In February 2021, Winter Storm Uri impacted the Texas electric grid and power systems leading to catastrophic failures including multi-day blackouts and the tragic loss of human lives. Renewable opponents supporting Texas vast oil and gas industries seized the opportunity to blame renewables and promote fossil fuels, despite the fact that failures in the gas delivery system and cascading power outages that further impacted the gas delivery system were primarily to blame.
To clarify the situation, to seek definitive answers, and to guide policymaking, the Texas Public Utility Commission commissioned The University of Texas to study the blackouts and the causes.
They concluded:
“The failure of the electricity and natural gas systems serving Texas before and during Winter Storm Uri in February 2021 had no single cause. While the 2021 storm did
not set records for the lowest recorded temperatures in many parts of the state, it
caused generation outages and a loss of electricity service to Texas customers several
times more severe than winter events leading to electric service disruptions in
December 1989 and February 2011. The 2021 event exceeded prior events with
respect to both the number and capacity of generation unit outages, the maximum load shed (power demand reduction) and number of customers affected, the lowest
experienced grid frequency (indicating a high level of grid instability), the amount of
natural gas generation experiencing fuel shortages, and the duration of electric grid
operations under emergency conditions associated with load shed and blackout for
customers. The financial ramifications of the 2021 event are in the billions of dollars,
likely orders of magnitude larger than the financial impacts of the 1989 and 2011
blackouts.
Factors contributing to the electricity blackouts of February 15-18, 2021, include the
following:
- All types of generation technologies failed. All types of power plants were
impacted by the winter storm. Certain power plants within each category of
technologies (natural gas-fired power plants, coal power plants, nuclear
reactors, wind generation, and solar generation facilities) failed to operate at
their expected electricity generation output levels. - Grid conditions deteriorated rapidly early in February 15 leading to blackouts.
So much power plant capacity was lost relative to the record electricity
demand that ERCOT was forced to shed load to avoid a catastrophic failure.
From noon on February 14 to noon on February 15, the amount of offline
wind capacity increased from 14,600 MW to 18,300 MW (+3,700 MW).2
Offline natural gas capacity increased from 12,000 MW to 25,000 MW
(+13,000 MW). Offline coal capacity increased from 1,500 MW to 4,500 MW
(+3,000 MW). Offline nuclear capacity increased from 0 MW to 1,300 MW,
and offline solar capacity increased from 500 MW to 1100 MW (+600 MW),
for a total loss of 24,600 MW in a single 24-hour period. - Demand forecasts for severe winter storms were too low. ERCOT’s most
extreme winter scenario underestimated demand relative to what actually
happened by about 9,600 MW, about 14%. - Weather forecasts failed to appreciate the severity of the storm. Weather
models were unable to accurately forecast the timing (within one to two
days) and severity of extreme cold weather, including that from a polar
vortex. - Planned generator outages were high, but not much higher than assumed in
planning scenarios. Total planned outage capacity was about 4,930 MW, or
about 900 MW higher than in ERCOT’s “Forecasted Season Peak Load”
scenario. - Power plants listed a wide variety of reasons for going offline throughout the
event. 3 Reasons for power plant failures include “weather-related” issues
(30,000 MW, ~167 units), “equipment issues” (5,600 MW, 146 units), “fuel
limitations” (6,700 MW, 131 units), “transmission and substation outages”
(1,900 MW, 18 units), and “frequency issues” (1,800 MW, 8 units). 4 - Some power generators were inadequately weatherized; they reported a level
of winter preparedness that turned out to be inadequate to the actual
conditions experienced. The outage, or derating, of several power plants
occurred at temperatures above their stated minimum temperature ratings. - Failures within the natural gas system exacerbated electricity problems.
Natural gas production, storage, and distribution facilities failed to provide
the full amount of fuel demanded by natural gas power plants. Failures
included direct freezing of natural gas equipment and failing to inform their
electric utilities of critical electrically-driven components. Dry gas production
dropped 85% from early February to February 16, with up to 2/3 of
processing plants in the Permian Basin experiencing an outage. - Failures within the natural gas system began prior to electrical outages. Days
before ERCOT called for blackouts, natural gas was already being curtailed to
some natural gas consumers, including power plants. - Some critical natural gas infrastructure was enrolled in ERCOT’s emergency
response program. Data from market participants indicates that 67 locations
(meters) were in both the generator fuel supply chain and enrolled in
ERCOT’s voluntary Emergency Response Service program (ERS), which would
have cut power to them when those programs were called upon on February - At least five locations that later identified themselves to the electric
utility as critical natural gas infrastructure were enrolled in the ERS program. - Natural gas in storage was limited. Underground natural gas storage
facilities were operating at maximum withdrawal rates and reached
unprecedently-low levels of working gas, indicating that the storage system
was pushed to its maximum capability.
Read the full report here: https://energy.utexas.edu/sites/default/files/UTAustin%20%282021%29%20EventsFebruary2021TexasBlackout%2020210714.pdf