Energy Shots #109:

The New Economics of Power Markets

Previous Energy Shots ‘deep dives’ into power markets have dissected the knock-on effects of increased variable fuel adoption on grid reliability, grid stability, price volatility, and generators’ revenue predictability.

Emerging practices like load flexibility and battery arbitrage — charging battery energy storage systems (BESS) when wholesale power prices are cheap and discharging power storage when prices are rich — are frequently suggested solutions to mitigating wholesale price volatility and its deleterious effects on generators’ revenue planning.

If accurate, one would expect to find quantitative support for these proposed solutions by evaluating wholesale power price trends in balancing areas with high power storage adoption.

• I.e., higher rates of power storage adoption should coincide with indications of increased ‘price stability’ — reduced wholesale price volatility, lower frequency of negative price events, and/or lower power prices at peak load.

However, the data dissected today challenges this assertion — analyzing historical wholesale power prices in balancing areas with high power storage adoption shows reduced price stability, higher frequency of negative price events, and higher peak power prices.

Furthermore, the data behind Energy Shots #109 indicates grid operators and upstream fuel producers will increasingly face region-specific volatility, revenue planning, and reliability challenges from seasonal VRE performance.

Power Storage, VREs v. Wholesale Power Prices

VRE Capacity in Context: VREs represent approximately 40% of the CAISO generation stack compared to approximately 36% for ERCOT, 9% for SPP, and 5.5% for PJM. CAISO has rapidly expanded its battery storage capacity to accommodate renewable intermittency, raising active battery capacity in the CAISO balancing area from fewer than 1 GW in 2020 to over 9 GW in 2023 and 10.5 GW in 2024. PJM’s non-ancillary power storage was last reported at less than 300 MW.

• Recent generation data provides context for CAISO’s power storage relative to PJM — CAISO’s trailing 30-day power storage discharge at peak load averaged approximately 7 GW. PJM’s averaged less than 0.03 GW.

With CAISO’s high rate of power storage adoption as our ‘test’ condition and PJM’s low rate of power storage adoption as our ‘control’ condition, historical hourly wholesale price analysis reveals consistent pattern:

Between 2016-2023, CAISO observed increased volatility in median wholesale power prices, higher frequency of negative power price hours, and higher frequency of ‘high’ power price hours (>$150/MWh) despite US-leading adoption of ‘low marginal cost’ VRE and power storage capacity.

• CAISO’s share of negative power price hours increased from 1.12% in 2021 to 3.42% in 2023. Meanwhile, CAISO’s share of power price hours >$150/MWh increased from 1.00% in 2021 to 2.97% in 2023.

Meanwhile, our ‘control’ PJM analysis reveals comparatively stable volatility in wholesale power prices across seasons, nominal changes to negative power price frequency, and lower rates of power price hours >$150/MWh.

• PJM’s share of negative power price hours increased from 0.01% in 2021 to 0.06% in 2023. PJM’s share of power price hours >$150/MWh fell from 0.90% in 2021 to 0.19% in 2023.

Region-Specific Challenges of Managing Seasonal VREs

Analyzing historical hourly wholesale power prices by ISO shows Mother Nature’s inherent unpredictability poses unique seasonal volatility and risk management challenges to regional grid operators and upstream fuel producers.

For example, readers can observe the consequences of California’s low winter solar output and high summer solar output on those seasons’ wholesale power prices in the graphic above.

Meanwhile, wind contributes the largest share of electricity in SPP, and the ISO shows the highest frequency of negative power price hours across all US ISOs until the three summer months when wind output falls.

• In 2023, SPP’s share of negative power price hours ranged between 6% and 9% for winter (Jan-Mar), spring (Apr-Jun), and Fall (Oct-Dec). During Jul-Sep, these rates fell to 2.9% — a consistent pattern for 2019-2023.

For ERCOT, this seasonal variability appears with peak wind output during low-demand shoulder months (spring/fall), coinciding with the Texas ISO’s highest frequency of negative power price hours.

ERCOT wind output falls during peak demand months (winter/summer), concentrating demand for thermal generation resources into an increasingly narrow band of revenue-generating seasons.

While cofounding variables limit conclusions about the direct relationship between power storage and price stability, historical trends in regional balancing areas’ wholesale power prices clearly exhibit the consequences of increased VRE adoption.

With interconnection queues across US ISOs dominated by solar, wind, and power storage technology, these observed trends indicate that generators will require more robust revenue planning and risk management strategies that consider region-specific challenges posed by 1) regional adoption of intermittent resources and 2) local energy policy.

Readers can request the charts from Energy Shots #109 and send follow-up questions to [email protected].

This commentary contains our views and opinions and is based on information from sources we believe are reliable. This commentary is for informational purposes, should not be considered investment advice, and is not intended as an offer or solicitation concerning the purchase and sale of commodity interests or to serve as the basis for one to decide to execute derivatives or other transactions. This commentary is intended for Mobius clients only and is not considered promotional material.