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The great capacity market debate: Which model can best handle the energy transition?

Cheap natural gas and generation subsidies have exposed vulnerabilities in capacity and energy-only market constructs. Can grid operators preserve reliability and maintain fair prices?

Recent upheavals in wholesale electricity markets are giving new life to a years-old debate about market structure as the nation shifts to a cleaner energy mix.

“The big debate out there,” said Gordon van Welie, CEO of ISO-New England, “is can you do it the way Texas is doing, which is an energy-only market? Or do you need a capacity market?”

Capacity markets aim to ensure grid reliability by paying participants to commit generation for delivery years into the future. Energy-only markets, by contrast, pay generators only when they provide power on a day-to-day basis. 

Of the wholesale electricity markets that serve two-thirds of the U.S. population, only two — the Electricity Reliability Council of Texas (ERCOT) and the Southwest Power Pool (SPP) — do not have capacity markets.

Supporters of the energy-only construct say it is the most efficient — preventing consumers from paying for generation that may never even be called on to provide power.  

“I think what Texas has done is like an antitrust concept,” Commissioner Donna Nelson of the Public Utilities Commission of Texas (PUCT) recently told an audience at the Energy Thought Summit in Austin. “You protect competition; you don’t protect individual competitors.”

But others worry energy-only markets could become increasingly unstable in coming years because low electricity prices could discourage generators from building new power plants without the guaranteed revenue of a capacity market.


“I think the Texas model, in the long-run, is very vulnerable."

Gordon van Welie

CEO at ISO-NE


“I think the Texas model, in the long-run, is very vulnerable,” van Welie told Utility Dive on the sidelines of the conference after Nelson spoke. “It'll work for a while; it'll work as long as you've got demand growth in Texas.”

The capacity market debate is not a new one — Texas stakeholders chewed the issue over from 2011 to 2013 — but the persistently low price of natural gas and the spread of generation subsidies means both market models will face stiff tests in the coming years to preserve reliability and ensure fair prices for consumers.

The problem of low prices

At the Energy Thought Summit last month, Commissioner Nelson said the ERCOT market, which covers 90% of Texas, is performing nicely: Prices to consumers are the lowest on record, reserve margins are healthy, and the power mix continues to get cleaner.

In fact, everything would be hunky-dory if it weren’t for the pesky federal government.

“If you could design a wholesale market that wasn't influenced by outside factors, obviously you wouldn't have the kind of issues we've been dealing with,” she said, “but you do have those environmental policies like the production tax credit.”


“If you could design a wholesale market that wasn't influenced by outside factors, obviously you wouldn't have the kind of issues we've been dealing with."

Donna Nelson

Commissioner at PUCT


Those “issues” stem from low prices. Along with the fracking boom of the past decade, which lowered the cost of natural gas generation, Nelson blamed the $23/MWh federal production tax credit for wind resources for depressing prices in the ERCOT energy market, reducing revenue for other plants.

“You can see if your average summer price is $24/MWh and you’re paying one of the segments of the market $23/MWh, that's going to distort the market and drive prices down,” she said.

In Texas, regulators ensure reliability through a mechanism called scarcity pricing, which allows real-time electricity prices to reach as high as $9000/MWh on days of peak demand. Instead of guaranteeing generation revenue through a capacity market, the promise of high prices is supposed to incentivize generators to build new plants and keep them ready to operate.

That mechanism works best when the grid’s reserve margin is at about 11%, Nelson said, allowing for “enough instances of scarcity that prices will go up and allow generators to recover their capital costs.”

But in recent years, Texas has become the nation’s wind energy leader, with more than 18 GW of capacity installed. Nelson said that build-out, facilitated by the PTC, has helped bump reserve margins up close to 17%, and the influx of cheap generation has cut down on the number of scarcity pricing episodes.

“Last summer, for the first time, we saw days with high demand where we saw about 4,000 MW of wind online,” she said. “Now, that's not enough where you can count on wind to always be there, but it is enough to remove the scarcity pricing, so that's another way scarcity pricing has been affected by renewables.”

The worry for markets like ERCOT is that even when the PTC phases out in the early 2020s, better energy efficiency and continued renewable energy additions will combine with cheap natural gas to keep electricity prices low, thereby reducing the incentive for generators to build new plants.

“What that investor has to do is look out into the future over 30 years and say, ‘How much money can I earn to cover my costs from the energy market?’” ISO-NE’s van Welie said. “The picture then is going to look grim. You're going to just see low prices as far out as the eye can see with them actually declining going forward.”


“The picture [for an energy-only market in 30 years] is going to look grim. You're going to just see low prices as far out as the eye can see with them actually declining going forward.”

Gordon van Welie

CEO at ISO-NE


Despite these worries, Nelson noted that Texas generators are expected to continue to add capacity in the short term. But whether the market will retain adequate incentives for new generation in years to come is a “fair question,” said Bill Magness, president and CEO of ERCOT — and it’s one that affects much more than just the energy-only market model.

A capacity market fix?

Out-of-market generation subsidies comprise much more than just the federal PTC for wind and investment tax credit for solar. There’s also “aspirational capacity,” as Magness termed it — renewable capacity directly contracted for by corporations or communities to meet sustainability goals, not necessarily capacity needs.

More significantly, many states have legislative renewable energy mandates or other clean energy policies that support certain generation resources.

In van Welie’s jurisdiction, both trends are particularly strong. Every state in ISO-NE has a renewable energy mandate, Connecticut lawmakers are debating nuclear subsidies, and Massachusetts last year passed a law mandating an additional 2.4 GW of offshore wind and hydropower purchases.

From a market standpoint, the problem with these mandates and long-term power purchase agreements is that they give renewables and/or nuclear “an economic leg-up over the other resources that don't get access to those incentives,” van Welie said.

“It definitely leads to price depression in the energy market, because these renewable resources have no marginal fuel costs and can bid down into negative price territory, as the wind often does all over the country,” he said.


“[The presence of renewable mandates and generation subsidies] definitely leads to price depression in the energy market..."

Gordon van Welie

CEO at ISO-NE


In places like ISO-NE, the capacity market is designed to provide a solution by balancing lower energy market prices with higher revenues for generators in the capacity market.

“With the forward capacity market, we're really saying we also value energy and the scarcity conditions at $9000/MWh,” van Welie said. “The difference is we'll price it at $3500/MWh in the energy market … but we're also valuing the option that we bought from the generator at $5500/MWh.”

The critical difference, van Welie said, is that in an energy-only market, generators must wait and hope for the day when real-time prices hit $9000/MWh. With a capacity market, some of that revenue is guaranteed.

“The capacity market is saying, ‘I promise you that I'll pay you $5500/MWh if you show up and operate when I need you to operate,' just like the scarcity event in Texas,” he said. “The difference is, I promise it to you on a forward basis. I've taken it out of the equation whether you collect this money or not. I've changed it around to say, ‘You will collect the money as long as you perform for me.’”

While plant owners must still clear capacity auctions, the opportunity to secure revenue years in advance gives generators added incentive to build new plants, supporters of capacity markets say. But others call the model wasteful, since the grid operator pays out the capacity costs for load events may not materialize years down the line. 

Van Welie said that over the long term, the energy-only and capacity market constructs would end up delivering similar cost results to consumers. “Economists would argue that if you have two perfectly comparable markets, you'll end up in approximately the same place in terms of what you spent,” he said.

But capacity markets remain vulnerable to price depression as a result of out-of-market subsidies, van Welie cautioned.

“If these resources also enter as price takers without any checks and balances into the capacity market, you can actually end up compromising the ability of the capacity market to balance the revenues,” he said.

That issue could soon come to a head in ISO-NE with respect to Massachusetts’ hydro purchase mandate. If those special PPAs are allowed to enter the capacity market, “you will end up with a price depression,” van Welie said.

ISO-NE has a minimum offer price rule to guard against artificially low prices in the capacity market, so that will likely “hold the hydro contract out.”

"The MOPR will screen out subsidized capacity offers, ultimately resulting in surplus capacity, and consumers will end up paying for extra resources, which is an inefficient outcome," van Welie said.

Other around-market moves, such as state nuclear supports, could suppress capacity market revenues for unsubsidized plants if the subsidized resources play in the market. Those concerns have sparked challenges to nuclear subsidy programs and proposals in New York, Illinois, Connecticut, New Jersey, Ohio and Pennsylvania.

Van Welie said they point to a bigger issue — how to reconcile environmental goals that demand more renewable energy additions with the need to preserve market incentives for new generation.

“The big discussion is, how do you solve that problem? These two objectives are in tension with each other.”

Solutions on the horizon

The question of reconciling renewable energy policies and electricity market functioning is not one solely for progressive states. Texas also dipped its toes into the around-market pool in 2005, when the state financed the build-out of the competitive renewable energy zone (CREZ) transmission lines.

“That certainly created increased incentive for additional wind all over the place,” ERCOT’s Magness said, “so we spend a whole lot of time figuring out what are the issues that arise technically and operationally from that phenomenon.”

The spread of both these pro-renewable policies and out-of-market nuclear supports has captured the attention of the federal government. The Federal Energy Regulatory Commission next month will hold a two-day technical conference on around-market subsidies, aiming to devise solutions that preserve price formation while allowing states to meet their individual energy and climate goals. And the Department of Energy last week kicked off a review of whether federal energy subsidies are leading to the early retirement of baseload generation.

Van Welie said he and the ISO-NE staff have devised a capacity market fix they believe will go a long way to aligning environmental goals and electricity market operations, but he would not divulge any details ahead of the organized market's technical conference on May 1.

“We're working on a solution where we're quite optimistic we've got something that will work,” he said.


“It’s like my predecessor always used to say during the capacity market debate: ‘We can operate reliably either way.’ I still feel that way."

Bill Magness

CEO at ERCOT


ERCOT is the sole grid operator to not fall under FERC jurisdiction, but Magness said Texas stakeholders will be watching the conference and other markets for solutions, as they share many of the same problems.

“There are concerns with prices at the levels that they are in ERCOT and other places,” he said. “Are you creating sustainable incentives for people to continue to get the grid what it needs to operate? No matter how you slice it, it’s a challenge.”

In Texas, Magness said the debate about capacity markets is unlikely to resurface — it’s simply been hashed out ad nauseam already. But regardless of market structure, he still expects the nation’s grid operators to be able to preserve reliability for consumers.

“It’s like my predecessor always used to say during the capacity market debate: ‘We can operate reliably either way.’ I still feel that way,” he said.

This post has been updated to clarify a quote from Gordon van Welie regarding the minimum offer price rule (MOPR).

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Filed Under: Generation Solar & Renewables Regulation & Policy
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