By Kent D. Howie and Alan L. Ross, Borden Ladner Gervais LLP
Alberta continued to rapidly overhaul its electricity market, announcing several decisions during November 2016 that will have significant impacts on the structure and operations of the Alberta electricity market. The announcements are all intended to help achieve Alberta’s stated objectives that by 2030 (i) there will be no pollution from coal-fired power generation in Alberta, as all coal-fired plants (approx. 6,300 MW) will either be phased out or be pollution free by then, and (ii) 30% of electricity used in Alberta will be generated from renewable sources – the so-called “30 by 30” policy. These two objectives are an integral part of Alberta’s broader Climate Leadership Plan.
Competitive renewable power procurement
Alberta announced in November that it will hold its first renewable power procurement in 2017. It will be the first of many procurements, as the Alberta Government has committed to provide the financial support required for 5,000 MW of renewable capacity to be added in Alberta by 2030.
The 2017 competitive procurement will be for 400 MW, and will be executed in a three stage competitive process with winning projects having a 2019 in-service date. The procurement process begins in Q1 of 2017, and will progress as follows:
• Request for Expressions of Interest (REOI) — a 4-6 week process (Q1 2017) during which industry can provide feedback on the competition without obligation. This aspect is focused on assessing interest in the overall process.
• Request for Qualifications (RFQ) — a 4-6 month process (Q2 and Q3 2017) to determine on a pass/fail basis, which bidders are qualified to proceed to the final stage. At this stage, bidders will be required to pay a non-refundable qualification fee and demonstrate their qualifications for: (i) project eligibility (i.e. meets the definition of “renewable”, is located in Alberta, is 5 MW or greater and is likely to meet the specified in-service date); (ii) financial strength and capacity; and (iii) technical capability.
• Request for Proposals (RFP) — a 2-3 month process (Q4 2017) during which qualified bidders must provide bid security and submit their final binding offers (i.e. bid price). Successful bidders will be selected based on lowest price.
The procurement will result in winning bidders receiving financial support in the form of a 20 year Renewable Electricity Support Agreement (RESA) with the Alberta Electric System Operator (AESO). The key financial support in the RESA will be an indexed renewable energy certificate (REC) which, in essence, is a contract for differences linked to the Alberta power pool price for electricity. RECs will be automatically adjusted so that when pool prices rise, the support to be paid falls and if the pool price rises above the bidder’s strike price, the bidder must pay the difference to the AESO. The intent is that successful bidders will not bear the Alberta pool price risk over the term of their RESA but, in return, will forego windfall profits in times of high pool prices. The RESA will be the key agreement upon which developers will seek financing for their renewable projects.
Successful bidders will ultimately be determined based solely on the economics of their respective projects and on a fuel-neutral basis, with wind, solar, hydro or other renewables all able to participate.
New capacity market
A key question that stakeholders in the Alberta electricity market have been asking for the past year is whether or not Alberta’s energy-only merchant power market is sufficient for the Province to achieve its stated policy of phasing out approximately 6300 MW of coal-fired power by 2030 and replacing it with renewable generation (2/3) and gas-fired generation (1/3). Until this past month, the Province has been saying “yes it is”, and has been firmly committed to maintaining the Alberta market in its current form as an energy-only market. This past month the Province changed its mind, and announced that by 2021 the energy-only market will now be changed to a capacity market. The new capacity market will provide generators with a market in which to compete to sell their electricity, like they have in Alberta today, plus a market in which to compete for payments to keep generation capacity available to produce electricity when needed.
Energy-only Versus Capacity Market?
Currently, Alberta operates Canada’s only merchant power market through which all electricity, whether generated in Alberta or imported, is exchanged in a fair, efficient and openly competitive manner using an economic merit order system – the Power Pool.
Generation in Alberta is competitive, with generators determining the form of energy they will convert into the electricity they will offer into the Power Pool. If dispatched, the generators are paid the competitively determined Power Pool Price for the hour in which they are delivering their electricity into the grid. The Power Pool is now energy-only in that the generators are paid based on the electricity they produce based solely on the Power Pool Price. That Power Pool Price fluctuates over time based on the cost of generation and the economic principles of supply and demand. Since 2014, Power Pool Prices have plummeted in Alberta to record lows of under $20 per MWh. For a more detailed description of the Alberta Electricity Market and its Power Pool see New Opportunities in the Alberta Electricity Market – A BLG Overview at http://www.blg.com/en/newsandpublications/new-opportunities-in-the-alberta-electricity-market.
Unlike an energy-only market, in a capacity market generators are also compensated throughout the term of a power contract for having the capacity to generate electricity, even if they may not be actually generating electricity. Investors in generation projects like a capacity market because a contract for capacity helps them to recover their fixed capital costs even in times of low Power Pool Prices or if their power is not being dispatched in Alberta because it is too expensive.
Why the Change in Alberta Policy?
To ensure that there is new renewable generation in place to replace the phased out coal generation, the Province has committed to provide the financial support described above in a competitive procurement for new renewable projects. Of course, renewable energy is variable and needs to be firmed, often by gas-fired generation. In addition, the Alberta coal phase-out plan contemplated that gas-fired generation would replace 1/3 of the coal being phased out. If one adds in load growth, it is estimated that 9000 MW of new gas-fired power is required by 2030. The Province and the AESO have always maintained that these new gas-fired projects would be built by developers who would be prepared to take or manage their Power Pool Price risk in the energy-only Alberta market – the way that new gas-fired projects have been built since 1996 in Alberta. Simply put, the Province believed that the gas-fired power would show up as coal got phased out, without the Province providing long term contracts or capacity payments to incent developers to build these projects. Accordingly, the “sanctity” of the energy-only market alone was something the Province was married to – at least until this past month.
A close reading of the Province’s announcement helps one to understand why there has been a change in Alberta policy. The Province reached a conclusion that equity investors and project financiers required electricity price stability and the revenue certainty provided by a capacity market for new non-renewable projects to be built. Without this kind of revenue certainty and stability, sufficient non-renewable power projects would not get built in Alberta. The Province was not prepared to count on the energy-only market to send the necessary price signal in time for the gas-fired plants to be built for coal’s planned phase out. Those price signals would only come if power supply became tight in Alberta such that there was a reliability risk and more price volatility and price spikes in the Power Pool during peak hours, something the Province did not think Alberta consumers would accept. This change to a capacity market was also recommended by the AESO, who concluded that the current energy-only market would not ensure that Alberta has a reliable electricity system in the future due to a reluctance of developers to invest in energy-only markets.
The New Capacity Market
Alberta will now transition to an Alberta electricity market that has two separate markets. A market in which generators compete to sell electricity, and a market in which generators compete for payments to keep generation capacity available to generate electricity when it is required. Generators will have a stream of revenue for capacity and another stream of revenue for the electricity that they sell in the market. Like the PJM Market, Alberta will have both an energy and a capacity market.
This announcement should not impact the first procurement for renewable power that is described above because the Alberta capacity market will not be in place until after 2019, when the successful renewable projects from the first procurement must already be in-service. Future procurements may require changes to the extent that a renewable project may be eligible for capacity payments.
The AESO will plan, determine, approve and administer the capacity contracts to procure the capacity required to meet Alberta’s electricity demands according to the following timetable:
2017 - Stakeholder engagement to determine design;
2018 - Incorporation of design into ISO rules, contracts and/or legislation as required;
2019 - First procurement begins; and
2020/21 – First contracts awarded.
New gas-fired power project developers have welcomed the revenue certainty that the new capacity market will bring for them in Alberta. There are a number of gas-fired projects permitted in Alberta, though it is expected that other projects will be initiated and expedited by developers so that they can be ready in time to participate in a 2019 procurement. It is also expected that coal to gas conversion will be pursued by the owners of some of the coal plants that are being phased out in Alberta.
Cap on power rates for small consumers
Alberta also announced last month that by June 2017, it will put in place a cap or rate ceiling to ensure that Albertans opting for the Regulated Rate Option (“RRO”) will not pay more than 6.8 cents per kWh for electricity. The RRO is available to small customers (residential and small commercial) in Alberta who consume less than 250,000 kWh per annum, and who do not choose to sign a contract with a competitive retailer. The RRO price is set periodically by the Alberta Utilities Commission. It is presently about 3.8 cents per kWh in Calgary during this period of historic low electricity prices in Alberta – other areas like Edmonton are within a cent of the Calgary RRO. It has been as high as 15 cents since RRO was first implemented in 2002. The 6.8 cent ceiling price proposed by the Province will apply until June 2021.
It is important to note that it is the retail price charged to consumers, and not the wholesale or Power Pool Price that is paid to generators, that is being capped – yes, think government subsidy for consumers. In providing such a cap, Alberta seems to be trying to get out in front of consumer/voter fears that, like other Provinces, Alberta’s phase out of coal and move to renewables will result in very high power prices for Albertans.
The role of providing long-term fixed prices for consumers has generally been performed in Alberta by competitive retailers. Though the Province stated that consumers are still free to contract with these competitive retailers, those opting for RRO will have the price protection afforded by the Province’s cap. Not surprisingly, many competitive retailers are wondering whether their business model has been undercut by the actions of the Province in now mitigating power price risk for residential and small commercial customers.
The announcement is light on detail, including the mechanics of how the cap will work and how it will be funded by the Province. The Minister of Energy for Alberta will lead a consultation with distributors, RRO providers, retailers and consumers beginning this month.
Compensation paid to coal plant owners
The Province also announced in November that it had reached an agreement to compensate the owners of the six coal units (Genesee 1, 2 and 3, Keephills 3 and Sheerness 1 and 2) that are to be phased out early to meet Alberta’s objective of having no pollution from coal plants by 2030. Agreements were reached with Capital Power, TransAlta and Atco Power that will see the Province make annual payments totaling $1.1 billion dollars (in 2016 dollars) to these owners between now and 2030. According to the Province, the payments are to be funded using money received from the carbon levies Alberta is imposing on industrial emitters, and not by consumer electricity rates. The payments were calculated based on the net book value of these units and the years that their life will be stranded due to the coal phase out policy decision. A discount factor was applied to reflect that some of the assets can be reused, for example for a coal to gas conversion. This announcement ended speculation and debate over whether or not any compensation would or should be paid to the coal plant owners.
These November changes provide a pathway for Alberta to achieve its objectives to phase out coal generation and have 30% of electricity generated from renewable sources by 2030. 2017 will see the commencement of Alberta’s first competitive renewable procurement, a cap on electricity prices, and work begin on the design of Alberta’s new capacity market. There is still a lot of work to be done, but the Alberta announcements in November show that the Government of Alberta is prepared to make the difficult electricity market decisions necessary to ensure that Alberta will be using only lower-carbon and zero-carbon forms of generation in 2030.
About the authors: Kent D. Howie and Alan L. Ross are partners in the Calgary Office of Borden Ladner Gervais LLP and practice in its Electricity Markets Group.
Originally posted November 24 on the blog site of Borden Ladner Gervais LLP. Reprinted with permission.