March 2022 Alberta Electricity Newsletter: Implications of a Wind-Hinging Market

March 31, 2022
Will Chow

Alberta has become a strongly wind-hinging market. With 2,269 MW of installed capacity, momentary capacity factors that have reached 96%, and Alberta load ranging from approximately 7,600 MW to 11,700 MW, wind power can at times provide for a significant portion of Alberta internal load. Wind power in the province is also highly correlated; wind farms are closely situated in pockets of regions that exhibit high wind speeds translating to high overall capacity factors; and, when the wind blows in Alberta it really blows. The market is experiencing a wind-hinging effect. Our data shows this. The image on this page is an example.

The graph shows aggregate wind is highly variable with large numbers of near-zero wind energy output and large amount of near-maximum capacity factor hours (i.e., AB wind displays an unusually high degree of “all or nothing” wind output).

The corresponding pricing impact also seems to follow a pattern of windy hours with market clearing prices near marginal cost of the remaining thermal units; non-windy hours quickly reaching scarcity prices.

Power Advisory forecasts thousands of incremental MWs of wind capacity to be added by 2040 - meaning that, if market design and framework hold steady, this phenomenon will persist and perhaps become more acute.

Alberta’s energy-only market enables market participants to be highly responsive to changes in supply mix and the corresponding pricing impact. In the short term and from a static efficiency perspective, one way that market participants appear to be responding is by committing their generation units (placing units on long lead time) based on their wind forecasts. By doing so, the market thus far has avoided supply shortfall (when the wind is not available) and supply surplus (during high wind conditions). This approach seems to be offering an acceptable level of supply adequacy and supply surplus, as long as the wind forecast holds.

Power Advisory observes there to be up to 9 gas-fired and coal-fired steam generation units totalling more than 3,000 MW of maximum capability that are offered in accordance to this strategy. Each of these units requires a long lead time to start up and sync to the grid. The units exhibiting this behaviour are the thermal (many now converted to either gas or dual-fuel) units and as they age may be more difficult to recall to service with short notice without significant investments in major maintenance and overhaul.

Long lead time units have always functioned in a space between economic and physical withholding. Economic withholding is a feature of the Alberta market while there exists much stronger regulation and ISO Rules to manage physical withholding. As units are withdrawn in the medium term[1] for commercial reasons by being placed into long lead time, expect the MSA, AESO, and policy makers to observe the phenomenon more closely.

Historically, unit self commitment has worked well because net-demand (inclusive of renewable output) has been predictable on a medium-term basis (24-72 hours ahead). Predictability and competitive forces have enabled market-oriented mechanisms to ensure short term supply adequacy.

ISO Rules allow for the system operator to direct units on from a state of long lead time for the purpose of maintaining reliability and supply adequacy. To date, the AESO has never taken such action. If the magnitude of wind forecast error outpaces the market-enabled margin for error and system operators are forced to direct units for reliability unit commitment, expect the AESO and policy makers to review the requirements in the ISO Rules, including criteria for directing units.

The future impact of wind generation and unit commitment will depend largely on the future of wind forecasting. Expect forecasts to continue to improve through better weather modelling and more high-quality wind data. However, more wind generation will magnify the pricing impact and MW volumes subject to forecast error.

The two images on the following page are a glance at the wind forecast errors from March 2015 (top) and March 2021 (bottom), taken from the AESO website. Mean absolute percent errors have fallen (11.8% to 8.1%). Also, and perhaps more importantly, average range between min and max forecast have fallen (684MW in 2015 to 344MW in 2021). The min/max is likely a key data point to inform market participants decisions regarding unit commitment and is also a data input for the system operator to assess short and medium-term supply adequacy.

As a large portion of the generation fleet uses long lead times to react to market signals and wind forecasts, the remaining margin left to address supply adequacy (and supply surplus) falls to the rest of the dispatchable merit order. This margin is approximately the sum of: (1) remaining peaking plants; (2) delta between the MSG and MC of the remaining online units; (3) remaining ATC; and (4) demand response.

As long as extreme events in the forecast error are smaller than the above noted margin, unit self commitment will continue to enable a pure market signal to ensure medium-term supply adequacy. Current ISO Rules related to directing long lead time assets to ensure a day(s)-ahead supply adequacy are not sufficient to function as a regularly used market design mechanism. Chronic use of long lead time directives would erode market signals and confidence in the energy-only market. Power Advisory expects this wind forecast based unit commitment to be monitored closely by the entire sector and possible future adjustments to the market design to consider price caps and floors, more organized signals to coordinate unit commitment, and possibly the exploration of more centralized unit commitment.

Power Advisory is excited to welcome Will Chow to its team. Fresh from the AESO system control center, Will brings a depth of understanding in real-time operations and energy markets.

[1] Power system operators and market designers have traditionally broken adequacy into short and long term.Power Advisory suggests that supply adequacy should be thought of in three timeframes: short-term adequacy encompassing what is available immediately for dispatch (including dispatched operating reserves); medium-term adequacy including short term adequacy plus long lead time units and transmission outages impacting generation; long-term adequacy addressing the investment signal and resources yet to be built.