Lessons learned from the Texas Energy Crisis

In many ways Alberta is the envy of the world in terms of reliability and quality of electric service, but the assumptions that underlie the provision of this service were fundamentally shaken during four frigid days in Texas in February 2021. 

While this shock to the system was felt across North America, the lessons to be learned from Texas are particularly germane to Alberta because of the similarity in deregulated electricity market frameworks. Texas and Alberta are ethe only jurisdictions in North America to utilize an energy only market design. Given the unique similarities, the obvious question is; “What happened in Texas and could it happen in Alberta?”  

The Canadian chapter of the Energy Bar Association recently invited four distinguished speakers to provide insights into the crisis. Pat Wood III and Joe Kelliher, former FERC Chairmen, spoke to the circumstances in Texas while former AEUB Chairman Neil McCrank and former AESO President Dale McMaster joined the panel to discuss the Alberta implications.  The complete program is set out in Appendix A.

All four speakers were integral to the transition in both Texas and Alberta over the past two decades from heavily regulated gas and electric sectors to today’s restructured approach where competition and markets operate together with a modern regulatory approach.  

The Texas Energy Crisis

The historic polar vortex that hit the southern United States in February inflicted a severe cost in Texas – nearly 200 lives lost and property damages over $200 billion. The sub-zero temperatures caused two events that were not anticipated by state regulators:

1. Failure of thermal generating plants due to lack of winterization and limited fuel supply.

2. Unprecedented surge in electricity demand.

Inadequate winterization caused freezing of gas supply and control instruments and, in a system with a winter peak of 66 GW, about 30 GW were unavailable. In its worst case planning, based on the “Groundhog Day” blizzard of 2011, ERCOT, the system planner and operator, had anticipated a loss of 14 GW of thermal plant. 

While wind resources were initially accused of causing the crisis, in fact, even though they experienced some storm related outages, ERCOT had anticipated these outages in its planning and wind resources performed as expected. 

Texas natural gas production dropped 45% from 21.3 Bcf/d in the week prior to the crisis to a low of 11.8 Bcf/d during the crisis. Gas supply was impacted by freezing conditions, however the bigger supply disruption was caused by power being cut to wells, processing plants and compressor stations.

* Bob Heggie is the Chief Executive of the Alberta Utilities Commission. He is also co-chair of the Energy Law Forum and Vice President of the Canadian Chapter of the Energy Bar Association

At the same time that electricity supply was failing, demand for electricity surged as Texans turned up their thermostats. A large portion of Texans rely on low efficiency resistant electric heat in poorly insulated homes and the demand surge caused by the frigid conditions increased demand by 20 GW – roughly one-third of winter peak. Again, this demand surge was not anticipated in the state’s extreme winter planning scenario because planning was based on the 2011 storm.

The large drop in supply together with the surge in demand made it impossible to balance the system without controlled outages. ERCOT requested controlled outages for about 20% of the system. These actions avoided a more catastrophic state-wide blackout. 

Over the four days of the crisis, the shortage between supply and demand averaged 10 GWs. The deficit was so large that the distribution companies could not rotate the outages due to inadequate control systems. The inability to rotate outages was devastating as it left two-thirds of Texans without electricity and water for up to 70 hours.

What Caused the Crisis?

While other factors have been identified as playing a contributing role in the crisis including planned outages, lack of interconnection capacity to other grids, and energy only market/lack of capacity mechanism, these factors played a minor contributing role, if any.

The key insight is that the gas and electric systems in Texas  are deeply integrated and while all units went offline ( wind, gas, coal, nuclear), the largest loss was from natural gas production. As more renewables are added into the grid in the future, the reliance on natural gas during shortage events will increase. 

Going Forward

Texas will need to change the way it plans for extreme weather events. The current practice of planning based on historic worst case may be insufficient due to the unpredictability of extreme weather events that cause multi-point, systemic failure.   Better coordination across responsible regulatory agencies may also be required. Integrating planning and enforcement responsibilities across PUCT, ERCOT and Texas Railroad Commission will ensure winterization of infrastructure and identify critical gas infrastructure that would not be subject to load shed. 

Improved coordination would address the issue of gas production and processing equipment that use electricity being cut off during rolling outages which then cut gas supply leading to generator outages. 

Operationally, the outage management system must be overhauled to allow for rotation of controlled load sheds. 

Lastly, improved communication with the public would likely have led to a smaller demand increase and less loss of life if the public was made aware of emergency procedures. For example, citizens were operating generators or cars in garages to stay warm. 

Lessons for Alberta

The main lesson for Alberta is a functioning market under normal conditions is not a substitute for emergency preparedness and rigorous system planning. The similarities between the Texas and Alberta markets is striking.  In both markets natural gas fueled electricity met approximately half of the total consumer demand. Gas is the dominant resource and will remain that way for many years. A combination of coal retirements and coal to gas conversions will further increase Alberta’s reliance on gas generation by 2023. Unlike Texas however natural gas, not electricity, is the primary source of heat for housing stock. Nevertheless, the deep integration of gas and electricity increases the risk that gas supply outages could severely impact Alberta’s electricity generators. 

While energy markets by design omit the central planning role, the Texas crisis underscored the need for proactive, forward looking planning and emergency preparedness in Alberta, particularly to address extreme weather events. 


The Texas crisis highlighted the critical importance of communication during a crisis in order that Albertans are prepared when electricity, gas and water may not be available for an extended period. Regulatory oversight in Alberta is similarly fractured and greater clarity in roles and responsibilities was recommended to address the increasing interdependence of markets. 

Alberta’s natural gas system is winterized but may not be weatherized. Facilities are designed for cold temperatures. For example, gas wells may have alcohol injected to alleviate freeze-offs and compressors are located inside. Less clear is whether system planning in Alberta takes extreme heat or wildfire risk into account. Regardless of the cause, managing multi-point failures in the gas and electricity systems is critical as climate change and extreme, unpredictable weather events threaten infrastructure more than ever.   

The Texas electricity crisis is a wake up call for all jurisdictions, not just Alberta. The session provided valuable lessons in the hope that the Texas energy crisis is not repeated – anywhere.