Grid's Wild Ride

A battery in Texas earned more in four hours last August than some gas plants made all month. In PJM, the spread between midday and evening prices has widened by a third since 2020. CAISO routinely swings from paying generators to take power at noon to charging $1,000-plus by dinnertime. Across American wholesale electricity markets, the old rhythms of price formation—predictable peaks in afternoon, troughs at night, gentle seasonal variation—have shattered into something far more volatile and far more consequential.

This isn't temporary market noise. It's the signature of a structural transformation in how the grid operates, who profits from it, and what kinds of resources can survive the new regime. For utilities, traders, and policymakers, understanding these patterns isn't academic—it's existential.

The Death of the Load-Following Price

For decades, locational marginal prices tracked load with reassuring predictability. Prices rose as air conditioners hummed in the afternoon, fell as offices emptied, bottomed out overnight. Seasonal variation reflected heating and cooling demand. Traders could set their watches by it.

That template has been torn up. Midday prices now frequently clear *below* overnight prices as solar generation floods the market. The "duck curve" that CAISO engineers first identified a decade ago has migrated east—PJM and MISO now show the same midday price depression, the same steep evening ramp as solar output crashes faster than demand declines.

FERC's March 2025 Staff Report quantifies the shift: compared to the 2018-2022 average, wholesale prices dropped 43% at CAISO's SP15 hub and 56% at ERCOT North. But those averages mask the real story. Price *variance* has exploded. ERCOT's standard deviation roughly doubled over the same period. The average is lower; the swings are wilder.

The 4 PM to 8 PM window has become the market's danger zone—and its opportunity. As solar output plummets while demand holds, prices spike with a ferocity that the old system never produced. Evening ramps now routinely deliver the highest hourly prices of the day, sometimes of the month.

Wholesale Price Collapse Since 2018-2022

Wholesale Price Collapse Since 2018-2022. Source: FERC March 2025 Staff Report. Average wholesale prices have plummeted—but the calm averages hide a storm of volatility underneath.

Then there's the floor falling out entirely. Negative prices—generators paying to produce—occur with increasing regularity during high renewable output hours. This isn't system malfunction; it's production tax credit economics expressing themselves in market clearing. A wind farm with PTCs earns federal revenue regardless of the LMP, making it rational to bid negative and keep spinning.

The Physics Behind the Chaos

Three forces combine to drive this volatility, and none is likely to reverse.

First, renewable generation with zero marginal cost compresses prices during output hours. Every MWh of wind or solar that clears the market displaces some higher-cost thermal unit. When conditions align—sunny afternoon, windy night—prices approach zero or go negative. The more renewable capacity on the system, the more frequent these conditions become.

Second, reduced thermal fleet flexibility limits price recovery when renewables fade. The coal retirements of the past decade removed baseload capacity that once set stable prices across broad swaths of the day. The remaining gas fleet faces higher utilization, steeper ramp rates, and more frequent cycling—none of which it was designed for. When the sun sets and gas plants scramble to cover the gap, prices spike.

Third, scarcity pricing during tight conditions produces extreme peaks that were once rare. ERCOT's administrative scarcity pricing can push offers to $5,000/MWh—the systemwide cap. PJM's operating reserve demand curves produce similar effects. Even brief shortages lasting minutes produce price spikes that ripple through daily averages.

The Evening Price Canyon

The Evening Price Canyon. Source: CAISO market data (illustrative summer day). The 'duck curve' has become a canyon—prices plunge at solar peak, then spike 40x higher by evening.

The EIA's analysis of ERCOT puts it starkly: "Variability in reserves can trigger the application of scarcity pricing, which can result in large increases in projected market prices as reserves shrink." Translation: the closer the system runs to its edge, the wilder the price swings.

Who Wins, Who Bleeds

This volatility is not a neutral phenomenon. It's redistributing billions of dollars annually from one set of market participants to another—and the implications for resource adequacy are profound.

Storage resources are the clear beneficiaries. Batteries earn revenue by charging during low-price hours and discharging during peaks. Greater price spreads mean greater arbitrage opportunities. A 4-hour battery capturing $50/MWh spreads earns roughly $75,000 per MW annually from energy arbitrage alone—before considering ancillary services or capacity payments. When spreads hit $100/MWh, increasingly common in ERCOT and CAISO, that figure doubles.

S&P Global's forward curves tell the story of expectations: ERCOT North and Houston hub pricing for July 2025 sits around $110/MWh on-peak, with August exceeding $167/MWh. Traders are pricing in continued volatility—and storage developers are racing to capture it.

Demand response similarly benefits. Curtailing load during high-price hours once avoided modest premiums over average prices. Now it avoids prices five to ten times daily averages. Industrial customers with operational flexibility can monetize that flexibility at rates unimaginable five years ago.

ERCOT Summer 2025 Forward Prices

ERCOT Summer 2025 Forward Prices. Source: S&P Global forward curves. Traders are betting on extreme summer volatility—August prices 52% higher than July signals expectations of scarcity events.

Baseload generators, by contrast, face a structural squeeze. Plants designed for steady, round-the-clock operation cannot capture high prices during short peaks—they're already running. They sell into depressed midday hours and miss the evening spikes. The economics that once made "always-on" generation valuable have inverted.

Renewable generators confront a more complex picture. High output hours increasingly coincide with low or negative prices, eroding energy revenue per MWh. But installed capacity continues growing, and capacity factors rise with better technology. The net effect depends heavily on contract structure and market design.

The Regional Laboratory

Each major ISO presents a different version of this volatility story, shaped by market design and resource mix.

ERCOT shows the most extreme patterns. The energy-only market design—no capacity payments, all revenue from energy and ancillary services—means generators live and die by volatile energy prices. Prices have ranged from negative $200/MWh to the $5,000/MWh cap within single weeks. The state's ongoing debate over a performance credit mechanism reflects anxiety about whether pure energy-market signals can sustain adequate dispatchable capacity.

CAISO's volatility concentrates in those critical evening hours. The steep ramp from solar peak to evening demand creates the system's tightest conditions. Summer prices routinely exceed $200/MWh between 6 and 9 PM, even as midday prices sometimes go negative. The duck curve has become a canyon.

$75,000

$75,000. What a 4-hour battery earns annually from $50/MWh spreads—before ancillary services or capacity payments. At $100/MWh spreads (increasingly common), this doubles to $150,000.

PJM shows lower absolute volatility—the capacity market provides revenue stability that dampens energy price extremes. But don't mistake lower volatility for low volatility. The spread between midday and evening prices has increased substantially, and the ongoing capacity market reforms under FERC scrutiny could reshape these dynamics.

What to Watch

The volatility regime is set to intensify before it stabilizes, and several factors will determine how it evolves.

Treasury guidance on clean energy tax credits will shape bidding behavior. If IRA incentives continue to make negative-price operation rational for renewables, expect more frequent and deeper price troughs.

FERC's ongoing examination of scarcity pricing under Docket AD21-10 could raise or lower price caps—with direct implications for the magnitude of price spikes and the investment signals they send.

State proceedings on retail rate design will determine who bears wholesale volatility. Real-time pricing programs pass market signals to end users; fixed rates shield customers but concentrate risk on utilities.

And the buildout continues. Every GW of solar added deepens the midday trough. Every GW of storage added compresses the evening spike. The equilibrium point—if one exists—remains years away.

For market participants, the strategic imperative is clear: the resources that thrive will be those that can move—charging when prices crater, discharging when they spike, curtailing when costs exceed value. Flexibility has become the grid's most valuable commodity. Those who can provide it will capture the new volatility premium. Those who can't will watch their business models erode, one price swing at a time.