'Graceful transition': ISO-NE's CEO on how wholesale markets can ease decarbonization

A well-designed capacity market can help ensure reliability with high levels of renewables, argues Gordon van Welie

When it comes to transitions in the power mix, the one happening in ISO-New England is striking.

The grid operator for the six states that make up the U.S. Northeast has seen its fuel mix change markedly in the last decade and a half. Whereas more than 40% of electricity generation in the region came from coal and fuel oil in the year 2000, now less than 6% does, according to the ISO’s latest Regional Electricity Outlook (REO).

Most of that retiring coal and oil power has been replaced by natural gas, which moved from 15% of the region’s generation in 2000 to nearly 50% today. And while new gas generation offers lower-carbon power than many of the plants it replaced, it also puts a strain on electric reliability, the head of the regional grid operator told Utility Dive.

“In the last three years we've attracted over 3,000 MW of new natural gas fired generation,” Gordon van Welie said in an interview at the Energy Thought Summit last month in Austin, Texas. “That's a good thing from a resource adequacy point of view, but it puts more pressure on the existing gas infrastructure, which hasn't seen any investment to meet this demand.”

Over the past decade, the region hasn’t added any new gas pipeline capacity, meaning that “existing pipelines are now running at or near maximum capacity at times, particularly in winter,” according to the ISO's latest report, raising prices for gas plants and threatening reliability during prolonged cold periods.

The “obvious answer” is building more gas pipeline infrastructure, van Welie said, but apprehension from policymakers and concerted opposition to new fossil fuel investments from environmentalists mean that no new projects are online yet.

Faced with that situation, the ISO started to think last decade about how to reform its capacity market rules so it could better ensure that generators who bought into the market would actually show up to deliver electricity. While the resulting market construct has helped ease the transition to a grid reliant on natural gas, van Welie said it will also be essential in moving to an energy system that does not rely on fossil fuels — if policymakers can get market structures and incentives right.

A grid that used to be based on coal and oil is increasingly reliant on natural gas.

Correcting the capacity market

In wholesale electricity markets, generators bid for the opportunity to deliver electricity at some point in the future. While players in the day-ahead market compete to deliver power the next day, those in the capacity markets bid to provide power at a time further in the future — three years, in the case of ISO-NE. Participants in the real-time energy market compete to balance differences between advance bids and actual, real-time supply and demand on the grid.

“You lock in the price the day ahead, and then the next day you'll get paid based on whether you’ve performed against that price,” van Welie said. “It’s the same concept through the capacity market, just three years ahead.”

If an entity wins the bid, it must be ready with the specified resource at the agreed-upon point in the future, which helps ensure electric reliability. But in the case of ISO-NE, van Welie said, that second part wasn’t alway happening.

“In the beginning, the capacity product definition didn't have much teeth in it when it came to performance,” he said. “It was really a payment for providing a piece of infrastructure, irrespective of [whether] it performed or not, and we learned very quickly that that wasn't working for us.”

Without some performance requirement built into its capacity market structure, the ISO was seeing some generation assets not perform to the standards demanded by their contracts.

As plants came under increasing financial pressure, van Welie said, some would decrease maintenance investments, cut staffing or choose not to buy fuel, and the grid operator started to see the average performance of its generation fleet drop off.

“A combination of those things had us sitting there saying, ‘We're trying to operate a system and our resource base isn't performing,'” van Welie said. “So, that led us to say we have to change the capacity product.”

The result was a capacity market reform that resulted in a “very simple concept,” van Welie said. Instead of a payment for infrastructure, players in the capacity market would bid for the opportunity to provide electricity or reserves to the ISO if called upon three years in the future. That means that while the resource could sit idle if there is no demand, it must be ready to perform if the ISO calls on it.

“We don't talk about what your resource type is, we don’t really care about whether there's steel in the ground or not,” van Welie said. “If you've taken on this obligation through the capacity market and we call on you in three years time, you have to deliver.”

This technologically-agnostic approach allows for a wider variety of resources — from gas plants and utility-scale renewables to demand response and aggregated distributed energy resources — to bid for contracts in the capacity market. But no matter the resource, the penalties for not delivering promised power when called upon are steep.

“If you don't deliver, we're going to take away from you the promised payment and the rate,” van Welie said. “In the beginning, [the penalty is] $2500/MWh, but eventually it will be $5400/MWh.”

While that’s a “pretty steep penalty for not performing,” there’s also a big upside for the highest-performing generators, van Welie said. If a generator performs better than what it is contracted for, the ISO will “pay you the money we’ve collected from the guys who are not performing, so you get the upside and $5400/MWh.”

Capacity markets and renewables

Since the reforms, the ISO has had fewer issues with plant performance through the capacity market, as it provides a lucrative incentive for keeping plants operating at a high level.

The same concept can help grid operators cope higher penetrations of renewable resources on their systems, van Welie said. As grids become more reliant on intermittent generation like wind and solar for their daily needs, well-structured capacity markets will be essential to ensuring that backup resources have a financial incentive to stay operational.

In his interview, van Welie described a situation where policymakers mandate the construction of large amounts of variable renewable generation independent of market dynamics — perhaps through a renewable portfolio standard or another mandate.

In such a world, prices in the real-time and day-ahead electricity markets would be expected to fall as the renewables — which lack the fuel costs of fossil plants — begin producing electricity.

“These resources get built, they get connected, and they produce energy, and what they do, because they have very low variable cost, is they will drive down the energy prices,” van Welie said.

While that could result in lower prices for consumers, it also presents a challenge: Some sort of firm power resource — whether gas generation today or storage in the future — will need to be kept online in order to compensate for interruptions in renewable energy generation.

“Let's say we're in a world where 90% of the daily energy is coming from renewable resources. That's kind of where policymakers want to go right?” van Welie said. “But let's say one day the weather's not cooperating — the sun's not shining and the wind's not blowing. You need to jump to another set of resources. How are you going to pay for that?”

The answer lies in the capacity market, van Welie said, which “acts like a natural revenue balancing mechanism.”

Every year, when the ISO runs its capacity market auctions, generators tell the grid operator through their bids what they think it will cost to provide capacity three years in the future. If companies expect their revenues to shrink in the energy markets in years to come, they will increase their bids in the capacity market.

While the balancing mechanism is “not one-for-one,” van Welie said the capacity market provides an incentive for generators who may struggle in the daily energy markets to keep their plants operating at a high level so they can collect capacity payments.

“I think that allows people to say I’m going to invest in a technology that's going to give me a high likelihood of meeting the ISO performance requirement,” van Welie said.

Energy market revenues are already exhibiting a downward trend in ISO-NE and van Welie expects capacity market revenues to begin increasing as more low-cost renewables are added to the system.

A ‘graceful transition’

While most of the generation today comes from fossil fuels, the capacity market construct envisioned by ISO-NE would allow that to change as new resources come online as well. As revenue shifts move resources from daily energy markets to the capacity market, incentives will also increase for demand-side resources, like demand response or aggregated distributed resources, to play a role as well.

“To the extent that people invent technologies that can do a more efficient job of giving us what we want, like a battery for example, they'll be able to displace some of the more traditional technologies in the capacity market,” he said. “So I think what we've created is a market mechanism that allows for a graceful transition.”

The benefits for distributed resources and the capacity market go in both directions, van Welie said. While the market can offer an opportunity for aggregators to group a variety of customer-sited resources and earn revenue on them, the capacity market’s performance requirements also help the grid operator handle even higher penetrations of DERs.

“Once they're hooked into the capacity market, they have the incentive to make sure that all the consumer devices that they're harnessing to give us what we want are controlled in a manner that is consistent with the incentive of keeping the lights on,” van Welie said.

“The elegance of offering people the opportunity to provide a service to the grid through the capacity market … [is that it] really creates that alignment in terms of the operational incentives that you're looking for,” he added. “You're saying, ‘You have an operational accountability and here's a financial accountability that goes with that.’”

While the market structure is expected to allow for the integration of more DERs, its potential to allow for deeper decarbonization of the grid doesn’t stop with providing alternative resources a chance to compete with traditional generation. It also provides an opening for policymakers to put in place new incentives to push the power sector toward lower carbon emissions.

“How one goes about doing that is important,” van Welie said. “If you do it through a resource-neutral incentive that tilts the market to get your objective without selecting specific resources, you do so in a way that's most in harmony with the wholesale market construct.”

While policymakers have long tried to influence which resources regulated utilities purchase, the organized market allows them to apply a certain standard — say, a price on carbon — to the entire territory, treating every generating resource in the same way under the incentive.

“The policy conundrum is, how do you achieve this policy around renewable energy in a way that doesn't damage the market? And I think the way you do it to put a price on carbon or put in a clean energy standard or do something that's resource-neutral that pays for what you want, which is carbon-free electricity,” van Welie said. “That way you'll gradually over time shift the mix in the market as opposed to creating these dislocations by contracting for stuff on the side.”

“It's a graceful way of tilting the playing field in a way that the market adjusts itself,” he added, “as opposed to having to have a lot of policy intervention in the market to get the outcome that you're looking for.”

As capacity market prices increase, emerging technologies like battery storage will have an opportunity to displace traditional sources of electric capacity.

Protecting price formation

While ISO-NE’s wholesale market construct holds promise, the “graceful transition” van Welie speaks of will only occur if the market participants have confidence in it.

“We're saying to investors, ‘Trust the market, there's an opportunity to recover your capital investment,’” van Welie said. “For them to have faith in that, they have to know that the price formation in that market is such that they have an opportunity to recover their investment; otherwise, no rational person would ever invest their money in the market.”

Key to preserving faith in the market is protecting price formation in it, van Welie said. “How do you do that? You do that through the Minimum Offer Price Rule (MOPR).”

The MOPR is a rule first implemented in the PJM Interconnect that prevents market participants from offering a new resource into the capacity market at a price lower than the grid operator’s estimate of the resource’s competitive costs.

“Essentially what [MOPR] does is make sure that the resources that make an offer into the capacity market truly reflects the investment costs,” van Welie said, “so that you don't suppress the prices in the capacity market.”

The rule has not yet seen wide usage in ISO-NE, but “people recognize that this might become a mechanism that we have to utilize in the future,” van Welie said.

The MOPR rule is currently under consideration by the U.S. Supreme Court in the consolidated case Hughes v. Talen Energy Marketing. At issue is whether state officials in Maryland violated FERC jurisdiction by granting a contract with a guaranteed rate of return to a plant being constructed by CPV Maryland.

Update: The Supreme Court unanimously ruled on April 19 to throw out the Maryland program, keeping PJM's MOPR rule intact.

State officials say they simply wanted to ensure the plant would clear later market auctions, but FERC said the move artificially suppressed power prices and stepped into its jurisdiction over interstate power markets. Utilities filed briefs with the court arguing that the state incentives were in direct conflict with PJM’s minimum offer rule.

While reporting from the oral arguments suggests the Supreme Court could side with FERC, van Welie expressed concern that the high court could alter or throw out the MOPR rule in its decision. That is the single biggest threat to the market structure his team has worked to create, he said.

“If the MOPR rule was basically set aside and [the Supreme Court] said people can do whatever they want and cause resources that are otherwise uneconomic to enter the capacity market, lowering the prices in the capacity market, then how are you going to pay for the resource base that's needed?” van Welie said. “So that's where it's vulnerable. The minimum offer price rule — that construct — is really the most vulnerable part.”

This post has been updated to reflect the Supreme Court decision April 19 in the case Hughes v. Talen Energy Marketing.

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Filed Under: Generation Solar & Renewables Distributed Energy Efficiency & Demand Response Regulation & Policy
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