Storm Uri was, in many ways, the perfect storm. Larger and colder than those that caused the hard freezes of 1989 and 2011; temperatures fell 50°F lower than normal and triggered severe weather warnings in all of Texas’ 254 counties.
The tragic human toll and significant financial losses suffered have seen the public demand answers. Who will be held accountable? And who should have to pay?
Rather than pointing fingers, focusing on the facts can help find areas for improvement.
So, why were these conditions so problematic for Texas’ power system?
Texas taken by storm
To assess the outages, we need to understand the role of ERCOT.
The Electricity Reliability Council of Texas operates as a 501(c)(4) non-profit organization and exists to maintain grid stability and help market participants fulfill customers’ electric needs. It is a completely objective organization and does not own assets or have a vested financial interest in the value of energy.
Instead, ERCOT orchestrates activities between power generators, retailers, and transmission owners with oversight from PUCT (Public Utilities Commission of Texas).
Given this independent position, and the fact that the polar vortex drove demand to 75GWs - 8 GWs higher than ERCOT’s peak winter forecast and 20 GW above the February average – is it reasonable to expect the council to have acted differently?
We believe that there are additional factors to consider.
Unlike other ISO/RTO’s, ERCOT operates an energy-only market, without a supporting forward capacity or resource adequacy market.
When ERCOT developed new market power and resource adequacy rules in 2006, it was believed an energy-only market would provide the necessary price signals to ensure long-term resource investments, while avoiding additional costs in consumer electricity rates.
Up until recently, that thinking held true. ERCOT has largely balanced supply and demand to avoid a scenario that was fatal to grid performance.
However, the market composition is now under scrutiny because it has not provided the financial incentive required to cope with “black swan” events like Winter Storm Uri.
A moment of weakness
ERCOT’s reserve margin (generation capacity beyond forecast needs) has also come into question.
ERCOT’s generation capacity capability is based on summer readiness forecasts, not winter readiness; the reserve margin of 15% was calculated using 2021 summer expectations and an estimated peak of 77 GWs.
A secondary consequence of the market approach is that several generation assets were down in preparation for peak summer demand when the storm hit. Demand is historically low in February, so many generators use the month to ensure their units are ready to operate at maximum capacity when demand and energy prices are highest. In Texas, that’s in summertime.
Uri’s extreme operating conditions also impacted the generation fleet that was available. Natural gas generators, who supply 46% of ERCOT’s total energy capacity, had to contend with frozen well heads, pipeline pressure problems, and fuel handling constraints. Texas will need to address the critical interdependency between the natural gas (Railroad Commission) and power (PUCT) industries to support the State’s growing energy requirements.
Additionally, coal piles and fuel handling equipment froze, impacting coal units. Frozen feedwater equipment and pressure sensors tripped a large nuclear unit. Wind turbines froze over, and solar panels were covered by snow.
ERCOT has come under fire for the fleet’s lack of winterization, but there is currently no regulatory obligation on generators to carry out expensive upgrades. The council does not have the authority to enforce the issue, and in a competitive market, generation owners find it difficult to justify the costs of winterization for rare events.
Solution? Implement a forward performance capacity market
Capacity markets secure the appropriate amount of supply needed to meet long-term forecast demand while providing financial incentives for generators to maintain reliable supply.
Compensating reliable generators empowers them to cover costs related to fuel security, equipment upgrades and winterization; while financial penalties linked to poor performance serve as incentive to ensure that capacity is available.
Invested in Interconnection
ERCOT has limited interconnections with surrounding systems and markets, an intentional choice that eliminates federal regulatory oversight. In the wake of the storm, it has been suggested ERCOT should invest in transmission interconnections to send and receive power when the grid in Texas, and neighboring markets, is stressed.
Unfortunately, Texas’ neighboring power markets (SPP and MISO) were both experiencing operational problems during Uri; they had also issued emergency orders and were in no position to help. Even if one or both markets could have aided ERCOT, the scale of interconnection capacity required to mitigate the emergency would not have been a practical consideration.
Solution? Decentralize or Incentivize
Instead of interconnection, invest in smart grid technology, battery storage and energy management applications to create a more decentralized grid that allows for dynamic grid management. Developing micro-grids would help make it easier to balance supply and demand across more targeted subsections of the grid.
Alternatively, extending demand resource programs to the retail level can lower demand. At $9Kwh ($9,000 MWh wholesale), customers have a significant incentive to reduce demand, which can avoid a total power cut and address overall stress on the grid.
Blame and frustration are inevitable, but they can also be useful if they bring the facts into focus. Solutions such as new market incentives, investment in grid technologies, and greater coordination between State regulators, ERCOT & market participants, can help make the Texas grid a robust and reliable power system. The storm has revealed weaknesses in the entire system, and provided an opportunity to strengthen the market model, so that we can weather the storms to come.
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