Phasing Out Coal-Fired Power Plants in Alberta by 2030: Recent Developments

By Babatunde Olateju
Manager, Carbon Capture and Utilization, Alberta Innovates
Surindar Singh
Executive Director, Clean Technology, Alberta Innovates
Jamie McInnis
Portfolio Manager,
Reservoir Simulation and Modelling Research Group,
University of Calgary


The province of Alberta, located in Western Canada (see Figure 1), is regarded as the pillar of Canada’s energy economy. It is home to the third largest oil reserves in the world,1 produces 68% of Canada’s natural gas,2 holds significant renewable energy resources, and is the site of Canada’s first commercial windfarm.3 Yet the most abundant fossil fuel energy resource in Alberta is coal. The energy content of coal in Alberta is greater than the energy content of natural gas and oil combined, including the oil sands.4 Coal-bearing formations underlie 304,000 km2 or 46% of Alberta’s total area, making the formations larger than the United Kingdom. Alberta’s coal resource is estimated to be greater than 2 trillion tonnes.4

FIGURE 1. Location of Alberta in Western Canada

Since the deregulation of the Alberta electricity market in 1996, electricity supply has been dominated by coal. It accounted for 51% of electricity generation in 2015 and 39% of the current generation capacity in the province.5 Alberta’s electricity sector accounted for 17% of its greenhouse gas (GHG) emissions6 in 2013. Coal-fired plants are the primary source of these emissions. Against this backdrop, a newly elected provincial government in May 2015 brought a change to the political leadership and also to the provincial climate change policy. In June 2015, the provincial government introduced bold new changes to the Specified Gas Emitters Regulation (SGER).A The emissions levy was increased from the original $CDN15/tonne (US$11.19) to $CDN30/tonne (US$22.13) by 2017.7 Additionally, a higher performance criterion was put in place: By 2017, emissions intensity must be reduced by 20% from an established baseline, as opposed to the original target of 12%.7 In November 2015, the government articulated the following points relevant to the electricity sector, as part of its Climate Leadership Plan:

  • Mandated phaseout of pollutant emissions from coal-fired plants by 2030.
  • Coal-fired plants will pay $CDN30/tonne for emissions, based on an emissions performance standard, by 2018.
  • Replacement of existing coal-fired plant capacity (6299 MW), with about 4200 MW of renewables (two-thirds of existing coal capacity) and 2100 MW of natural gas (one-third of existing coal capacity), will be achieved by 2030.
  • Thirty percent of Alberta’s electricity generation (MWh) will be from renewables by 2030.8

Keep Hills 3 coal-fired power plant

In November 2016, plans for a capacity market (by 2021) to complement Alberta’s current energy-only market system were announced.9 In the energy-only market system, generators are only compensated for the actual amount of energy (MWh) supplied to the grid. The introduction of a capacity market is intended to strengthen the reliability of supply and stabilize electricity prices, while providing an opportunity for generators to earn revenue by making generating capacity (MW) available to be dispatched when required.

In light of this new era in Alberta’s electricity market, this article aims to address the following questions: (1) What do these changes mean for coal-fired power plants in the context of Alberta’s electricity market? (2) What are the key determining factors for the successful phaseout of coal and what are the implications? (3) Are we living in a post-coal era or is a future coal resurgence possible?

To address these questions, we first need to understand the current basic Alberta economics of electricity generation as it pertains to coal-fired plants.


In Alberta’s wholesale electricity market, the price is determined by supply and demand forces; a price floor of $0/MWh and a price celling of $999/MWh are set in place. The mechanism to determine the price of electricity involves the Alberta Electric System Operator (AESO) using a merit-order system where generators offer bids to supply electricity at various prices (often related to their marginal cost of electricity generation). The AESO dispatches supply bids in ascending order of costs—i.e., the least-cost bid is dispatched first, and so on—to service demand. The last bid dispatched within a one-minute time frame sets the system marginal price (SMP). Finally, the average of the SMP for each minute in a given hour sets the hourly pool price. The hourly pool price is used to compensate all generators that supply electricity in a particular hour.10 An exception occurs when a supply bid was dispatched for only part of an hour, at a price greater than the average price in that hour. In such a case, the AESO pays the supply bid price for that portion of that hour.10

The economics of operating coal-fired plants in Alberta are quite challenging for several reasons. First, to coincide with the oil price shock in the last quarter of 2014, electricity demand weakened (about two-thirds of Alberta’s electricity demand is industrial) as new supply capacity was about to be commissioned.B As a result, the pool price began a steep descent and reached levels (< $CDN20/MWh) not seen in two decades.11 Second, sustained low natural gas prices make gas plants a competitive option relative to coal, particularly for baseload operations. Third, the April 2015 introduction of wind power plants into the merit-order system10,12 added downward pressure on the pool price. Wind plants have near-zero marginal costs and can afford to bid into the market at low energy prices that are uneconomic for coal. With significantly increased renewable penetration anticipated (plants with generally low marginal costs), the downward pressure exerted on prices will likely increase in magnitude. Last, the changes to the SGER resulted in a material increase in the cost of compliance for coal power plants; it is expected to rise from $CDN2/MWh in 2015 to $CDN6/MWh in 2017.13


The difficult economic circumstance of coal-fired plants is not unique to Alberta; it is indicative of a broader trend in electricity markets across North America. For example, both the Electric Reliability Council of Texas (ERCOT) and wholesaler PJMC have low natural gas prices. Additionally, the increased penetration and cost-efficiency of renewables such as wind and solar are reducing the market share and competitiveness of coal significantly.14 A successful phaseout of coal by 2030 must be done in a planned, orderly fashion to ensure the reliability of the grid, affordability of energy prices, and the continued downward trend of GHG emissions in the future. This is dependent on several factors that serve as key determinants of success in the impending phaseout.

Striking a Delicate Balance

The rate at which coal is phased out vis-à-vis the rate at which gas and renewable generators are phased in is a delicate balance that needs to be carefully struck.

There are many implications to this careful balancing act. The phaseout of coal will result in gas becoming the dominant baseload energy generation option. Moreover, due to the intermittency of renewable generators, natural gas peaking plants will increasingly be relied upon to firm up supply; these peaking plants will have attendant GHG emissions during their operation. With this in mind, there is an opportunity for technological innovation that will facilitate the penetration of utility-scale low-carbon energy storage technologies (e.g., pumped hydro, redox flow batteries, sodium sulfur batteries, etc.) in Alberta’s electricity market. Energy storage has the potential to mitigate the intermittency of renewables, without the attendant operational GHG emissions aforementioned. Gas being the anchor baseload generator will also lead to the increased exposure of the grid to the dynamics of natural gas prices which, historically, have been quite volatile. Furthermore, the concentration of electricity supply from one fuel type, i.e., gas, is likely to create the same challenges of phasing out a dominant generation option such as coal. From a GHG perspective, gas-fired plants of today are likely to be the coal-fired plants of tomorrow, as our energy economies become increasingly GHG averse. A portfolio approach that ensures sufficient diversification of the energy supply mix will provide stability for the grid in the future.

The Incentive to Build

In light of the coal phaseout, the need for additional renewable capacity in Alberta’s electricity market cannot be overstated, if the climate leadership objectives8 are to be realized. However, in a low-price electricity market, the incentive to build additional capacity is practically nonexistent. Addressing this issue is quite complex and presents several challenges. The Alberta government has introduced a renewable electricity incentive program (to be carried out by AESO) that will provide support for the addition of 5000 MWD of renewable capacity by 2030. The details of the first auction (400 MW of renewable capacity) have been released by AESO.15 Some key features of the auction include: a competitive bidding process; use of existing transmission or distribution infrastructure; renewable credits provided will be indexed to the pool price, i.e., a contract for difference; and plants must be operational by 2019. As reported by AESO,15, the indexed renewable credits create three possible scenarios that are a function of the (winning) bid priceE in the auction and the pool price of the market.

In the first scenario, if the pool price is lower than the bid price—the government pays the difference to support the project. Second, if the pool price is equal to the bid price—there are no payments made by the government. Last, if the pool price is higher than the bid price—the plant owner pays the government the difference. Going forward, the competitive nature of this entire 5000-MW program and the effective apportioning of the risks involved will be crucial in creating a favorable investment environment, while also making electricity prices affordable.

Genesee 3 Coal Power Plant

Accessing the Opportunity of Change

Alberta’s electricity market is in a state of transition. This fluid state of the market has included competitive auctions for renewable energy generation, along with the planned addition of a capacity market by 2021. The capacity market, depending on the way it is designed, holds significant promise not just in enhancing the reliability of supply, but in incenting innovation. Apart from “traditional” generators (gas, hydro, wind, solar, biomass), nontraditional generators, which have baseload and load following functionalities, with low to zero GHG emissions during operation, are likely to benefit significantly from the revenue certainty a capacity market provides in a carbon-constrained electricity sector. Nontraditional technologies that hold some potential in this regard include commercial technologies such as geothermal power, as well as emerging technologies including next generation small modular nuclear reactors. These technologies create opportunities for innovation and the mitigation of greenhouse gas emissions from the electricity sector.

That said, whether Alberta’s future electricity market will encompass the nontraditional technologies as legitimate participants will become clearer as time progresses.


Some would argue that coal in Alberta has no future and is slowly becoming a relic of the past. This argument is founded on a number of factors, but often, it does not consider that coal is a resource, not just a fuel for electricity. Coal as a resource will remain the same; recovery and production technologies will evolve. The evolution of technology in response to the economic, environmental, and social constraints will be a crucial determinant of the question: Will coal be back? In this light, several technological trends and opportunities are worth highlighting.

In the near term, before the 2030 phaseout, the co-firing of coal with other carbon-neutral feedstock such as biomass, economics permitting, provides an opportunity to lower the cost of compliance of coal-fired plants (due to the reduced GHG emissions) and utilizes potentially stranded coal assets.

The technological development and maturity of carbon capture and sequestration as well as underground coal gasification, considering their cost effectiveness, environmental performance, and social acceptability, has the potential to introduce new life into coal for the production of fuels; for example, hydrogen, synthesis gas, dimethyl ether, and others. Carbon conversion technologies that transform CO2 into a value-added product such as fuel or cement introduce additional potential for the environmentally sustainable use of coal. Finally, coal can be used in non-combustion applications. Current efforts are being made to extract rare earth metals from coal,16 which enable crucial functionalities in renewable technologies and other technology platforms such as consumer electronics and aerospace. New materials produced from coal, such as carbon foam,F are alternative uses of coal that could be sustained in a low-carbon era.


For the phaseout of coal to be conducted successfully without adverse impacts on Alberta’s grid, it must be undertaken in a careful, deliberate, and orderly manner. Despite the need for new capacity to come online to replace coal-fired plants, the effective apportioning of the risks involved should be carefully considered. The future concentration of supply on one fuel type (i.e., gas), with limited diversification of the supply mix, is likely to create the same challenges currently being experienced in phasing out coal-fired plants, as energy economies become increasingly GHG adverse. Finally, we must remember that technology rose to the occasion to find ways to access and utilize coal during the Industrial Revolution. Technological innovation will be vital if coal is to have a place in an energy future with heightened environmental consciousness.G


  • A. The SGER was originally introduced in 2007. It required large emitters (≥100,000 tonnes CO2e/yr) to reduce their emission intensity against an established baseline, earn emission offsets or performance credits, or pay a levy of $CDN15/tonne into a Climate Change and Emissions Management Fund. The 2007 SGER is available at:
  • B. Alberta’s largest gas-fired plant (800 MW of capacity) began commercial operation in March 2015.
  • C. PJM is the wholesale electricity market for all or parts of several northeastern states in the U.S. More information is available at:
  • D. More information on the Renewable Electricity Program is available at:
  • E. The bid price is, ideally, the lowest possible price the project developer can accept to advance the project.
  • F. CFOAM® carbon foam and CSTONE are enabling technologies for a host of next-generation material systems and components. More information is available at:
  • G. The views expressed are that of the authors and do not represent the opinions of Alberta Innovates or the University of Calgary.


  1. Canadian Association of Petroleum Producers (CAPP). (2016). Canada’s petroleum resources,
  2. Alberta Energy Regulator (AER). (2016). ST98-2016: Alberta’s energy reserves 2015 and supply & demand outlook 2016–2025. Executive summary,
  3. Canadian Wind Energy Association (CANWEA). (2016). Wind energy in Alberta,
  4. Alberta Innovates Energy and Environment Solutions, Canadian Clean Power Coalition. (2013). In-situ coal gasification in Alberta—Technology and value proposition: Final outcomes report,
  5. Alberta Energy. (2016). Energy statistics: Electricity supply,
  6. Government of Alberta. (2016). Alberta’s current emissions,
  7. Osler, Hoskin & Harcourt LLP. (2016, 15 April). Carbon and greenhouse gas legislation in Alberta,
  8. Government of Alberta. (2016). Climate Leadership Plan—Ending coal pollution,
  9. Alberta Electric System Operator (AESO). (2016). Capacity market transition,
  10. EDC Associates Ltd. (2016). Quarterly forecast update – Second quarter 2016,
  11. Varcoe, C. (2016, 9 July). Alberta’s power market in turmoil as prices hit 20-year lows and demand falls. Calgary Herald,
  12. Market Surveillance Administrator. (2015). Market share offer control, 2015.
  13. Leach, A., & Tombe, T. (2016, August). Power play: The termination of Alberta’s PPAs. University of Calgary, School of Public Policy Communique, 8(11),
  14. Schlissel, D.A. (2016, 16 September). A sustained coal recovery? “When you get there, there’s no there”. Institute for Energy Economics and Financial Analysis,
  15. Alberta Electric System Operator (AESO). (2016). First competition,
  16. Rozelle, P.L., Khadilkar, A.B., Pulati, N., Soundarrajan, N., Kilma, M.S., Mosser, M.M., Miller, C.E., & Pisupati, S.V. (2016). A study on removal of rare earth elements from U.S. coal byproducts by ion exchange. Metallurgical and Materials Transactions, 3, 6–17.


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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