By Michael Kuser, Tom Kleckner, Rory D. Sweeney, Amanda Durish Cook

RTO officials and their Market Monitors on Monday unilaterally rejected Energy Secretary Rick Perry’s proposal to provide price supports to coal and nuclear plants, calling it expensive, inefficient and counterproductive.

The ISO/RTO Council (IRC) led the opposition, with CAISO, PJM, MISO, ISO-NE and NYISO also filing comments in opposition. Also filing statements opposing the proposal were PJM Market Monitor Joe Bowring; David Patton, Market Monitor for MISO, NYISO and ISO-NE; and Keith Collins, head of SPP’s Market Monitoring Unit.

In a joint filing supporting the rule, the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association criticized the RTOs for failing to address trends threatening coal and nuclear generators. (See related story, FERC Flooded with Comments on DOE NOPR.)

They said NERC’s and RTOs’ “confidence in the current state of electric reliability … are based, in large measure, on existing conditions and short-term forecasts, largely ignoring the trend toward premature retirements of baseload coal-fired generating capacity currently available to address reliability and resiliency needs.”

The coal groups acknowledged that some RTOs “have tried to explore measures intended to maintain traditional baseload capacity in the market, and have even taken some halting and less-than-full steps in that direction, a tacit recognition that existing market rules and structures are not properly valuing the reliability, resiliency and long-term price stability benefits that traditional baseload capacity provides.”

But it said “the few revisions to existing RTO/ISO tariffs and related market structures and rules have so far been much too little and far too late. Without action by the commission to remedy these tariffs and market structures, the electric system will devolve to lose the value of fuel diversity and end up overwhelmingly dependent on intermittent renewable and natural gas generation.”

Rebuttal

Patton recommended FERC define the contingencies the Department of Energy seeks to address. “Without first identifying in detail the contingencies and associated reliability risks to the system, there is no way to quantify a resilience requirement,” he said.

He said MISO and ISO-NE have already conducted fuel-security studies.

“MISO’s evaluations of the adequacy of the gas pipeline infrastructure found the MISO North and Central regions to be ‘favorably located at the crossroads of pipeline corridors extending from many supply basins … with more than 20 interstate pipelines and significant gas storage resources.’ Hence, MISO’s potential exposure to natural gas supply contingencies is relatively low, and the need for the payments called for under the [Notice of Proposed Rulemaking] is similarly low.”

Patton acknowledged New York and New England are more vulnerable to natural gas system contingencies than MISO. But, he said, “it is highly unlikely that the proposal in the NOPR is a feasible or reasonable means to address these vulnerabilities,” saying dual-fuel capability “has been the most effective and cost-effective means” to address them.

“This illustrates the problems that arise when one starts with a very specific answer, rather than starting with a clearly defined issue or objective and allowing the markets to provide the most efficient answer,” he said.

ISO-NE

ISO-NE found fault with what it called the NOPR’s “one-size-fits-all” approach to the region’s risks and said its stakeholder processes were preferable to the NOPR to “develop market-based solutions, if any are needed.”

“The NOPR does not address these risks, and ISO-NE proposes to instead use the time the region has in 2018 and beyond to quantify its fuel-security risks,” the RTO said.

The grid operator said the NOPR would “significantly undermine the efficient and effective wholesale electricity markets,” and that moreover, “New England has no urgent need to rush to a solution, given that the three-year Forward Capacity Market has ensured resource adequacy until at least 2021, and the region has already taken steps to improve operating procedures and generator incentives to secure firm fuel supplies.”

Commenting on the proposed rule’s estimated burden of $291,042 per respondent RTO/ISO to develop and implement new market rules as proposed, including potential software upgrades, ISO-NE said such efforts would “be in the millions of dollars for each RTO.”

The NOPR would undermine New England’s wholesale electricity markets in two ways, the RTO said: “First, these resources may have no incentive to bid their appropriate fuel and operating costs in the energy market … [and] could profitably bid zero. While there are admittedly few coal resources remaining in the region, if these costly units bid zero, it will undermine price formation in the day-ahead and real-time energy market and increase emissions.”

Second, the RTO said, its FCM enables resources to offer to retire if the market does not clear at or above a specific price: “Normally, as units age and their costs rise, new resources will be more economic than retaining aging units that require a higher price. With full cost recovery guaranteed, however, these aging resources will remain, deterring the development of newer, more efficient and more cost-effective generating units.”

ISO-NE also said it has developed new operating procedures to improve information on generator availability during cold weather conditions, such as requiring generators to report their anticipated availability to the grid, including details on their ability to procure fuel.

The RTO said it also has increased market-side efficiency and improved gas-electric coordination to mitigate the supply problems arising from natural gas pipeline constraints.

“For example, the ISO has shifted the day-ahead energy market timeline to better align the electricity and natural gas markets to give generators more time to procure the gas they need to run,” it said.

NYISO

NYISO asked FERC not to adopt the proposal but said if it deemed action necessary, it should give the RTOs at least 180 days from the effective date of any final rule to submit compliance filings.

“[The] deadlines are simply not realistic and attempting to impose them would not be reasoned decision-making,” the ISO said. “The NOPR’s approach would distort, if not destroy, wholesale market signals needed to attract and retain resources required for reliability.”

The ISO called the proposed grid resiliency pricing rule “flawed” for being premised on inaccurate assumptions and statements as they relate to New York.

“The NOPR does not establish that its proposal is appropriate or that ‘grid resiliency’ issues should be addressed the same way in different regions,” said the filing, adding that the grid operator “is not aware of any imminent emergency likely to develop on the wholesale electric system that necessitates drastic and immediate action.”

All resource adequacy criteria have been satisfied in New York and are expected to continue to be satisfied for the foreseeable future, said the ISO. For example, on Jan. 7, 2014, New York set a new record winter peak load of 25,738 MW during the polar vortex, and “NYISO met all reliability criteria and reserves requirements without activating emergency procedures at any time during the winter operating period. It did so despite significant generator capacity derates on some of the coldest days, including generation resources that would appear to qualify under the NOPR as ‘eligible grid and reliability resources.’”

The ISO said it has made improvements to its energy and ancillary service markets and incorporated features into its capacity market rules “that reflect the importance of resiliency to withstand severe weather events,” including basing the downstate installed capacity demand curves on peaking plant designs that include dual-fuel capability.

PJM

PJM agrees there is an issue with maintaining reliability, but not the one suggested by the department.

“The DOE didn’t exactly get it right in the way it attempted to articulate the problem,” Stu Bresler, PJM senior vice president of operations and markets, said Thursday.

During a special conference call to preview the RTO’s plan for responding to FERC’s request for comments on the NOPR, Bresler said that the real issue is energy price formation. PJM has been working on that topic for more than a year to respond to concerns over public-policy initiatives impacting market prices.

CEO Andy Ott made similar observations during a media call on Monday, calling it “a tall order” to implement the proposal “and then expect the competitive market to continue to function effectively.”

“The DOE proposal, which essentially is the cost-of-service type of mechanism, we don’t believe is workable. We don’t believe that that is an appropriate response,” Ott said. “We believe [it] is contrary to law and will not really solve any problems. … A better and least-cost solution would be to do proper valuation of resource attributes through a market construct.”

Ott said the proposal is discriminatory because it is exclusive to certain technologies, rather than the service provided to the grid, and only in RTOs with capacity markets — such as PJM.

“PJM does have an abundance of coal and nuclear plants that are in the merchant category, so … it does look like this is certainly targeted at the PJM region,” he said. “We do say that in our comments that this proposal does seem to be focused on this region.”

Bresler said that the NOPR — which cited natural disasters and the 2014 polar vortex to argue that units with large on-site fuel stockpiles should be subsidized to save them from retirement — misses the mark. (See FERC’s Independence to be Tested by DOE NOPR.)

“The point is that just maintaining a whole lot of resources with a 90-day fuel supply on site would not have relieved the problems with a majority of the outages during the polar vortex,” Bresler said. “While the polar vortex did highlight the need for the markets to ensure that we are signaling the need for resources to be able to operate on peak days, just resources with long-term fuel supplies on site was not the majority of the issue.”

During natural disasters, Bresler said, the main challenge is downed power lines, not generating plants being unable to run.

“Events like that … primarily affect the delivery system from supply to demand, not the supply resources themselves,” he said, noting that some coal plants impacted by Hurricane Harvey this summer weren’t able to run at full capacity because their coal piles were soaked.

“In the interest of framing the right problem, we will point out these things that we feel sort of led DOE down the wrong path as far as what the actual problem is,” he said. “We will say, however, that there is an issue that we do need to address, specifically to the PJM region. And that is the fact that there are some instances in PJM where not all resources are valued appropriately for the fact that they are relied upon to reliably meet the demand. … We are concerned that resources right now may not be offering as much flexibility as they could provide because they don’t have incentive to do it.”

Using competitive markets to “transparently” price needs is “superior” to providing cost-of-service payments to certain unit types, he said.

“One concern we have with the DOE approach is it seems to imply that while we may need to keep some of these resources around to ensure reliability and resilience, so therefore let’s keep them all,” Bresler explained. “That again is, from our standpoint, inefficient from the standpoint of the cost to load. Whereas the markets, we believe, have done a very good job to provide the discipline for what really is necessary and what’s not necessary and thereby not just provide efficient signals for entry, but also provide efficient signals for exit.”

PJM’s comments to FERC included a version of a proposal staff presented at its August meeting of the Markets and Reliability Committee. Bresler said the proposal will be revised and presented again at the Dec. 7 MRC meeting.

Ott acknowledged that PJM’s comments don’t reflect the perspectives of all its members.

“There really was no full vetting of these comments with stakeholders,” he said. “One, there isn’t sufficient time, and second is … PJM’s comments are PJM’s and we do not vet those through stakeholders.”

In his comments to FERC, Monitor Bowring said approving the DOE proposal “would replace regulation through competition with an unworkable hybrid of competitive markets and cost of service regulation. The eventual result would be the demise of competitive markets in the PJM region.”

“If the reliability rules need enhancement,” he continued, “the reliability rules should be enhanced. The DOE proposal should be rejected. The PJM region needs more competition, not less.”

MISO

MISO’s comments urged FERC not to adopt the proposal, saying it fails to identify imminent reliability or resilience issues, and said its footprint currently doesn’t have any such issues that would warrant immediate action “beyond the application of ongoing processes and existing tools that address resource availability and retirement in the MISO region.” [Editor’s Note: An earlier version of this article incorrectly reported that MISO did not file its own response.]

“Instead of proceeding in haste with material changes that could have broad-ranging and potentially adverse impacts, MISO urges the commission to move at a deliberate pace, to work through its existing dockets and to leverage its established processes to initiate a full, thorough and public vetting of the issues raised by the proposal,” the RTO wrote.

The RTO told stakeholders earlier this month that they would insist FERC respect the RTO’s existing reliability process, and would study frequency control, ramping, voltage support, inertia and inertial response to identify the features of a “resilient” generator. (See MISO Ready to Define, Study ‘Resiliency’ for DOE.)

SPP

SPP told stakeholders Thursday it would will join the IRC filing, pointing to what staff called “some pretty strong comments.”

“The council does a really good job of laying out why this doesn’t work from an RTO perspective,” SPP General Counsel Paul Suskie told the Strategic Planning Committee.

“If you’re a plant under the rule, your costs are totally covered,” Suskie said. “Why would you do anything but bid zero into the market? It will drive costs down further and distort markets further.”

Some stakeholders expressed discomfort with signing onto the IRC comments without seeing the language.

“The basic issue here is the subsidy,” countered SPP Board Chair Jim Eckelberger, saying renewable energy tax credits had led to oversupply. “We don’t want to screw up the market even more. We should take a strong stand here.”

In its call for comments, FERC said the NOPR’s scope applies to commission-approved ISOs and RTOs with capacity markets and day-ahead and real-time energy markets. Noting SPP’s lack of a capacity market, Suskie said while it “appears this rule is not applicable to SPP,” staff will work under the assumption that a final FERC rule could apply to the RTO.

Suskie said the proposed timeline for action is “impractical.”

“Staff would recommend additional time to implement if the final rule applies to SPP,” Suskie said, noting staff would have to compile a list of eligible facilities. “Staff is very concerned. … If you read what the intent appears to be, basically any coal or nuclear plant not [rate-based] within an RTO would have to be fully compensated.”

Suskie asked who would determine a plant’s rate of return and cost of capital.

“Traditionally, those things are decided at the commissions, not RTOs,” he said. “How do you enforce a 90-day coal supply? How do you enforce whether a plant complies with environmental regulations?

“If this is applicable to SPP, it would be a big sea change,” Suskie said.

Keith Collins, executive director of SPP’s MMU, said his group agrees with much of what Suskie said, saying the NOPR is “proposing a solution to a problem that’s not well defined.”

The NOPR “doesn’t define the problem well in a way that’s actionable and measurable,” Collins said. “When you actually read the [recent DOE grid study], it says more work needs to be done to value and define resiliency before you come up with solutions. What’s included, what’s excluded … it’s hard to say.”

Like Suskie, Collins said the 90-day timeline does not allow sufficient time to properly consider the NOPR.

“If there’s a question to be raised, it can be answered over time, but we don’t support what’s going on,” he said. “Competitive forces have been part of policy in the energy and electricity markets over the last 25 years. It will provide new technologies, batteries and the like, that will improve the resiliency for the grid in ways we’re not aware of today.

“What the Energy Policy Act of 1992 did was promote competitive markets and open access,” Collins said. “If someone can provide power cheaper than someone else, they should be able to do that. If I built a plant a while ago that’s unprofitable, that’s a signal. Resources are indicating they are not being able to recover their costs. We see the consequences of a policy like this with our negative pricing.”

In his filing, Collins said “the SPP markets provide insight into the adverse consequences of policies designed to preserve capacity that would otherwise be uneconomic in typical ISO/RTO markets.

“The SPP market, which is dominated by vertically integrated utilities, provides an example of the potential difficulties that will be faced if the Proposed Rule is implemented,” he wrote. “The SPP market has a considerably high capacity margin, currently trending above 40% compared to the 12% minimum requirement in the SPP Tariff. The excess capacity distorts price formation in the competitive market by encouraging price insensitive offer/bid behavior and mutes price signals for others type of generating technologies.”

CAISO

CAISO said the rule would not apply to it because it does not have a capacity market or coal or nuclear resources that would be eligible for the proposed compensation. But it opposed the rule nonetheless, saying “there is no basis for a universal finding that having a 90-day, on-site fuel supply is essential for ISOs and RTOs to maintain grid reliability or resilience.”

Rich Heidorn Jr. contributed to this article.