By Rich Heidorn Jr.

TORONTO — The Association of Power Producers of Ontario’s annual conference attracted about 300 people last week, a sharp drop from past years, when more than 500 attended.

But things are looking up, APPrO President Dave Butters told the gathering. After “a couple of difficult years” in which the group cut its office space in half to save $50,000 annually, he said the group collected a record $830,000 in membership revenue in 2018.

Butters said the group may consider a name change under a business plan it will unveil in about a month to broaden its membership. “We want to be an organization that is broader and wider than just centralized generation,” he said. “We see [distributed energy resources], storage — all these things are potentially opportunities.”

Here are some of the highlights of what we heard.

Alberta also Adding Capacity Market

The Alberta Electric System Operator (AESO) plans to add a capacity auction to its energy-only market in late 2019, with the market operational by 2021. AESO said it is making the change to improve reliability, increase price stability, give generators greater revenue certainty and allow market forces to drive innovation and cost discipline.

AESO has proposed a one-year term for its capacity market, although that could change, said Evan Bahry, executive director of the Independent Power Producers Society of Alberta (IPPSA).

Bahry said Alberta’s market is being challenged by the province’s plan to eliminate coal-fired generation and add 5,000 MW of renewables by 2030. “We’re a thermal market, reliant on coal and natural gas historically; very little hydro,” he said.

The industry also must deal with “a lot of agencies in our marketplace, all of which have their own independent mandates,” he said.

“We in our business make 20-, 30-year investments. Billions of dollars are required to replace retiring assets and to meet future load growth. This requires coherence, requires stability,” Bahry said. “We’re [seeing] greater change … now than we’ve seen in the last 20 years. That’s a lot for investors to digest.”

Harsh Critique from TransAlta Boss

Dawn Farrell, CEO of Calgary-based TransAlta, offered a harsh critique of policymakers and customers.

Of consumers: “They want electricity to be cheap. They don’t want it to be affordable, and they don’t want it to be reasonably priced. They want it cheap. They’ll pay a lot of money for cable, they’ll pay a lot of money for their phones and data streaming and for movies.

Of Alberta’s market: “The new market in Alberta has 500 rules. That’s not a market. Markets don’t have 500 rules.”

She said policymakers should take a lesson from the large regional transmission grids in the U.S. “Electricity flows wherever it wants to flow, and you get the benefits of the economies of scale there. And they get the benefits of the different resources in the different jurisdictions. You think about Canada and for some reason there’s these invisible lines in between the provinces, which are just political constructs.”

She said the failure to take advantage of transmission dooms innovative ideas, such as the proposed pump storage project at TransAlta’s 355-MW Brazeau hydroelectric plant. “It’s too big for Alberta. … It would be great for Alberta and Saskatchewan.”

“As a country,” she lamented, “we do not have our best interests at heart. We do not think about competitiveness.”

New England Faces Another Tight Winter

Robert Ethier, vice president of market operations for ISO-NE, discussed the RTO’s challenges with insufficient winter gas supplies and states’ reluctance to allow new pipelines or transmission. Asked about a proposed transmission line from Quebec’s hydro resources, he said, “We’d love to have it.”

He noted the RTO is seeking a reliability-must-run designation for Exelon’s Mystic generating station, which has access to LNG storage. The proposal, which is pending before FERC, “has not gone over very well in New England,” he said. “It’s going to be very expensive.” (See FERC Advances Mystic Cost-of-Service Agreement.)

He said the RTO is “trying to strike a balance” in shifting to renewables, noting that solar generation, with a capacity factor of less than 5%, “doesn’t help at all” in meeting winter needs.

“Our system is not ready to have these old coal and oil units retire,” he said.

Dan Dolan, president of the New England Power Generators Association, said that although gas prices spiked during last January’s deep freeze, the “system … worked.”

“In the face of the longest, deepest cold snap in over 100 years, with tremendous outages due to transmission line failures, we didn’t have a single reliability shortfall. And we saw tremendous responses in investment and performance from the generators on the system optimizing the fuel infrastructure that does exist,” Dolan said.

He said he was concerned about the market providing enough revenue to prevent the retirement of coal and oil generators needed during winter peaks. He said state-contracted resources are projected to grow from the current 17% of the market today to 60% within a decade.

“The question is, is the existing market design sufficient to maintain this half-pregnant status of a tremendous portion of the market being merchant with the rest of the market … made up of resources that are indifferent to that market price? And I would argue that the answer is no, on both the energy and capacity end.”

Storage vs. Peakers

It’s a question that comes up often at energy conferences: When will storage be versatile and cheap enough to compete with natural gas peakers?

Not soon in the frozen north, speakers said. Despite declining prices, solar/storage combinations cannot help New England in winter, Dolan said. “It’s awfully hard for solar to perform when it’s under a foot and a half of snow,” he said, adding that current battery storage can only fill gaps for hours, not days.

Bahry said storage will struggle to compete as long as natural gas prices remain cheap. “If we’re dealing with gas a buck a [gigajoule], nothing competes … with dispatchable peakers in that pricing environment,” he said.

Nuclear Refurbishments

Jeffrey Lyash, CEO of Ontario Power Generation, gave an update on the status of his company’s $12.8 billion ($9.7 billion USD) refurbishment of the Darlington nuclear plant, calling it “Canada’s largest clean energy program.”

Darlington is a CANDU (Canada deuterium uranium) pressurized heavy-water reactor that has been producing about 20% of the province’s electricity since the early 1990s. Unit 2 was taken offline in 2016, beginning what is expected to be a 10-year project involving all four units. The refurbishment — which Lyash said is far more extensive than projects to extend the lives of U.S. pressurized water reactors and boiling water reactors — is expected to allow the plant to run until 2055.

He said he feels the “weight of responsibility” to deliver the project on time and on budget because Unit 2 is the first of 10 reactors, including six at the Bruce Power plant, scheduled for retrofits. OPG, which is owned by the province, is sharing best practices on the renovations with privately owned Bruce Power, which plans to spend $13 billion.

“The future of the nuclear industry hinges on the success of this project,” Lyash said.

The Future of LDCs

Gordon Kaiser, CEO of Alberta’s Market Surveillance Administrator and former vice chair of the Ontario Energy Board, had a provocative answer in a panel on what local distribution companies will look like in 2025.

“They won’t exist,” he said. Instead they will morph into larger, integrated utilities with generation assets, he predicted. Municipal ownership of LDCs will decline because of the need for professional boards of directors to manage the investments. They will replace boards of municipal “councilors looking for hockey tickets,” he said.

Kaiser’s vision was not shared by other panelists.

Moderator David McFadden, chair of Toronto Hydro, said municipal utilities are not ready to sell yet.

Toronto Hydro CEO Anthony Haines said LDCs will be even more important in the future.

Former FERC Chair Joseph T. Kelliher, executive vice president of NextEra Energy, said he didn’t see such a shift happening in the U.S. either because of the large number of municipal utilities and political obstacles to mergers. He acknowledged, however, that some munis are selling their transmission to escape liability for NERC reliability standards.

Kelliher said many U.S. utilities remain inattentive to controlling costs despite earnings pressure and flat energy demand. Cost-of-service regulation is of limited use, he said. “I’ve always thought it was misnamed, because cost-of-service regulation really is profit-level regulation, because it’s the rate of return that’s regulated, not really the cost,” he said. “Cost-of-service regulation is very ineffective in weeding out routine excessive costs.”

“Competition hasn’t really fully affected LDCs,” he continued. “It’s remarkable how many utilities are not attentive to controlling costs.”

Complexity

Jason Chee-Aloy, managing director at consulting firm Power Advisory, said he senses stakeholder fatigue after more than a decade of competition and repeated changes in market design.

“I do think that stakeholders in general — we’re a firm that’s all over North America — are starting to throw their hands up in the sense that this stuff is getting really, really complicated,” he said.