleared 108% higher than the month prior and 137% higher YoY. This continues a trend since October's Regulation market redesign, which has seen Regulation consistently clear above energy prices.

What drove Regulation prices during ramp hours?

5-minute Regulation prices spiked during morning and evening ramps. Average prices during ramp hours reached $167/MW/h in January 2026, compared to $64/MW/h in January 2025.

The highest 5-minute prices exceeded $1,700/MW/h during evening ramp hours. PJM co-optimizes energy and ancillary services, meaning resources qualified for Regulation were likely tied up providing energy as prices spiked during load ramps. This left limited qualified capacity for Regulation, particularly as the service remains under-subscribed relative to pre-October levels.

Batteries qualified for Regulation captured outsized returns during these windows. The combination of elevated average prices and extreme intraday spikes made January 2026 one of the strongest Regulation months on record.

Prices spiked even though demand was not unprecedented

Winter Storm Fern pushed PJM prices to extremes. But comparable demand earlier in the month and in January 2025 cleared at a fraction of these prices.

At net loads around 100-120 GW, January 2025 prices clustered below $100/MWh. Pre-storm January 2026 showed a similar pattern.

Post-storm was different. The same net load range produced prices between $200/MWh and $700/MWh.

Average load during the storm period reached 120 GW. This was elevated but not record-breaking. The price response was disproportionate to the demand signal.

The generation mix only partially explains the price spikes

The generation mix was not out of the ordinary. Sources of energy during the storm period aligned with historic periods of high demand.

Gas generation averaged 53 GW during the storm, up 18% from January 2025. Oil generation quadrupled to 3.4 GW as the system called on peaking capacity. Coal ramped to 29 GW, 16% higher than January 2025, even as full-month coal generation was down 9% year-over-year.

With oil units providing multiple GW of energy, they likely set the marginal price during key intervals. Oil-fired generation is expensive, usually ranging from $150-200/MWh. But even oil alone does not explain $800/MWh power.

Fuel prices and forced outages drove the price dislocation

Gas prices spiked alongside the storm. Henry Hub spot prices rose from $2.57/MMBtu in early January to $30/MMBtu on January 23 as constrained pipeline flows and freeze-offs tightened supply.

At $30/MMBtu and typical heat rates, gas-fired generation costs rise to $200-300/MWh. That alone brings marginal costs closer to the $700-800/MWh prices observed during the storm.

Gas prices fell back to around $10/MMBtu by month-end, but power prices remained elevated. While gas at $30/MMBtu explains part of the story, forced outages explain the rest.

Forced outages compounded the fuel cost spike

Forced outages doubled during Winter Storm Fern. They peaked at 19.7 GW on January 26, removing capacity equal to 16% of average storm load.

From January 1-20, forced outages averaged 7.7 GW. From January 21 onward, they averaged 15.7 GW. Planned outages stayed flat throughout.

Gas plants bore the brunt. Constrained pipelines and frozen equipment forced thermal units offline just as heating demand peaked. It's the third time in a decade that cold weather has knocked out large amounts of gas-fired generation in PJM.

Spiking gas prices lifted marginal costs. Forced outages tightened supply. Together, they pushed prices to $700-800/MWh.

Batteries were insulated from both dynamics. They faced no fuel constraints and no freeze-related outages. While thermal generators struggled to stay online, batteries captured the resulting price spreads.

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Winter Storm Fern drove disparate outcomes across PJM hubs

Price volatility was not uniform across PJM's nodes. Transmission constraints and local generation outages created sharp divergences between hubs.