In early November, last year, Alberta’s plan to phase out coal appeared to be headed for an ugly showdown with utility companies.
Electricity sellers like Enmax, owned by the City of Calgary, were insisting on their right to walk away from money losing Power Purchase Arrangements (PPAs) with coal plants and the province was challenging that right in court.
A PPA is an arrangement to purchase power from a particular generating facility and bid it into a power pool.
It made for an odd picture. On the one hand, the NDP government had changed the rules for its carbon levy on large industrial emitters and deliberately increased the cost of coal-fired production relative to cleaner gas-fired production. On the other hand, the same government was trying to force utilities to continue paying the owners of coal-fired plants through PPAs, even though other sources of electricity were becoming more economical.
The picture got even more odd with reports the government might use retroactive legislation if court action failed. In a province desperate for new energy investment to replace coal generation, taking such a drastic step against existing industry players seemed strange indeed.
And then came a policy announcement on Nov. 22 — and a promise of more to come. Over the course of the next seven days, the picture changed dramatically.
At first, with only a consumer price cap announced, critics protested loudly saying this was a government backing blindly into worse and worse decisions. But as each successive announcement added to the rest, it became obvious that this was a comprehensive plan — one that had been in the works for months.
Still, it will take years to turn the planned reforms into a new design for Alberta’s electrical markets. And even though the major tools have been chosen, the exact design could still favour some priorities over others.
Marg McCuaig-Boyd, the NDP energy minister, said in an interview on Dec. 20 that the government is looking for “affordability, predictability and stability.”
Those qualities are important in any electrical system. But in a system that’s moving from coal to renewables, other qualities like flexibility may be just as important — and more challenging to achieve.
Depending on which priorities are emphasized in the design, the new market structure could help the province make the leap from coal to renewable energy – or burden it with another round of infrastructure that has to be phased out.
Big reforms – and a lot of little details
Major changes can be sketched out quickly, but getting the full picture requires a look back at the history as well as a look behind the industry terminology to see how the pieces actually work.
First, Alberta is replacing its unusual ‘energy-only market’ with a combination of markets. The existing energy market will continue to set the price generators receive for actual electricity sold, and a new ‘capacity market’ will reward investors for keeping electrical generation at the ready.
Secondly, coal plants will shut down in 2030, regardless of whether they’re still eligible and economical to operate under federal rules and the owners will be compensated.
And thirdly, the PPA issue appears to be resolving as well — with a compromise that splits expected financial losses between the government and PPA holders.
In a press release that kicked off these changes last November, NDP Premier Rachel Notley said, “Our government inherited a volatile electricity system that doesn’t look out for consumers or work for investors.”
McCuaig-Boyd said these difficulties were not new, but “the previous government had received advice from the ISO [independent system operator] that the energy-only market wasn’t working as well.”
To understand the proposed reforms and whether they can fix the problems of the existing electricity market, it helps to look back even further at the tightly controlled system it replaced.
“…Renewables are still the odd thing that we accommodate, as opposed to the central thing we plan to depend on.” –Mike Jacobs
From cost-of-service to a competitive pricing pool
Before 1995, Alberta’s electricity market was a regulated system. Producers were paid what a government agency decided was necessary and fair, based on expected demand, the cost to build enough generating facilities and the costs to operate them.
If producers and the provincial government can agree on costs, a cost-of-service model like this works well — as long as planners get their demand forecasts right. They want to avoid electricity shortages, but oversupply is a problem too because the facilities have costs whether they operate or not. If predicted demand doesn’t materialize, those fixed costs can’t be spread out as widely and instead the price has to go up.
Under the regulated system, several large utility companies supplied electricity each within their own region. But without a way to trade electricity between regions, some resources might be underused, driving prices up overall. So in 1996, the province created a competitive power pool to meet overall demand more efficiently.
This power pool, sometimes called ‘the hourly pricing pool’, is not the same thing as the Balancing Pool that’s been in the news about PPAs. David Gray, an energy economist based in Edmonton, explained how the competitive power pool compares offers from different generation plants to determine whose power will be bought and at what price.
“Much of it is offered in at zero [dollars] because they are from either co-generation plants or renewable energy that has no control over when they produce,” he said. “And so those get stacked at the bottom, and then on top of that you stack all of the ones that have a positive price to them, and the last one that needs to be called on to satisfy the demand at that time, in that hour, sets the price for the market.”
This system ensures the cheapest available power is used first and more expensive power is used only when needed to meet high demand. As long as there are plenty of low-cost suppliers to choose from, consumer prices stay low.
More players means lower prices – until one player holds the last card
A market like this doesn’t work well with only a few players. In 2000, the government took the bidding rights away from the few owners of the existing plants and sold them in an auction of PPAs.
“It’s the person that holds the [PPA] that receives the money from the power pool,” Gray said. “But then they have to in turn pay the plant operator.”
Even if the power doesn’t sell, the plant owner still gets paid for fixed costs, so the PPA holders generally want to make sure their offers are accepted so they have some revenue to pay the plant owners.
But sometimes bidders might be tempted to hold back their power offers to force the price higher and boost their revenue. To prevent such artificial shortages, there is a ‘must offer, must comply’ rule saying the power must be made available.
Still, bidders can offer at such a high price the power won’t be bought. “So they have to offer the output of the plants into the market,” said Gray. “But they can do what’s called ‘economic withholding’, which is you offer them in, at or near the price cap of a dollar a kilowatt-hour.”
If one company controls the output from enough generating units, they can use economic withholding on some units output to tighten up supply and get a better price for the rest.
Price spikes were common back in 2013 and 2014. But when the Sundance 1 and 2 coal units west of Edmonton came back online after repairs and the new 800-megawatt (MW) Shepard Energy Centre east of Calgary started operating, there were too many supply options for any company to run up the prices.
Gray noted that the Shepard plant’s owner, Enmax, is in an interesting position because it’s both a buyer and a supplier of power. “It’s one of the reasons why the market is in the tank, is because the Shepard Gas Plant is price competitive with all of the coal plants, and so it’s added to effectively what’s base load generation.”
Soon though, with some coal plants scheduled to retire under federal rules and others becoming uneconomical, supply is bound to tighten up again.
For every action there’s an awkward reaction
Volatile prices were designed into the old system. The idea was as electricity demand pushed up against supply, the price would rise and tell investors to build new generating facilities.
Trouble was, as soon as any new generating capacity came online, it would push prices back down.
That made it hard for the province to attract investment for a shift away from coal. Increasing the carbon levy would increase the cost of coal-fired generation and raise the price of electricity — but if investors built new generating facilities, they could expect the price to fall again, driven down by their own new supply.
Meanwhile, as long as competition succeeded in keeping electricity prices low, the rising carbon levy made coal plants uneconomical to run – yet the plant owners still had the right to be paid through PPAs.
Looking at the situation for PPA holders in mid-November, Gray said: “So the problem is that the money they’re receiving from the power pool at the moment is less than the money that they have to pay the plant operators.”
But terms of PPAs gave energy companies an escape clause and Enmax was the first to use it, filing to terminate its Battle River PPA in Dec. 2015. The rules said if a government action made a PPA “unprofitable, or more unprofitable,” a company could get out of its obligations.
But the money-losing PPA would not disappear. It would come back to the Balancing Pool — the agency who ran the initial auction and kept control of unsold PPAs. Those PPAs held in the Balancing Pool worked just like those held by utility companies, except the profits and losses were passed on to consumers through the ‘Balancing Pool allocation’ on electricity bills.
For years, the Balancing Pool has distributed profits from the unsold PPAs it holds. But if enough money-losing PPAs were to be returned, the profits would become losses. And at that point, electricity consumers would be stuck with the bill.
A price cap doesn’t solve the supply problem
The first announcement in the week of electricity market reforms was a consumer price cap, which is reminiscent of the 2000-2001 brownouts in California.
There wasn’t a shortage of generating capacity, but California had a market setting the wholesale electricity price and a cap on the consumer price. When Enron used market power to run up the wholesale price, electricity retailers couldn’t raise their retail prices to cover their power purchases at the market rate. All they could do was buy less power than they needed to keep the lights on.
After the Alberta government’s November announcement, news reports in Calgary quoted Mayor Naheed Nenshi, who said, “In short, they’re regulating the retail price, but not the wholesale price. When governments have tried to do that in the past, it’s really been a recipe for disaster.”
But a YouTube video posted on Nenshi’s YouTube channel of the scrum show that was a shortened quote and Nenshi had also said the government planned to protect utilities — although he did not know how they would do it. He also emphasized the need for caution in planning a new system.
He noted too the PPA situation was still unresolved and could still do a lot of damage to utilities if they were forced to continue under those arrangements.
More stability for both generators and consumers
On Nov. 23, Albertans heard about the new capacity market. That measure could go a long way to protecting both utilities and consumers — from shortages at least.
Through an auction, the government will pay for generating capacity to be available over a certain period. By guaranteeing some return just for being ready to supply electricity, the auction should be able to attract investment even while prices stay low.
Once the capacity market is running, investors will have a new source of revenue to cover their fixed costs, so they won’t need to earn money through higher prices for electricity itself.
Since price spikes won’t be needed, economic withholding will no longer be justifiable and economist Trevor Tombe, expects the new market design will include a rule preventing it. “Right now, we allow [generators] to exercise market power to increase the price such that they can earn above their costs of production, because in our current system that’s the only way in which you can recoup your fixed investment,” Tombe said following the announcements.
Investors were happy to hear about the capacity market, according to McCuaig-Boyd. “We heard very early after we announced that decision from investors that they’re very familiar with it and they like it, so I think it’s going to be a good-news story,” she said.
The right system to meet government goals – but have they got the goals right?
Capacity markets are common across North America, but each one has to be designed to work within the demands and assets of a particular region. In Alberta, consultations and planning are expected to take years, with the market starting to operate by 2021.
One risk in this system, as with the regulated system, is setting the demand estimates too high.
Future capacity will be determined, Tombe said, “in part by decisions of the government agency that will coordinate this new market, and it may be that they overbuild, or they get more than enough capacity, and so that will add cost to the system in the whole.”
But unlike a regulated system, where overbuilding puts costs onto consumers and taxpayers over the lifetime of any excess generation projects, a capacity market creates obligations only for specific contract periods. In its report recommending the capacity market, Alberta’s Wholesale Electricity Market Transition, the Alberta Electric System Operator (AESO) writes that excessive costs from overbuilding could occur “for short periods of time,” which may be three to five years.
The capacity market can help to contain the risk of overbuilding electrical generation. But transmission — the infrastructure that moves power from generators to consumers — is a different story, since in Alberta that part of the system is still regulated to avoid any restrictions on the flow of available electricity. But as McCuaig-Boyd said, Alberta already has “a pretty robust transmission system,” and new generation can be tied in with minimal new construction.
But there’s another risk. Mike Jacobs, of U.S. Union of Concerned Scientists, said in an interview that the capacity market design might underestimate the possible role of renewables and the scale of change needed to support that role.
If the design emphasizes traditional fuel driven generation to handle peak demand, he explained, it could actually discourage alternative ways of balancing supply with demand, such as adding storage for those times when wind or solar are unavailable or installing home automation to run things like water heaters in off-peak hours.
If the design focuses too much on reliability and not enough on flexibility, the province might escape its dependence on coal only to find the replacement infrastructure also going quickly out of date.
“It can work either way,” Jacobs said. “I mean, in a lot of ways the capacity market rules can be used for good or evil.”
He mentioned several assumptions to question, such as whether capacity is really needed around the clock or only for short periods, whether the full demand must be met from within the system or whether — for example — the wind might be blowing in another part of the Prairies and whether a seemingly reliable type of generation could be vulnerable to risks such as seasonal fuel shortages.
Hopefully these issues won’t be overlooked as Alberta seeks to learn from other jurisdictions’ experiences with capacity markets. McCuaig-Boyd said the biggest challenge of the redesign is “just getting all the pieces in place and we’re mapping things out with the AESO. We’ve got till 2030 to do this, so it’s not like it has to be done overnight.”
The capacity market announcement set the direction for securing future generation, but that still left the question of what would happen with existing coal-fired plants. In November, two announcements addressed that issue.
First, the provincial government would use the carbon levy revenue from large industrial emitters to compensate owners of six coal-fired plants ordered to shut down by 2030. That early shutdown takes away as much as three decades of operation from newer plants, since federal shutdown rules use a 50-year lifetime rather than a specific year.
Tombe said the compensation replaces income the owners could otherwise have earned by operating longer. The deal helps reassure companies considering future investment in the province. Otherwise, he said, “It would effectively have been expropriation for some of these units.”
Since the compensation comes out of the industrial carbon levy, it doesn’t impose any additional cost on consumers.
Also in November, Capital Power and the province announced an agreement allowing the PPA for the coal-fired unit Sundance C, located near Edmonton, to come back into the Balancing Pool. Presumably that will mean some future losses for the Balancing Pool, but Capital Power has agreed to pay the Balancing Pool $39-million, apparently to make up for some of these losses.
The government also announced tentative agreements with two other PPA holders. In an interview shortly after the announcements, Tombe said, “It looks like if that settlement structure continues, then the PPA holders will pay for the market losses associated with low prices, and the government will end up paying for most but perhaps not all of the policy-related costs.”
In other words, the investors who bought PPAs took a risk that prices might fall, and they ended up paying for it. But they won’t have to pay the new costs that the government created by changing the carbon levy.
Where do we go from here – and how far?
From the agreements made public so far, it appears the provincial government is prepared to accept some costs — on behalf of all citizens — in order to reach its climate goals rather than putting all the burden on the industry and risk driving away investment.
The capacity market appears to be another investor friendly move, but one that also aims to deliver stable prices for consumers through a time of transition.
“So with our coal phaseout and Climate Leadership Plan, this is the system that’s going to provide the most affordability, predictability and stability,” said McCuaig-Boyd.
The minister mentioned several times that the government has received good advice from the AESO, and the press release about the capacity market includes a link to the AESO report.
One one hand, that advice is likely to be invaluable, considering how many interacting parts there are in an electrical market.
“Even from the first day,” the energy minister added, “I have always found electricity the most complex file I have.”
But as the design details are worked out, the government will need to make sure planners bring not only experience but also vision.
Jacobs has seen several jurisdictions work through changes in their electrical systems in his time as an energy analyst.
“The lesson I have from my experience is that most of the people at the table doing the design and commenting on it have not accepted the proposition that we’re doing this for high levels of renewables,” he said. “That throughout the engineering community, renewables are still the odd thing that we accommodate, as opposed to the central thing we plan to depend on.”
The editor responsible for this article is Nina Grossman and can be reached at firstname.lastname@example.org.