TODAY’S STUDY: New Energy Beat Old Energy In The Polar Vortex

Performance review: nuclear, fossil fuels, and renewables during the 2019 Polar Vortex

February 2019 (Wood Mackenzie Power and Renewables)

Key Takeaways

-The 2019 Polar Vortex weather event was not as severe as the one in 2014, particularly for the gas market

-Generator and fuel supply outages were much lower compared to 2014

-On the whole, each asset class ran exactly as designed/expected.

-Wind generation was intermittent and generally anti-correlated to load, performing well during portions of the event and displacing fossil fuels

-Solar power exhibited expected diurnal intermittency, helping with average on-peak demand, but not during the morning and evening peak loads

-Coal plants load-followed when needed, ran baseload when needed, and "absorbed" high wind generation by backing down when needed

-Gas and Hydro/PS plants provided flexibility, ramping as needed and serving peak loads

-Nuclear fleet ran at >98% capacity factor, with one outage at the Salem plant in New Jersey

-In regions with high levels of wind capacity, (MISO, SPP) -- wind generation is often is a better indicator of directional changes in power prices than load

-High wind generation = lower prices; low wind generation = higher prices

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-Transmission dynamics create big price differentials within and between ISO markets

-MISO Central/North was the bullseye of the Polar Vortex in terms of load impacts and high power prices. Meanwhile, limited transmission capacity meant MISO South power prices remained low throughout.

-As the cold abated in SPP, it was also unable to provide support to MISO and PJM due to transmission limitations

-Replaying the 2019 polar vortex conditions with 100% renewables:

-Any mix of wind and solar to serve load would require long-duration storage or optimization of multiple “stages” of shorter duration

-Assuming no transmission constraints and unfettered access to a wider pool of resources, the market would require firm generation for durations ranging from 18 and 40 hours to backstop renewable intermittency

-With long stretches of storage ‘charge’ and ‘discharge’, multi-day forecasting of intermittent output would be critical

-Existing Nuclear reduces the magnitude of hourly generation imbalances

-Distributed or demand-side technologies may help reduce peak load requirements and the need for utility-scale energy storage

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The 2019 Polar Vortex has similarities to the 2014 version, but several key differences, particularly in the gas market, mitigated its impacts

-In 2014, the deep freeze extended further south in the US into larger gas demand centers

-The extreme cold in 2019 was more localized to the Upper Midwest (lower gas demand region)

-While not escaping the cold entirely, New York and New England were more akin to “normal cold” during this latest event, rather than “extreme cold” experienced in MISO Central/North

-The 2014 event was more prolonged, lasting several days, whereas 2019 was acute but followed by a rapid warm-up

-In 2019, grid operators were better prepared, and there were fewer power plant outages

-A warm end of 2018 assuaged fears of low end-of-season natural gas storage levels…

-…so the fears of natural gas stock out were minimal in 2019 compared to 2014, which had multi-day record cold and large storage withdrawals.

-Weekly gas withdrawal hit a high of 288 bcf in 2014 (with six total withdrawals in the 200s) during the winter of ‘13/14, while we estimate the latest event at 246 bcf. For comparison, the early January 2018 Bomb Cyclone saw an all-time record 359 bcf withdrawal.

-As such, gas market volatility remained largely in check with muted basis compared to 2014

-By extension, power prices also remained in check with a few exceptions

-In the analysis presented in this Insight:

-We analyze data published by the US RTOs primarily affected by the Polar Vortex

-We refer to the combination of MISO, SPP, PJM, NYISO, and ISONE as the ‘Aggregate footprint’

-Due to disparate weather patterns across MISO (North + Central vs. South), a limited impact of the Polar Vortex on the South region, and limited transfer capability between these two bulk regions, our references to “MISO” refer to the aggregate North + Central regions, except where otherwise noted…

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What would 100% renewables look like during the 2019 Polar Vortex event?

Using actual market data we scale up to a 100% renewable energy mix over the week

1.Align real-world market loads, wind and solar generation

2.Scale up real-world wind and solar hourly shapes to a theoretical 100% renewable mix under three scenarios: 50-50% of wind & solar…75% wind & 25% solar…25% solar & 75% wind

1.Calculate the resulting “net load” to be served after wind and solar generation

2.Determine the longest streak of consecutive hours where net load is either all positive or all negative – this indicates the level of battery storage required to arbitrage periods of over-generation into periods of system need

3.Determine the max generation output of wind and solar as an estimate for the installed capacity need

4.Replicate this same analysis, but consider nuclear generation towards achieving 100% “clean”

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Key notes: This analysis assumes zero transmission, voltage, or spinning inertia constraints on a combined aggregate system of MISO/SPP/PJM/NYISO/ISO-NE...In reality, the ICAP values of wind/solar will be higher than those estimated as neither fleet produced at 100% during the week…This does not consider imbalances or analysis of the rest of the year…MISO and NY do not publish solar generation data. As a proxy we averaged SPP + PJM for MISO solar and used ISO-NE for NY solar

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