Capacity pricing changes: How each power market plans to account for resource adequacy
While PJM's capacity market reform plans dominate headlines, all grid operators are facing the need for greater flexibility as renewables increasingly enter their system.
The advent of state clean energy policies is pushing market operators across the nation to adapt how they price and value generation capacity.
Particularly in Northeast and Mid-Alantic states, many of which site power plants primarily through market forces, fossil fuel generators say renewable energy mandates and nuclear subsidies distort market signals and lower prices for their resources.
These interests have asked their market operators and the Federal Energy Regulatory Commission (FERC) to adopt rule changes to counteract the impact of clean energy policies, sparking a number of contested proceedings.
PJM Interconnection, the nation's largest market, has received the most media coverage for its plan to remove subsidized resources from its market, but each regional transmission organization (RTO) or independent system operator (ISO) is taking on questions about how best to secure the power capacity they need.
"No one's asking the question of should we still be utilizing mandatory capacity market constructs," Matthew Larson, partner at Wilkinson Barker Knauer told Utility Dive. "Instead, all that the RTOs [and] ISOs appear to be trying to do is [show] 'how can we accommodate state action.' And I think there's a million-dollar question out there that we're beating around the edge of."
The following is a list of the various capacity market considerations and commensurate FERC actions from the RTOs and ISOs in the United States.
In June, FERC issued a split decision to reject two proposed market fixes by PJM, which were meant to make up for the advantage clean energy resources receive from state subsidies. Commissioners split over how much control states should have over their generation mixes.
FERC ordered PJM to design new capacity market rules, granting an extension of its 2019 capacity auction.
The grid operator subsequently proposed a "resource carve-out (RCO)" plan that would remove subsidized resources from the capacity market by enforcing a price floor. Dubbed the Minimum Offer Price Rule (MOPR), it would block state-supported resources from bidding.
PJM told FERC that approach would be legal, but would also suppress capacity market prices below where they would be without any state subsidies. To correct for that, it also proposed an "extended RCO" plan that would boost prices for the remaining capacity market resources and recommended the regulators adopt it instead.
FERC is expected to act in January to allow changes to go into effect for the next capacity auction in August 2019.
Many fossil generators and consumer advocates oppose the extended RCO suggestion. Some environmental groups also objected to the grid operator's reaction to state subsidies, rejecting claims that coal and gas generation needed to be supported against more competitive, subsidized clean resources.
In particular, PJM's argument about reliability issues could be addressed with "more granular" capacity auction results, instead of deciding what resources the grid operator would dispatch for the entire year, Robbie Orvis, director of energy policy design at Energy Innovation, told Utility Dive.
"We've worked with other groups who have pushed PJM to at least move to a biannual [product], if not seasonal capacity products," he said.
Last April, ISO-NE put forth a similar plan to split its capacity market into two parts to better address how the grid operator handled subsidized resources.
Dubbed Competitive Auctions with Sponsored Policy Resources (CASPR), the plan was meant to prevent resources that are subsidized by tax credits or mandates from depressing capacity market prices.
In order to prevent subsidized plants from pushing too much needed capacity offline, CASPR proposed to create a second round of auctions in which retiring resources could transfer the capacity supply obligations they earned to new, subsidized resources.
FERC approved the CASPR plan in a 3-2 vote in March, with former Republican Commissioner Robert Powelson and Democrat Commissioner Richard Glick dissenting. The division, according to FERC observers, could make the CASPR more vulnerable on appeal.
"Kind of like in PJM, ISO-New England is worried about the long-term viability of the market when you have an influx of new supply, but you don't have quickly growing demand," Orvis said.
The two-part capacity auction mechanism will go into effect next spring.
New England states have set forth more and more ambitious climate and clean energy goals. Several states like Massachusetts, Connecticut and Rhode Island are issuing goals for offshore wind power and Massachusetts adopted a version of the Clean Peak Standard, which regulators have yet to define, adding more parameters to the power generation mix participating in the wholesale power market.
The issue is further highlighted by the Northeastern grid operator's small size compared to PJM, Orvis said.
In addition to the CASPR plan, ISO-NE is reforming its capacity market to value fuel security, or the ability of plants to access firm fuel supplies.
The ISO this summer asked FERC to approve cost recovery for Exelon's 1,700 MW Mystic Generating Station in part because it supports the operation of a major import facility for liquefied natural gas, which the grid operator says is vital for the region's generators.
FERC initially rejected that request, calling it too broad, but allowed the Mystic plant to apply for shorter term cost recovery while the ISO crafted more extensive changes to value fuel secure resources.
FERC this month approved an interim plan from the ISO that would treat Mystic and other fuel secure resources as "price takers" for the market's next three annual capacity auctions — not allowing them to set prices. Before the end of that period, ISO-NE will propose new fuel security rules.
The fuel security order was notable in part because a vacancy on FERC and illness affecting Commissioner Kevin McIntyre allowed the two Democrat commissioners to win approval of the order in a 2-1 vote. That dynamic changed last week with the addition of Commissioner Bernard McNamee, who won confirmation from the Senate this month.
Unlike PJM and ISO-NE, the Midcontinnent ISO (MISO) is structured with voluntary residual capacity markets, which can be attractive to states that want to exit full power market restructuring, according to Larson.
States such as Illinois, whose regulatory head critiqued the PJM plan, could start to question whether restructuring markets to "accommodate state action" is more necessary than "reforming the markets themselves," he added.
MISO does have a capacity market in the South, although the participating states have not been imposing such aggressive goals and mandates on renewable energy.
The northern area of MISO's resource adequacy is driven by states, Eric Gimon, a senior fellow at Energy Innovation, told Utility Dive. Movements within MISO to take a look at resource adequacy could lead to more granular capacity market products, like week-ahead, which Energy Innovation has supported in the past.
More granular capacity markets would serve to better address reliability of resources whose capacity can be estimated by forecasting weather, Gimon said, like wind power.
A lot of the wholesale market experts opposing PJM's proposal and other MOPR approaches seeking to ensure fuel security from baseload power want to see more granular capacity products.
New York ISO's capacity market is seasonal, meaning that the prices change to better account for shifting needs in reliability during peak seasonal times of demand. The NYISO system doesn't have coal generation, as PJM does, and the state is moving toward using a higher share of renewable energy.
"In my mind, New York is already further along and not actively trying to undercut the value of renewables in its capacity mechanism," Orvis said.
The grid operator is also working closely with the state to help support the development of renewables. State regulators are currently considering a version of the Clean Peak Standard, to ensure cleaner emissions during the highest rates of electricity use, and NYISO this month released a proposal to implement carbon pricing in its market. On Friday, Gov. Andrew Cuomo, D, pledged to bring the state to 100% carbon-free electricity by 2040.
CAISO also has incentives to work closely with the state of California, which is moving toward using 100% renewable energy. Unlike NYISO and other RTOs, the grid operator does not have centralized capacity requirements.
As California continues adding renewable energy capacity to comply with its ambitious renewable portfolio standard, the state has struggled with the "orderly retirement" of natural gas generators. The ISO has worked on increasing levels of resource adequacy as the dispatchable gas plants are being phased out, Gimon said.
The California Public Utilities Commission has opened a proceeding about setting up a central capacity market in order to address the emergence of community choice aggregators. The state regulators seek to address how customers that want to leave the service of utilities that have already invested in new or upgraded generation would repay utilities for the investment made on their behalf.
CAISO has self-scheduling natural gas plants on its system, meaning vertically-integrated utilities can choose the capacity at which their gas generation will be deployed. That has led to some issues where renewable generation has been curtailed to make room for the scheduled gas. However, the grid operator had been working to remedy this before Gov. Jerry Brown, D, approved a 100% renewable energy goal this fall, according to Orvis.
"As we start to move to a system with higher and higher shares of renewable demand and grid flexibility, we have to start thinking about all of these practices that have sort of been going on for a while and how they can limit or enhance the flexibility in the system," he said.
Independent gas generators proposed the establishment of a mandatory capacity market for CAISO, which was unanimously rejected by FERC in November after the regulator ruled the proposal didn't show how existing market rules were unreasonable. CAISO, state utility regulators and regulated utilities had opposed the proposal.
Southwest Power Pool (SPP) is similar to CAISO when it comes to self-scheduling issues, but the RTO's chief self-scheduled type of electricity generation is coal. In SPP, coal generators can be cycled throughout the day — the way gas plants would in California — to maximize the value of the plants. Like CAISO, SPP also implements resource adequacy requirements without having centralized capacity markets.
In the end, market-committed resources get pushed out first when there's too much generation on the system, regardless of generation prices. Of the 14 states whose grid is partially or entirely managed by SPP, several have strong wind resource potential, but wind is getting curtailed due to all the dispatched coal, according to Orvis.
The Electric Reliability Council of Texas (ERCOT) does not have a capacity market, but the grid operator faces similar resource adequacy issues as PJM.
Across the PJM region, cheap natural gas and — significantly less represented on its systems — renewables are undermining the economics of coal and nuclear. In Texas, coal generation has been similarly affected by cheap gas and a growing amount of wind and solar power. ERCOT's resource adequacy deliberations are bound to be "more complex and nuanced" because Texas is dealing with renewables on a larger scale, according to Orvis.
"Because the debates have been mostly limited to the capacity markets in the Northeast, you know the parallel doesn't seem obvious to Texas, but they have an interesting debate there over what they call economically-optimal reserve margins," Orvis said.
ERCOT uses planned reserve margins to build in a buffer of excess capacity to ensure reliability during peak usage periods, such as July and August. However, the coal units being relied upon in the summer will eventually need to undergo maintenance, Orvis said, and taking them offline can jack up prices during off-peak times, like September and October.
"You can think about ramping needs, all kinds of other needs, that can be resource adequacy that just don't get captured in the capacity notion," Orvis said.
Fossil fuel generators have proposed rule changes in the market that would increase prices, which are opposed by consumer groups as well as clean energy and environmental organizations. Texas regulators earlier this month postponed a decision on the plan.
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