By Rich Heidorn Jr.
TORONTO — Ontario and Alberta are developing capacity markets even as those in the U.S. face increasing stress from subsidized resources and growing resistance from states and public power.
The Alberta Electric System Operator (AESO) plans to add a capacity market in 2019, with the first contracts awarded in 2020 or 2021. (See related story, “Alberta also Adding Capacity Market,” Overheard at APPrO 2018.)
Ontario’s Independent Electricity System Operator (IESO) is developing an incremental capacity auction as part of its “Market Renewal” project, which also includes moving to a single pricing schedule, launching a day-ahead market and improving real-time commitments.
IESO says the Market Renewal program, which was announced in 2016, is “the most significant suite of reforms” since Canada’s largest province introduced competitive wholesale markets in 2002 and will produce at least $3.4 billion ($2.6 billion USD) in savings over 10 years.
Ontario has used a mix of regulated and contracted resources to meet its system adequacy needs and to eliminate coal-fired generation and add renewables. But that “approach did not always ensure that capacity was procured most cost effectively, that excess capacity was not procured, and that opportunities existed for innovative and emerging technologies,” IESO acknowledges.
The capacity market, with the first auction expected in 2023, will reduce costs by getting more competition for future resources, IESO says.
High electric rates were a major issue in last June’s provincial elections, when the Progressive Conservative party ended 15 years of Liberal party control. Ontario’s electricity rates, the highest in Canada, rose four times as fast as inflation between 2006 and 2017. After rate reductions in 2017, Ontario’s time-of-use rates now range from 6.5 cents/kWh for off-peak to 13.2 cents/kWh for on-peak.
To fund the renewable contracts under the Green Energy Act, and the costs of conservation programs, gas capacity expansions and nuclear power refurbishments, the province added a Global Adjustment surcharge, which rose from 1 cent/kWh in 2008 to about 10 cents in 2017.
Since taking office June 29, the new government has:
Forced the resignations of the board and CEO of Hydro One, the province’s transmission and distribution utility, which the party accused of waste and mismanagement. The Hydro One Accountability Act, introduced in July, requires a new compensation scheme for executives, the board and the CEO. The previous CEO was nicknamed the “$6 Million Man” for his salary.
Introduced legislation in September to repeal the 2009 Green Energy Act, which provided feed-in tariffs to expand renewable energy, encourage conservation and create clean energy jobs. Critics said it caused an increase in electricity costs as the province overpaid for power it didn’t need. The new government also canceled 758 renewable energy contracts totaling $790 million ($600 million USD) over 20 years and declared a moratorium on new contracts.
Canceled Ontario’s carbon tax and cap-and-trade program and prohibited trading of emission allowances.
Still on the government’s to-do list are promises to cut electric rates by 12% for “families, farmers and small businesses” and “aggressive reforms” to “stabilize” industrial electric rates.
Mike Richmond, co-chair of McMillan LLP’s Power and Energy Law Group, displayed the Conservatives’ energy plan on a single PowerPoint slide during a presentation at the Association of Power Producers of Ontario’s 30th annual conference last week.
“It’s not a complicated plan. That means there’s not a lot of wiggle room to do anything but this,” Richmond said. “In fairness, in less than four months, they’ve already done most of it.”
The new energy minister, Greg Rickford, told the conference that his party is committed to lowering high prices that he said had resulted in a “devastating exodus of jobs” during the Liberals’ control.
Rickford said the canceling of renewable generation projects was not an attempt to “put renewables out of business.”
“It simply suggests that we’re looking, in typical Tory pragmatic fashion, [for] solutions that work for families and … businesses.
“Moving forward, we’re evaluating and reassessing the structure of energy in the province — the system from regulation to procurement and all points in between — in an effort to drive [electric] costs down.”
Is Capacity Market the Answer?
Rickford said he was confident that IESO’s Market Renewal initiative and its incremental capacity auction will lower costs and increase efficiency. “We believe that because other jurisdictions have used capacity markets with much success,” he said.
Not everyone at the conference was so sure.
“I think people in the sector are — I’m not sure I’d use the word ‘skeptical’ — but questioning whether in fact that is the right answer to the kind of electricity system we’re likely to see in the future,” said APPrO President David Butters, who said the auction is unlikely to attract new generation. “It might be an opportunity to extend existing facilities, but there are contractual issues around that have to be considered. But it is probably worthwhile going in that direction, if only to get some experience.”
IESO is planning a forward period of three and a half years (although the first auctions may contract one or two years in advance). It will seek one-year commitments for existing resources (six months for seasonal resources) and multiyear commitments for new resources.
In September, IESO released projections showing it may have a capacity shortfall of 1,400 MW during winter and summer peaks beginning in 2023. The shortfalls could rise to 3,700 MW in 2025 before plateauing at 2,000 MW through 2030, when the province expects to have all its nuclear capacity operating again following refurbishment projects. Butters said the projections assume continued use of existing resources whose current contracts will expire, particularly in the late 2020s. IESO, he says, must address the gap “without delay.”
But IESO CEO Peter Gregg told the conference the grid operator won’t decide until the end of 2019 whether it needs to act to address the gap.
Barbara Ellard, IESO’s director of markets and procurement, said Market Renewal is an acknowledgment that the grid operator needs different products and services to maintain reliability into the future.
“Market Renewal is really only the first step to get us there. It is about building a better foundation. And a lot of Market Renewal is about price, obviously,” she said.
In September, the grid operator released its high-level design for the single schedule market, which will introduce locational energy prices, and is intended to align pricing and dispatch, reduce the need for out-of-market payments and enable the launch of a day-ahead market.
IESO currently uses an “unconstrained schedule” to set a single price across the province for every five minutes, which does not account for actual system conditions and operational constraints. To ensure reliability, it runs a separate dispatch schedule that selects units based on system conditions.
“Our energy market has many, many flaws,” Ellard acknowledged. “We’re not right-sized. We often have too much generation on or we have too little generation on as we get into real time. We don’t have the right price signals that make sure that we get those right resources operating at the right time.
“On the capacity side … we are looking to make sure we only procure … capacity that we need.”
Judy Chang of The Brattle Group, which IESO hired to produce a cost-benefit analysis for Market Renewal, said there is a limit to what Ontario can learn from more mature markets. “We can’t just think about what’s been done already in other markets. We really have to build a foundation in a way that’s adaptable to the future,” she said.
Limit to Grid Defection?
One audience member suggested that with electric production becoming more decentralized with microgrids and behind-the-meter generation, IESO was pursuing a solution that “seems more appropriate for 2002.”
“We do not foresee a future any time near where there isn’t a wholesale need,” Ellard responded. “We are decentralizing, [but] I think some of the modeling that’s going to come out is going to show there will be a natural limit to this concept of grid defection. So, from a system operator perspective, whether it is a 10,000-[MW] demand or a 30,000-[MW] demand, we need to figure out how to meet that demand.”
In a panel discussion on regulation, speakers criticized both IESO and the Ontario Energy Board, which regulates electric transmission and distribution, and nuclear and baseload hydropower generation.
Attorney George Vegh, the head of McCarthy Tetrault’s energy practice, said IESO should face a “reckoning” for its inefficiencies.
“Before we jump in and say we know all the solutions, let’s find out what the problems were,” said Vegh, former general counsel of the OEB.
“There are some hard questions that we should be asking ourselves. If you look at operational efficiency in particular … someone should be asking the question: ‘Why was this not the IESO’s day job over the last 15 years?’ The things that we’re talking about — single-schedule market or day-ahead market — these have been on the agenda for over 10 years.”
Ontario Energy Board’s Role
Vegh said OEB also has a role in creating a favorable climate for generation investments.
“Investment in long-term assets requires confidence that government will keep its commitments. What makes it credible is constraints and checks and balances.”
OEB “hasn’t played any role at all,” Vegh said. “There has been no oversight. A lot of these decisions were very uneconomic.”
Vegh said the OEB should be challenging the assumptions behind IESO’s load forecast and reserve requirements.
“All of these things should be looked at much more transparently in a much more open process with the ability to test some of these assumptions instead of just being told: ‘Oh, we might have a capacity gap, but we might not.’
“What are the resources that might be available to meet that gap and how should they be evaluated? There’s no clear criteria for any of that. We’re just told, ‘Don’t worry, we can change some reserve requirements. We can tweak this and tweak that.’ I don’t think that’s good enough. I think that what we need to do is to have much more independent oversight around these assumptions for planning and the assumptions for procurement.”
Minister Rickford also called for ways to “strengthen transparency and trust” in the OEB. “This regulator has not had a significant examination for many years. It is in need, in some respect, of a modernization,” he said.
Brian Rivard, director of research at the Ivey Energy Policy and Management Centre, also called for expanded oversight of IESO.
“The onus should be on the IESO to put forth changes … to the market rules or changes to the market design and prove that it has to do so because there are inefficiencies in the sector, that the remedy it’s proposing will correct those inefficiencies and, thirdly, that [in] doing so, the benefits that will be achieved … [outweigh] the costs. The OEB’s there to allow for a transparent review of that.”
A.J. Goulding, president of London Economics, lamented that “there’s been some chipping away at OEB oversight” in the past decade.
He said OEB’s job will become increasingly challenging “as we start thinking about things like … connection charges, an interconnectivity standard across distribution utilities … thinking about whether we need to … extend the principle of open access down to the distribution level.”
Role of Energy Ministry
At the same time, Goulding said, the energy ministry should resist temptations to micromanage IESO.
“To me the IESO is the appropriate place for planning for the sector. The ministry’s job is policy,” he said. “We also need to stop over-planning. Ultimately, if we believe in the incremental capacity mechanism, then we need to let it do its job. We need to make sure that it is technology-neutral and let the market drive choices for future optimization.”
APPrO’s Butters said he had three words of advice for government. “Leave us alone,” he said. “Actually, four words: please,” he added, drawing laughter.
“Very Canadian,” chuckled moderator Linda Bertoldi, chair of Borden Ladner Gervais’ National Electricity Markets Group.
“We’ve got a really good system. We have invested a lot of money in making it reliable and making it cleaner, and there’s a cost to that,” Butters said. “Let’s not make short-term decisions that will have longer-term consequences.”
Jason Chee-Aloy, managing director at consulting firm Power Advisory, said Ontario “lacks the environment for merchant investment” because of the dearth of bilateral contracting, market rules that don’t value flexible generation and excessive regulatory risk and government intervention.
“FERC isn’t the end-all and be-all in the U.S. But it is an independent body that issues orders. It doesn’t always agree with the system operator. Sometimes it sides with customers; sometimes it sides with producers. We don’t have that here. So, I think that weak governance is going to affect how we make decisions on investments.”
Brattle’s Chang said the U.S. regulatory system is no panacea, noting that her home state of Massachusetts is impacting wholesale markets by signing long-term supply contracts. “The fights between the states and the federal [government] is not something that I would hope for anybody else to have to deal with,” she said.