Snapshots of a Cold Snap

Alberta Power System Data & Observations on the Jan 2024 Cold Weather Event

Introduction

Alberta experienced extreme cold weather from January 9th to 15th, 2024, and, as the cold front approached, I thought it would be interesting to take periodic data snapshots to understand how the power supply mix evolved during this period using data and screen shots from the Alberta Electric System Operator (AESO) data dashboard. This article tells the story and summarizes my observations.

Evolution of the Supply Mix

I think the way the supply mix changed over this period clearly demonstrates the critical importance of dispatchable generation for ensuring system reliability during extreme weather. The current renewable generation technologies provide value during normal operating conditions, but we need to ensure we have adequate dispatchable generation resources to maintain system reliability under all operating conditions, and particularly during extreme cold and hot conditions.

As the cold front moved in, initially wind generation provided some much needed energy as wind speeds were high and then solar contributed when things stabilized and the clouds cleared, but gas-fired generation kept the lights on and heaters and furnace fans running throughout the event.

During the course of this weather event, Alberta set a new winter peak demand record and the system reached Energy Emergency Alert level 3 (EEA3) on four consecutive days (see the Appendix for EEA definitions), narrowly avoiding controlled load shedding on January 13th. Pretty action packed, to say the least! Here’s the chronology of the cold front:

January 9th and 10th: As the cold front moved in and temperatures dropped, we had windy and cloudy conditions. This provided good wind generation but no solar and helped moderate prices as demand rose with decreasing temperatures.

January 11th: Alberta set a new demand peak demand record of 12,384 MW. Fortunately, we had about 1000 MW of wind on the system during this time, which was very helpful and demonstrated the value of resource diversity.

January 12th: The system was in EEA3 for 5 hours and came very close to supply shortfall conditions, but the AESO was able to meet demand with operating reserves and imported power from BC and Saskatchewan.

January 13th: The system was in EEA3 for 5 hours again, coming within tens of MW of supply shortfall and the AESO narrowly avoided controlled load shedding (rolling blackouts) due to the following factors:

• the AESO directed all available operating reserves to provide energy

• a public appeal using the emergency public broadcast system resulted in a demand reduction of about 200 MW

• there were no generation or transmission forced outages

• there were no natural gas supply disruptions

• emergency energy imports from Saskatchewan and BC bridged the gap between in-province supply and demand for several hours - we were fortunate they had surplus energy as both provinces were also experiencing high demand due to the cold weather

Here’s a screenshot showing all contingency reserves directed for energy and generation about 340 MW less than demand. This was the first time I’ve seen a situation like this in my 25 years working with power systems. Shocking.

January 14th: The system was in EEA3 for 6.5 hours, but the AESO was able to meet demand with operating reserves and imported power from BC and Saskatchewan and no emergency public appeal was required.

January 15th: The cold front started to move out and the system was briefly in EEA3 for one hour during the morning ramp while temperature was still -30 C, but system conditions quickly returned to normal, after which the skies were clear and wind and solar began contributing energy as temperatures began to rise and cold front moved out.

So, to say it was an eventful week would be an understatement.

Key Observations

For me, there were several takeaways from this period of extreme cold:

• Alberta’s power system is experiencing the effects of several years of GHG policy uncertainty that has slowed or stopped investment in new gas-fired generation and our growing demand is now starting to catch up to our installed dispatchable generation capacity. We need electricity policy certainty ASAP, both federally and provincially, to ensure ongoing investment in dispatchable generation and transmission as our load continues to grow.

• The availability and reliability of the natural gas supply and transportation system in Alberta is CRITICAL to power system reliability because we are currently dependent on gas-fired generation for reliability and supply security. If we had experienced any gas supply or transportation disruptions during this cold period, it would have literally been lights out. The tight coupling of the natural gas and power systems is a significant operational risk we need to explicitly acknowledge and plan for.

• Wind and solar generation add good resource diversity to the power system, but we will always require dependable, dispatchable baseload and peaking generation to take whatever nature provides and fill in the MW to ensure reliability under all operating conditions, and especially during extreme hot and cold conditions.

• Interconnections to other jurisdictions provide significant reliability value. However, unless those jurisdictions are planning for and reserving firm capacity for you under emergency operating conditions and you have agreements in place for firm capacity under emergency operating conditions, then relying on interconnections during emergency operating conditions is a strategy of hope because the other jurisdictions will likely be facing the same operating conditions and any energy you get will be on a voluntary “best efforts” basis.

• The value of demand side management is something that requires much more focus in power system planning for the energy transition. Albertans responded immediately to the emergency public appeal and reduced demand by 200 MW, so just imagine how much demand we could save around the clock if people started using power more efficiently and wasting less. MWs of demand avoided are far cheaper than building new generation in the vast majority of cases, and we should make demand side management a key part of power system planning and electricity rate design whenever possible.

The Story in Data

I took data snapshots each day from the AESO’s website to document how the supply mix evolved over the 7 day extreme cold period. Below is the data in tabular form followed by a series of supply mix screenshots.

A few things that stood out for me in the data:

• Gas provided between 7500 and 9300 MW as our baseload supply source

• The small capacity of coal we have left (820 MW) supplied between 7% and 8% of demand throughout the cold weather period

• Wind generation contributed as weather changed, but contributed little to no energy during the stable period of the cold front, due to a combination of low wind speeds and equipment low temperature operating limits

• Solar did not appear to be materially affected by cold temperatures

• Energy storage, while small (190 MW installed capacity), played a role in providing contingency reserves and frequency response support in the event of generation or transmission outages during the critical operational hours.

APPENDIX - Energy Emergency Alert Definitions

EEA0 – System normal, adequate supply to meet demand

EEA1 – All available generation resources are in use.

• The AESO is experiencing conditions where all available generation resources are committed to meet firm load, firm transactions, and reserve commitments, and is concerned about sustaining its required contingency reserve.

• Non-firm wholesale energy sales, other than those that are recallable to meet reserve requirements, have been curtailed.

EEA2 – Load management procedures in effect.

• The AESO is no longer able to provide its expected energy requirements and is energy deficient.

• The AESO has implemented its operating plans to mitigate emergencies.

• The AESO is still able to maintain minimum contingency reserve requirements.

EEA3 – Firm load interruption is imminent or in progress.

• The AESO is unable to meet minimum contingency reserve requirements.