Alberta’s First Clean Power Call Realizes Record Prices

The election of the Alberta New Democratic Party with a majority government in May of 2015 heralded the introduction of wide-ranging reforms to the Alberta electricity market. Electricity in Alberta has responsibility, in a largely fossil fuel system, for a high percentage of provincial CO2 emissions. As a result, the Alberta Government’s Climate Leadership Plan1 has, as arguably its most important objective, the reduction of GHG emissions from the sector.

Specific policy prescriptions to reduce emissions from the sector reflected in the Plan include:

  • an economy-wide carbon levy
  • phasing out coal-fired generation
  • increasing renewables generation
  • promoting energy efficiency
  • increasing the role of distributed energy resources

All of these policy prescriptions, to one degree or another, are being put into action. With the introduction of these changes, the Alberta Electric System Operator (AESO) conducted an assessment of whether Alberta’s energy only market design was expected to result in sufficient investment to ensure continued system reliability in light of the changes and their potential impact on electricity market dynamics.

The AESO concluded that the status quo was not expected to be sustainable and recommended the introduction of a capacity mechanism to improve reliability, particularly during the coal phase-out. The government accepted the AESO’s recommendation and directed that a capacity mechanism be designed and introduced into Alberta’s market framework.

For purposes of this summary, I will briefly touch on developments on the accelerated early retirement of coal plants initiative, with the balance of the document addressing the approach taken to facilitate development of renewable generation.

The Climate Leadership Plan requires the accelerated phase out of the entire coal-fired generation fleet by the end of 2030. Alberta’s supply mix includes approximately 6000MW of coal-fired capacity. The fleet is of mixed vintage and, as a result, includes both legacy plants built prior to deregulation and merchant plants built after the Alberta market was restructured. Especially, for newer plants, the early retirement prescription would see some owners with stranded investments as these plants could have otherwise operated post 2030. Compensation has been agreed to by the government that will see unit owners paid $1.36B.

In addition to the accelerated, regulated phase-out of coal power, the government announced a “30 by 30” target for renewable energy. Rather than relying on market forces to determine replacement capacity for the retired coal generating plants, the government mandated that 30 per cent of electricity (energy) used in Alberta come from renewable sources by 2030. The government has pegged this renewable energy objective at 5000MW, in terms of targeted installed capacity.

A market approach presented difficulties in meeting this objective. Low-carbon investments present special problems for markets, particularly in terms of making the investment in renewables-based generation attractive relative to investment in natural gas based generation, whose levelized costs and fixed costs are lower than low carbon alternatives.

In response to this challenge, the government announced a clean power call program. A clean power call is an open, competitive request for proposals from renewable generators to determine the long-term contract price required to build a specified amount of renewable generation.

The long-term contracting mechanism chosen was a contract for difference or “CfD”. The CfD pays the difference between the market-clearing price and the long-term price needed to make the investment to build the power plant, as determined in the clean power call. The winning bid in the clean power call is typically referred to as the “strike price”.

CfDs stabilize revenues for renewable developers at a fixed level over the 20 year contract term, thereby reducing commercial risk. If the market-clearing price is lower than the strike price, the CfD counterparty, in this case the AESO, pays a top-up. If the market clears above the strike price, the generator pays back the difference to the AESO.

The quality of the CfD, including its term, the enduring nature of private law contract certainty and counterparty credit quality, will all drive perceived risk and ultimate cost of investments.

The AESO was charged by the Alberta Government with procuring the renewable energy to meet the Climate Leadership Plan objectives. The AESO established the first procurement round and auction process. The process was called the Renewable Electricity Program or “REP” and called for bids on 400MW of capacity. The results of the bids from the first REP auction were released on December 13, 2017.

Four wind projects were selected totaling 596MW, with prices ranging from $30.90 to $43.30/MWh with a weighted average of $37.00/MWh. These prices are record setting and were so attractive that the AESO procured an additional 196 MW above its intended 400 MW target.

The winning bidders include Capital Power Corporation (201 MW), EDP Renewables Canada Ltd (248 MW) and Enel Green Power Canada Inc. (two projects: 115MW and 31 MW). Capital Power is Alberta-based whereas Enel and EDP are large, multi-national energy companies based in Italy and Portugal, respectively. All three winners are large balance sheet entities with likely access to capital at extremely competitive rates.

By all accounts, the REP results are a huge success. The realized prices are likely the result of one or a combination of: contract term length, counterparty credit rating, declining capital cost for wind installations, improving capacity utilization rates, capital structure and cost of capital. They do not include transmission costs beyond the direct interconnection.   Certainly, a realized price of $31/MWh suggests extremely low capital costs, improving capacity factors, high leverage and extremely low financing costs.   By way of comparison, Ontario’s procurement program in March of 2016 resulted in a realized price of $85/MWh for 300 MW of wind power.

Alberta’s wholesale electricity prices have been low as compared to historic levels. The average wholesale price in 2017 was $22/MWh. At those prices, Alberta consumers would be required to “top-up” generator revenues however, wholesale prices are predicted to rise in 2018 to the $60/MWh range due to announced coal retirements. As a result, in the short-term, generators may be paying back to Alberta consumers any revenues realized above the CfD strike price.

In terms of market impacts, increasing amounts of subsidized renewable generation with zero marginal costs can change market-pricing dynamics resulting in more price volatility, fewer middle priced hours in the merit order and lower priced hours, resulting in lower average prices.   These are only potential impacts however. As the Province moves to its 5000MW target, there is a higher risk prices will be chronically low, resulting in the renewable resource cannibalizing itself.

Directionally, the introduction of more renewables will impact the relative dispatch order and affect investment decisions, potentially displacing more efficient gas-fired generation in favour of more flexible but less efficient alternatives. Using incentives to force fit renewables into the supply mix will result in emission reductions that might otherwise not occur or take longer to occur if left to market forces.

The economic efficiency of these subsidized incremental reductions can be measured as an abatement cost – the incremental cost incurred by society divided by the CO2 reduction achieved. The incremental cost can be determined by netting the estimated avoided thermal production costs from the contract price and the CO2 reduction can be determined from the avoided thermal emissions.

Using a simplistic calculation, the estimated abatement cost of the renewable incentive at $37.00/MWh is roughly $50.00/ per tonne of CO2. The carbon price in Alberta for 2018 is $30/ tonne CO2. While the investment is relatively higher than the current social cost of carbon, prior estimates of abatement costs using historic levelized cost estimates for wind technology would have yielded abatement costs in excess of $100/ tonne CO2. Additionally, this calculation used a natural gas price of $2/GJ and should gas prices increase, the abatement cost decreases, ultimately reaching zero at $5/GJ.

In conclusion, it remains to be seen whether subsequent auctions will realize prices at this historically low level or whether the winning bidders’ investments in the first REP auction will be financially successful. It is safe to say however that the first REP auction, utilizing a market-based procurement approach, produced a first generation of renewable generation build out at the lowest possible cost.

*Bob Heggie is the Chief Executive of the Alberta Utilities Commission.

  1. Government of Alberta, Climate Leadership Plan (Edmonton: Alberta Environment and Parks, 20 November 2015), online: <>.

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