Pending price reforms in the nation’s largest wholesale electricity market are stoking concerns of a low-profile bailout for aging coal and nuclear plants.
The Federal Energy Regulatory Commission in January rejected a plan from the Department of Energy to support such generators. Now, the CEO of the PJM Interconnection is trying to assure the sector that proposed reforms to its power markets would not have the same effect.
“This was never about trying to save plants that don't run,” PJM CEO Andy Ott told Utility Dive. “That word ‘resilience’ that was used on the DOE side is just not the same [as what we're doing].”
The DOE’s Notice of Proposed Rulemaking (NOPR), filed last September, would have provided cost recovery to merchant power plants that keep 90 days of fuel supply onsite, largely benefiting coal and nuclear generators. DOE and its allies in those sectors argued the plants are essential for the resilience of the power system — the ability to “bounce back” from outages.
FERC regulators threw out the 90-day provision in their ruling, saying DOE did not prove that existing market rates are unreasonable, nor that their solution would improve them. But they also validated DOE’s concern about system resilience, asking regional grid operators to report back in 60 days on how to improve it.
Some industry observers are concerned those filings, along with ongoing efforts to reform power market rates, could amount to a “stealth NOPR” — higher payments to many of the same generators that would have benefited from the DOE proposal.
The conversation centers on the PJM’s efforts to reform price formation in its energy and capacity markets. While those plans predate the DOE NOPR, some market observers are concerned they would have a similar effect.
“If [a reform] results in a larger payment in the energy market to inflexible units it could have many of the same impacts as the NOPR ... and that’s what led to me to think of it as a stealth NOPR.”
Joel Eisen
Professor of Law, University of Richmond
“If [a reform] results in a larger payment in the energy market to inflexible units it could have many of the same impacts as the NOPR without being done by a FERC rule, and that’s what led to me to think of it as a stealth NOPR,” said Joel Eisen, an energy law professor at the University of Richmond. “The same inflexible generators get that would have benefited by the resilience NOPR ... stand to benefit by the way price formation would be defined here.”
“Let’s also not forget the swath of capacity market reforms that PJM has put forward,” Robbie Orvis, director of energy policy design at think tank Energy Innovation, said in an email. “Together with [energy market] price formation reform, these changes will undoubtedly increase revenue for coal and nuclear generators, though admittedly other units as well.”
Some FERC regulators have weighed in as well, warning regional grid operators proceed with caution on energy market reforms, respect state input on capacity repricing and keep their resilience docket filings — due March 9 — away from plant bailouts.
Ott says many of the bailout concerns stem from a “lack of information” about the grid operator’s proposed reforms. In a Tuesday interview with Utility Dive, he offered new insights into PJM’s plans for energy and capacity market changes, as well as its upcoming resilience filing.
Energy market reform
Of PJM’s proposed market reforms, changes to its energy market have attracted the most scrutiny for bailout concerns.
Floated in a staff white paper last November, PJM’s plan would alter market rules to allow large, inflexible units to set the locational marginal price (LMP) that forms the foundation of the day-ahead and real-time energy markets.
Currently, the next resource that can respond to a price signal is allowed to set the LMP — typically gas plants that can vary their output. The PJM proposal would allow coal and nuclear plants to set LMP as well, raising energy market prices between 2% and 5% by the grid operator’s estimate.
PJM says the pricing reforms are needed to reduce uplift — payments given to generators when the LMP does not reflect the cost of serving load. But some critics are concerned it could amount to a plant bailout.
“It is accomplishing many of the same objectives,” as the DOE NOPR, Eisen said. “By allowing inflexible units to set locational marginal price, it would arguably reduce uplift but would also result in higher payments to generators.”
Ott said those concerns stem from a misunderstanding of what the grid operator hopes to accomplish with energy market reforms. The proposal was intended to combat uplift payments, he said, but was pulled into the conversation on the DOE NOPR when the department referenced it in its filing and FERC highlighted it in its rejection decision.
“We owe the stakeholders a more refined articulation of the problem,” Ott said. “There was the DOE report [on grid resiliency] and then the DOE NOPR and then what we were saying, so the issue got very muddled.”
A new cold weather report issued by PJM this week aims to provide that refined articulation, Ott said. Its analysis of a cold snap that gripped the grid operator’s territory in January showed that uplift payments rose to $4 million a day, an 11-fold increase over previous years.
“That should help people get an idea of what we're trying to solve and maybe get rid of some of this noise about is there a conspiracy theory,” Ott said, “because it's really, truly about making sure the prices that we calculate reflect the units that are operating, simple as that.”
Current energy market rules that allow only flexible units to set LMP were made due to computational limitations in market software when PJM was being set up in 1998, Stu Bresler, PJM’s vice president for operations and markets, said in a December podcast interview. Ott stressed that the energy market proposal aims to correct that issue, and would not amount to keeping plants online that would otherwise retire.
“Only generators that are actually running get paid [the] energy price, so this is not a veiled attempt to save plants that never run, because obviously if we change the energy price formation you have to actually produce energy for that to affect you,” he said. “I think the DOE NOPR, the notion of trying to save plants, was geared toward saving plants that are on their way to retirement.”
Orvis said that analysis “doesn’t tell the whole story.” While it wouldn’t benefit plants that aren’t running, the proposed LMP rules would still raise revenues for generators that run only infrequently, likely pushing them to change their bidding behavior to increase their output.
“In particular, the price formation proposal appears as if it will mostly benefit units during times of low load, when inflexible generators are more likely to be a larger share of load, and setting the price under the new proposal,” Orvis wrote. “That conclusion points to increased revenues for coal and nukes in particular, which often run during off-peak hours.”
Whether those increased revenues would be enough to keep marginal plants online remains unclear. Jeremy Harrell, policy director at the conservative clean energy think tank ClearPath, said it is unlikely for many of the plants targeted by the NOPR.
"What PJM's putting forth is not a NOPR-lite."
Jeremy Harrell
Policy Director, ClearPath
“You're not going to see what PJM has proposed to be a difference-maker for a coal power plant that is going to retire otherwise,” he said. “For the nuclear fleet, I think there are plants in PJM that it could be a difference-maker for them. Some of those that are on the verge or just a little bit in the red, it would be a difference-maker for and would keep them open.”
Whether PJM will actually propose its energy market reforms at FERC remains in question as well. Last week, FERC Commissioner Cheryl LaFleur told a DOE advisory group her agency would have to “think very hard” before it enacts any proposal that alters LMP formation.
“I don’t think it's something that we should change lightly, but should we get a proposal from PJM, we'll obviously give it serious thought,” she said.
The energy market proposal is currently pending a PJM stakeholder committee, Ott said, and the final outcome of that could look different than the white paper proposed last fall.
“Certainly [LMP reform] is an avenue or dimension of solution,” he said. “Also enhanced reserve markets is an additional dimension of solutions…. I think we need all of the above and we need both. We need pieces of both of the solutions, but us showing through this stakeholder discussion we're not wedded to a final solution.”
Capacity repricing
While PJM’s energy market reforms are likely months away from a potential filing at FERC, reforms to its capacity market — which allocates generation resources years in the future — are much closer to federal scrutiny.
Earlier this month, PJM announced it would file two competing proposals to reform its capacity market to FERC, asking federal regulators to help it choose a policy direction.
The announcement came after many stakeholders expressed concern with a proposal from the PJM staff that would split its capacity market into two parts. A competing proposal from PJM’s independent market monitor to expand minimum price rules garnered more stakeholder support, but most market participants indicated they would rather stick with the status quo.
The controversy attracted the attention of federal regulators, with FERC Commissioner Robert Powelson warning last month that any proposed capacity solution would have to get input from states — which do not have a vote in PJM’s stakeholder process — for it to pass muster at FERC.
Ott said the disagreement over policy options led PJM to its unusual dual FERC filing — tried only once before by ISO-New England.
"The policy call [on capacity repricing] should be made by the regulator, not by us."
Andy Ott
CEO, PJM Interconnection
“I talked about it with the [PJM Board of Managers], and we made the decision that the policy call should be made by the regulator, not by us,” Ott said. “I know it's a bit odd, a bit surprising, but we thought it was such a crossroads of which way should we go, and then … the third option is to do nothing and we need to make a call on that, too.”
Ott said PJM will file the two proposals under Section 205 of the Federal Power Act in mid-March and ask FERC to choose a policy option for it to refine and deliver back as a final proposal.
“The point here is FERC needs to make a policy call,” he said, “and if doing nothing is not an option and something needs to be done, then there are essentially two ways to go.”
Both the PJM staff and market monitor proposals aim to adapt the market to state energy mandates and incentives. The worry is resources covered by these policies — like renewables or nuclear — could depress prices in wholesale power markets, forcing other plants offline and threatening reliability.
In the PJM staff's split auction approach, the first part would operate like today, but a second phase would make adjustments to resources covered by government subsidies. PJM would recalculate prices after the first round by removing offers from subsidized resources and replacing them with reference prices, reflecting PJM’s estimates of a competitive offer.
An alternative plan from PJM’s Independent Market Monitor would expand the current Minimum Offer Price Rule (MOPR) to cover subsidized resources, preventing them from bidding in at price levels below a certain point.
Ott argued the two proposals represent different schools of thought on how to handle state energy policies. While his two-tiered proposal aims to “accommodate” state policies, the expanded MOPR is more of a “mitigation” effort that would prioritize market efficiency at the expense of state energy policies
“The question is, what's more important? Are state policies more important or is the market integrity more important?” Ott said. “My opinion is they are both important and they both can be accommodated.”
Ott also argued that some of the exemptions in the expanded MOPR — such as for some resources mandated by state renewable portfolio standards — could be found to be unduly discriminatory by FERC. FERC could take actions to fix the exemptions, and PJM’s filings will offer options to do just that, Ott said, but the bigger policy call is to choose between state priorities and market efficiency.
“We think if PJM’s market comes out and says we're the dominant consideration and the states' policies are less important, I don't believe that,” he said. “I don't think states believe that. I'm not sure FERC will believe that, not for long anyway. So I don't think it's sustainable to take that position, so it's not really what I want, it's more what we think is sustainable.”
Meanwhile, some market observers question whether any capacity reform is needed. Low prices in PJM’s capacity market are due to a glut of resources, Orvis said, more than the impact of state policies.
"The cure to low revenue is to remedy the extreme oversupply situation in PJM by letting unneeded capacity retire, not to pay all plants more and encourage new entry."
Robbie Orvis
Director of Energy Policy Design, Energy Innovation
“Just today I saw a report that in 2018 PJM is expecting another 11.5 GW of net capacity additions (more than 15 GW new capacity but offset by some retiring capacity) on top of a reserve margin that is already ~10% above PJM’s reserve margin requirement,” Orvis emailed. “The cure to low revenue is to remedy the extreme oversupply situation in PJM by letting unneeded capacity retire, not to pay all plants more and encourage new entry.”
The resilience filing
Before PJM submits its two capacity market proposals to FERC, it will also have to file its response in the grid resilience docket set up by the NOPR rejection by the end of next week.
Those pending filings from regional grid operators have also attracted scrutiny from federal regulators wary of the plans becoming a bailout for uneconomic plants.
"Some RTOs are suggesting things that don't necessarily, at least to me, really relate to resilience," Commissioner Richard Glick said at a regulatory conference last month. "They may be using this process as an opportunity where they may otherwise pursue a filing under the Federal Power Act under Section 205 or 206 for instance."
Ott acknowledged the commissioner’s concern, but also pointed out that FERC asked for recommendations on pricing reforms as a part of its resilience directive to RTOs.
“FERC actually asked are there changes to wholesale markets that are needed,” he said. “Well obviously we're going to say yeah, so that's going to come in from that perspective.”
Beyond market changes, Ott said much of PJM’s resilience filing will echo findings in its draft resilience roadmap, released last summer for stakeholder review.
Resilience filings from PJM and other U.S. grid operators are due on March 9, after which market participants will have 30 days to file reply comments. Ott said he hopes the docket can result in a conception of system resilience that moves beyond the conversation of plant bailouts.
“Certainly we don’t view the resilience docket that FERC opened as only about pricing,” Ott said. “It's about much more."
