By Rich Heidorn Jr.

What is “resilience?” How can you measure it? And how much can be achieved through just and reasonable rates?

Those are the questions FERC and grid operators will be answering following the commission’s rejection last week of Energy Secretary Rick Perry’s proposed rulemaking to benefit coal and nuclear generators (RM18-1).

FERC’s ruling created a new docket (AD18-7) and requires RTOs and ISOs to respond to two dozen questions about how they assess resilience. The commission said it will use the responses to determine whether additional action is necessary. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

Defining, Measuring Resilience

FERC teed up the new proceeding by inviting comment on its suggested definition of resilience: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”

It also asked grid operators to identify what attributes contribute to resilience and how they will obtain them. They are likely to look to NERC’s definition of “essential reliability services,” which the commission also referenced in its order. (See NERC Report Urges Preserving Coal, Nuke ‘Attributes’.)

FERC offered less guidance on how the grid operators can measure resilience. There is no widely embraced equivalent to the one-day-in-10-years loss-of-load expectation used as a reliability benchmark.

Also unclear is how much it could cost to meet such a resiliency target; any proposal that increases costs is likely to face opposition from stakeholders serving load. In PJM, for example, load representatives — who have long complained of paying for excessive capacity reserve margins — are opposing the RTO’s “price formation” proposal that could boost costs by as much as 5%.

In FERC filings in October, RTO officials and their Market Monitors unanimously rejected Perry’s Notice of Proposed Rulemaking as expensive, inefficient and counterproductive. (See RTOs Reject NOPR; Say Fuel Risks Exaggerated.)

Predictions

ClearView Energy Partners said it is “skeptical of FERC making findings within this docket that lead to determinations that existing tariffs in particular RTOs are suddenly unjust and unreasonable on resiliency grounds.”

“Substantive changes to energy market tariffs to increase compensation for ‘baseload units’” are unlikely, ClearView added. FERC “may be more likely to pursue a rulemaking, or set of issue-specific rulemakings or policies, instead.”

“I think it’s safe to say that what comes of compensating resources for ‘grid resiliency,’ to the extent it occurs, will look little or nothing like what Secretary Perry had intended,” wrote Jason Johns, a partner with Stoel Rives, in a blog post.

Prior Efforts

The commission started the grid operators’ 60-day clock with the issuance of the order, making the deadline for their answers March 9. Responses to the filings will be due in an additional 30 days.

The new proceeding will be informed both by state initiatives to preserve in-state generation and RTO efforts that began before Perry’s NOPR and the Department of Energy grid study that preceded it.

The coal and nuclear industries say the RTOs have not addressed market failures unfairly punishing their generators.

“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,” the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association said in a joint FERC filing in October. “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.”

Below is a summary of the RTOs’ prior comments on their resilience efforts and issues that may factor in the new proceeding.

CAISO: Resilience ‘Mechanisms in Place’

CAISO told FERC last year that Perry’s proposed rule would not apply to it because it does not have a capacity market, nor coal or nuclear resources that would be eligible for compensation.

CAISO “already has mechanisms in place that ensure” its resilience, the ISO said. “Regional planning, procurement, coordination, programmatic and reliability efforts in the CAISO [balancing authority area] have produced a diverse infrastructure and ‘set of tools’ that have enabled the CAISO to operate a system that has remained both reliable and resilient in the face of significant threats to the loss of supply such as with the restricted operations of the Aliso Canyon gas storage facility, the unexpected shutdown of the San Onofre Nuclear Generating Station, fires affecting transmission lines, severe droughts and the solar eclipse.”

ISO-NE: ‘No Urgent Need’

ISO-NE told FERC in October that “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.”

Last week, the RTO asked FERC for approval of a controversial two-stage capacity auction intended to replace aging fossil fuel generators with renewable resources from state procurements. (See ISO-NE Files CASPR Proposal.)

The RTO says it has improved gas-electric coordination to mitigate supply problems arising from natural gas pipeline constraints. Its Pay-for-Performance program, which offers compensation for dual fuel generators and increases penalties for those who fail to meet capacity obligations, takes effect June 1.

But New England remains vulnerable to the limits of its gas pipeline system, leading some to suggest resilience measures should include contingency plans that consider the loss of a pipeline supplying multiple generators.

“You’d probably be the market that keeps me up at night,” Commissioner Robert Powelson told ISO-NE Vice President of System Operations Peter Brandien in October, when RTO officials made their annual presentations on winter preparedness.

SPP, Exempt from NOPR, ‘Will be Engaged’

SPP was not covered by Perry’s proposal because the RTO lacks a capacity market. The RTO said last week it “applauds FERC’s decision and appreciates [its] commitment, through the opening of a new docket, to continue to ensure our nation’s electric grid is both reliable and resilient. As with all of FERC’s efforts, SPP will be engaged in this new docket.”

The RTO has been integrating increasing amounts of wind, thus far without reliability problems. Last month, the RTO set a new record for wind penetration (56.25%), lending credence to its claims that it can handle penetration levels as high as 75%.

SPP’s 40% capacity margin is well above the 12% minimum required by the SPP Tariff, Keith Collins, executive director of SPP’s Market Monitoring Unit, noted in comments to FERC in October.

MISO Welcomes ‘Broader’ Discussion

MISO spokesperson Mark Brown said last week the RTO is looking forward to a “broader industry discussion around resilience and its importance” with FERC, state regulators and other industry officials.

“As FERC noted in its order, MISO is involved in ongoing development of a long-term plan to address changing system needs as the resource mix evolves,” Brown said in a statement to RTO Insider. MISO’s plan involves multiple studies, including an analysis on the challenges of integrating growing volumes of renewable generation and how the natural gas supply affects its dispatch ability. (See MISO to Conduct Long-Term Renewable Integration Study and MISO in 2018: Storage, Software, Settlements and Studies.)

The RTO has been stymied in its attempts to address resource adequacy concerns in Zone 4 in Southern Illinois, where Dynegy has threatened to close some of its coal-fired generation, citing insufficient capacity revenues.

At the behest of Gov. Bruce Rauner, the Illinois Commerce Commission is conducting an inquiry on the issue, which included a workshop last month. (See MISO Zone 4 Players Still Divided over Resource Adequacy.)

The Illinois Clean Jobs Coalition responded to the FERC ruling by urging the ICC “follow the lead of FERC and reject Gov. Rauner’s proposal to bail out uneconomic coal plants in Illinois.”

The commission will hold another workshop Jan. 16. Final comments on the issue are due Jan. 30, and the commission is expected to issue a summary report by Feb. 26.

PJM Price Formation Proposal Faces Opposition

PJM responded to the DOE NOPR by calling for rule changes that would allow inflexible generators, including coal and nuclear plants, to set LMPs. At its final stakeholder meeting of the year, the RTO won endorsement for a stakeholder task force to examine the current rules and recommend fixes.

PJM estimates the energy market changes will reduce capacity market costs but still increase overall costs between 2 and 5% ($440 million to $1.4 billion annually). (See Rule Changes Could Spur $1.4B Jump in PJM Market Costs.)

Monitors, regulators and other RTOs filed comments opposing PJM’s proposal in November. PJM Independent Market Monitor Joe Bowring said the plan would undermine the RTO’s markets and suggested that the RTO was acting in the interest of Exelon, which would be the biggest winner from a boost to nuclear plants. (See NOPR Reply Comments Bring More Criticism of PJM Proposal.)

Beginning in delivery year 2020/2021, all PJM capacity resources must meet the RTO’s Capacity Performance requirements. The CP program employs performance penalties and bonuses like ISO-NE’s Pay-for-Performance initiative.

ERCOT Joining with PUC on Response

At the Texas Public Utility Commission’s open meeting Thursday, Chair DeAnn Walker said she is working with ERCOT CEO Bill Magness and General Counsel Chad Seely to prepare a response to FERC’s order.

ERCOT’s markets are not regulated by FERC, but the grid operator is subject to mandatory reliability rules overseen by the commission and NERC. The PUC has always aggressively defended ERCOT’s independence from federal oversight.

Walker characterized the filing as informational, saying it would “explain how we do things here.” She said she, ERCOT’s leadership and Texas Reliability Entity CEO W. Lane Lanford “have similar thoughts about how broad” FERC’s request is. She promised further details for a February open meeting.

FERC’s influence on the future of coal and nuclear generation will not be limited to the new docket. It may again be asked to weigh in on whether state efforts to support in-state generators violate federal jurisdiction. The Supreme Court has ruled on three cases concerning state-federal jurisdiction since 2015. (See Court’s Reticence Frustrates Energy Bar.)

The commission already has pending a request from the Electric Power Supply Association to apply the minimum offer price rule to nuclear units receiving payments under Illinois and New York’s zero-emission credit programs. The ZEC programs are also being challenged in federal court. (See Ill. ZECs Defenders Face Harsh Questioning on Appeal.)

NYISO Moving on Carbon Pricing

Despite the legal challenge to its ZEC program, New York officials last week continued working on their plan for funding the subsidies — integrating carbon pricing in NYISO’s wholesale electricity markets. (See New York Stakeholders Debate Carbon Policy ‘Issue Tracks’.)

“There is no imminent threat to reliability,” NYISO told FERC in October. During the 2014 polar vortex, NYISO noted, it set a new record winter peak load and “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, ancillary service and capacity markets, including basing the downstate installed capacity demand curves on peaking plant designs that include dual-fuel capability.

State Initiatives

Here are some of the state initiatives that could become factors:

• The New Jersey Legislature is expected to consider a ZEC-style plan in its 2018-19 session. ClearView analysts last week gave the plan a 65% chance of success, saying the Democrat-controlled legislature’s refusal to consider the bill in the lame duck session was intended to deny outgoing Republican Gov. Chris Christie a policy “win.” (See NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)

  

• Ohio lawmakers last year proposed legislation (H.B. 381 and S.B. 128) that would create a ZEC-style program that would benefit First Energy Solutions’ Davis-Besse and Perry nuclear plants, but the bills did not move out of committee. The term of Gov. John Kasich, who has opposed a nuclear “bailout,” expires in January 2019.
• Connecticut is also considering whether it needs to sign a long-term power purchase agreement to keep the Millstone nuclear plant operating amid a dispute over the plant’s profitability. (See related story, Conn. Regulators Hear Conflicting Advice on Millstone.)

“We applaud the commission for upholding the rule of law and taking the only appropriate actions under the circumstances,” the National Association of Regulatory Utility Commissioners said in a statement last week. “We also appreciate FERC’s acknowledgment that resilience issues ‘extend beyond the commission’s jurisdiction’ and its explicit encouragement for interested entities to engage with state regulators and others to address resilience at the distribution level.”

Amanda Durish Cook and Tom Kleckner contributed to this article.