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ERCOT
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Energy Risk ReportMay 28, 2020
MAY 2020
Procurement recommendations for commercial, industrial and institutional electricity users
EBWAnalytics.com
Andrew D. Weissman, Editor in Chief
2 Energy Risk Report: ERCOT
ERC OTR E V I E W
ERCOT wholesale power futures are trading unevenly in May. Summer 2021 contracts at
ERCOT North have surged $11.77/MWh (12.7%) since late April, reflecting expectations for
record demand despite COVID-related headwinds. Later-dated deliveries have traded in the
opposite direction, however: the winter 2020-21 strip is down $1.04/MWh (-3.5%) and summer
2021 contracts have slipped $2.65/MWh (-4.1%) month-over-month.
Falling natural gas futures underscore the role of scarcity expectations in ERCOT power
pricing. Summer 2020 deliveries at benchmark Houston Ship Channel are down $0.20/MMBtu
(-9.9%) month-over-month, while the winter 2020-21 strip declined $0.14/MMBtu (-4.7%) and
summer 2021 contracts slipped $0.10/MMBtu (-3.8%) over the same period.
Gas futures have resumed their downward slide due to remarkably well-supplied market
conditions, relatively lackluster demand rebound expectations, and repeated inventory builds.
That summer 2020 electricity futures have surged despite declining anticipated marginal
generator fuel costs reflects the impact of perceived scarcity risks on power pricing.
ERCOT’s final Summer 2020 Seasonal Assessment of Resource Adequacy (SARA) projects
record demand and sufficient reserve capacity in the most-likely scenario. The final
SARA projects peak summer demand of 75.2 GW—marginally above the record set in 2019—
fueled by warmer-than-normal weather and population growth trend.
The grid operator reduced its summer peak demand outlook by 1.6 GW relative to the
preliminary outlook released in March due to COVID-driven demand reductions. In the most-
likely scenario, ERCOT could have about 7.0 GW of spare capacity—equating to a peak reserve
margin of 12.6%.
Despite considerable nameplate reserve capacity, end users could still be exposed to
significant upside price risk. ERCOT cautioned that hotter-than-anticipated normal,
higher-than-normal forced thermal outages or weaker-than-forecast wind output, could all
force the grid operator to declare Energy Emergency Alerts to keep the lights on—implying
ERCOT Anticipates Record Demand This Summer
Key Takeaways
ERCOT projects 12.6% reserve margin this summer.
ERCOT downgraded its final demand estimate due to COVID and does not anticipate reliability challenges in the most-likely scenario.
Extent of upside price risks mitigated, but not eliminated.
Hot weather and weaker-than-expected generator performance could send prices soaring, especially since the scarcity pricing threshold is lower.
Post-2020 summer outlook may loosen further.
A combination of new renewable capacity and likely demand headwinds may reduce summer price risks starting in 2021.
Time Period EBW* Recommendation
Price ($/MWh)
05/28/2020 Trend Past Month
Trend Over Past Year 12-Month Range Year-Ago Actual
Price
Jun-Sep 2020 Buy $78.11 -$2.90 -$5.13 $62.41-$96.78 $111.49
Oct 20-Mar 21 Buy $26.95 $2.73 $2.46 $23.82-$28.99 $25.90
Apr-Dec 2021 Portfolio $43.08 -$0.67 $2.68 $37.23-$47.69 —
Cal 2022 Portfolio $36.55 -$0.14 $2.18 $32.37-$38.51 —
* See Glossary on last page
OUR PROJECTIONS aND RECOMMENDaTIONS
Renewable additions could weaken summertime scarcity risks in the years ahead.
3 Energy Risk Report: ERCOT DO NOT DISTRIBUTE
ERC OTR E V I E W
significant scarcity pricing. The second bullish Operating
Reserve Demand Curve shift this past spring also lowers the
threshold for price spikes.
Nonetheless, the experience of the last several
summers suggests the most-likely outcome is less dire.
The anticipated summer 2020 reserve margin is wider than
the previous two years, which included some scarcity
pricing but generally did not threaten grid reliability.
Contrary to fears, wind output has tended to overperform
during peak demand periods. Thermal generators have
also fine-tuned maintenance practices to ensure maximum
availability during the summer, although social distancing
may have impacted some of those preparations this spring.
History by no means guarantees future performance. Still,
it does at least suggest the most-likely result is several days
of scarcity pricing this summer even if grid reliability is less
threatened.
End users should still minimize exposure to summertime
price spikes—even if COVID demand reductions have
mitigated the extent of upside price risk.
The post-2020 summer outlook could loosen
further. ERCOT’s biennial Capacity, Demand and Reserves
(CDR) Report, also released this month, anticipates peak
summer reserve margins of 17.3% next year and 19.7% the
year after before declining to 14.1% by 2025. The actual
reserve margin may be even wider due to COVID-related
demand growth headwinds.
The latest CDR projections imply easing long-term
summertime scarcity risks. Reserve margin widening is
premised primarily on utility-scale renewables, however, so
a growing share of demand will be met with variable wind
and solar output.
End users should hedge their obligations through
winter 2020-21 and utilize a portfolio strategy for later-
dated deliveries. Ongoing natural gas price weakness has
extended an attractive end user procurement window.
Summer 2020 futures are well-priced now; end users should
hedge their exposure sooner rather than later to avoid
paying an even-larger premium as the market re-focuses on
scarcity risks.
A portfolio approach for post-winter 2020-21 reduces
end user exposure to re-inflated risk premiums driven by
scarcity pricing this summer while also maintaining the
flexibility to capitalize on further downside potential
driven by bearish factors such as a secondary COVID
outbreak, a particularly painful recession or the ongoing
surge of renewable capacity additions. ■
ERCOT North Day-Ahead Peak Futures, March-May 2020, 2H2020, Cal 2021, and Cal 2022
Source: EBW AnalyticsGroup, Bloomberg Source: EBW AnalyticsGroup, Bloomberg
Lost Daily Generation (GWh) from Nuclear Outages in ERCOT, 2020 vs 2019
4 Energy Risk Report: ERCOT DO NOT DISTRIBUTE
ERC OTR E V I E W
ERCOT North Day-Ahead Peak Electricity Prices, 2020 vs 2019 ($/MWh) ERCOT Daily Generation (GWh), 2020 vs 2019
ERCOT North Daily High and Scarcity Prices ($/MWh), Number of Days in June–August, 2016–2019 ERCOT Historical and Projected Reserve Margins, 2015–2020
Houston Ship Channel Natural Gas Hub Basis Differential, 2020 vs 2019 ($/MMBtu) ERCOT Natural Gas and Electricity Prices
Source: EBW AnalyticsGroup, Bloomberg Source: EBW AnalyticsGroup
Source: EBW AnalyticsGroup, Bloomberg Source: ERCOT, NERC
Source: EBW AnalyticsGroup, Bloomberg Source: EBW AnalyticsGroup, Bloomberg
2018
2019
ERCOT North Peak DA ElectricityHouston Ship
Channel NGHouston Ship Channel NGERCOT North Peak DA Electricity Price
Glossary: Our recommendations are made for a hypothetical commercial or industrial end user that consumes large amounts of electricity. With that in mind, end users must decide the timing to cover their electricity requirements.
“Wait” means that in our view prices are elevated and end users can get a better value by waiting for prices to fall.
“Buy” means that in our view prices are cheap relative to their true value, and end users are better served to buy now before prices rise.
“Portfolio” is more of a middle ground reflecting more balanced upside and downside risks. By taking a portfolio approach to procurement, end users cover a portion of requirements regularly to reduce upside risk exposure, but still retain downside potential should prices fall. In this light, a portfolio approach to procurement could be considered a cousin of dollar–cost averaging.
Terms and Conditions This publication is the property of Energy Business Network, LLC (“EBN”). The opinions and views expressed herein are those of the authors and not EBN and are subject to change based on market and other conditions. The articles and analysis are for informational purposes only and neither EBN nor the authors make any representations as to the completeness or accuracy of the information or conclusions stated.
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Eli Z. RubinSenior Energy Analyst
Andrew McCoyEnergy Analyst
Leara KufferExecutive Editor