By Amanda Durish Cook, Jason Fordney, Tom Kleckner, Rory D. Sweeney and Rich Heidorn Jr.

RTO officials asked FERC on Friday to allow their stakeholder processes time to develop additional resilience measures while urging the commission to require more coordination with natural gas operators and provide more information on cyber threats.

Friday was the deadline for the six jurisdictional RTOs and ISOs to respond to two dozen questions FERC presented in its January order rejecting the Department of Energy’s call for price supports for coal and nuclear generators and creating the resilience docket (AD18-7). ERCOT also responded, although FERC’s jurisdiction over the Texas grid is limited to NERC reliability rules. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)

The order asked RTOs to identify their resilience risks; whether they should assess their resource portfolios against contingencies from the loss of key infrastructure; and the bulk power system attributes that contribute to resilience.

ISO-NE expressed the most acute concerns among the RTOs, saying inadequate natural gas supplies could lead to load shedding on peak days by winter 2024. It said it will need until mid-2019 to develop solutions with its stakeholders.

PJM, however, said RTOs and jurisdictional transmission operators in non-RTO regions should be required to file rule changes needed to address resilience within nine to 12 months. “A deadline … would help ensure focus on these issues in the stakeholder process,” PJM said.

CAISO, meanwhile, criticized FERC’s definition of resilience as “somewhat vague.”

Other parties will have 30 days to respond to the RTO’s filings, although one coalition filed comments earlier last week. (See Coalition Targets Capacity Markets in Resiliency Docket.)

CAISO Says Resilience Order ‘Vague’

CAISO’s comments reflected its changing resource mix and unique circumstances compared with other RTOs, but the grid operator questioned the meaning of the term “resilience.”

“The CAISO notes that the concept of ‘resilience’ presented in the resilience order is general and somewhat vague. It includes no clear objective criteria, metrics or standards to evaluate whether the existing grid is resilient,” CAISO said in comments signed by General Counsel Roger Collanton and other attorneys.

The order also lacks cost-benefit analysis, financing concerns or “prudence assessment,” CAISO said, adding that current reliability standards address many similar issues.

While the ISO criticized aspects of the order, it did detail some challenges it faces, noting that the growth of renewables has put economic pressure on the gas-fired fleet through factors such as the inability to attain resource adequacy contracts and competition for flexibility services such as ramping.

Earthquakes, drought and wildfires are the unique risks facing California, CAISO said in its 176-page filing. It also cited as risks cyberattacks and the closure of the Aliso Canyon gas storage field and the San Onofre nuclear power plant.

There are no baseload coal units in the CAISO balancing area, and the last remaining nuclear plant, Diablo Canyon, is set to retire in 2024. With natural gas generation declining and the system rapidly transitioning to renewables, in part because of the massive expansion of rooftop solar, CAISO has surplus power in daylight hours, resulting in curtailments and ramping needs illustrated by the “duck curve.”

The grid operator said that entities other than RTOs also have a role in providing resilience, such as transmission and generation owners, fuel suppliers, federal and state agencies, environmental groups and others.

CAISO said it did not see a need for an additional requirement for RTOs/ISOs to identify resilience needs as proposed in the order, for multiple generation outage scenarios, fuel disruptions and other events. Analyzing “common-mode” impacts is appropriate and addressed in normal utility reliability planning, it said.

“Creating a new risk-based analysis requirement would likely be overly prescriptive, difficult to clearly define and likely duplicate existing reliability standards given the wide range of varying specific risks different ISOs and RTOs face,” it said.

CAISO said its sensitivity analyses indicate 1,000 to 2,000 MW of retirements could result in shortfalls in load following and reserves after sunset when rooftop solar goes offline. It is supporting multiyear resource adequacy requirements for local capacity resources instead of one year and changing its backstop procurement programs.

The ISO has a filing with FERC regarding its capacity procurement mechanism and reliability-must-run changes, the topic of heavy debate in stakeholder discussions. The ISO’s internal market monitor has filed a protest to the proposal. (See CAISO, Stakeholders Debate RMR Revisions.)

Studies that CAISO has conducted include gas-electric coordination planning studies for both Southern and Northern California, as well as frequency response studies related to the replacement of conventional thermal resources with renewables, storage and distributed energy sources. Special reliability studies are done during the transmission planning process.

The grid operator added that the question as to whether the grid could “reasonably withstand” high-impact, low-frequency events was not defined and is difficult to respond to.

CAISO asked for a “a holistic approach that also considers the unique circumstances and conditions facing each region” as the resilience criteria is considered.

ERCOT, Texas PUC: Consider All Foreseeable Threats

ERCOT and the Public Utility Commission of Texas filed joint comments in the docket, although they noted that the Texas grid operator does not fall within the Federal Power Act’s definition of an RTO or ISO and “therefore does not fall within the coverage of the commission’s order.”

Still, both entities saw “great value in providing input” because it could inform FERC’s “possible application of its authority over public utility tariffs” and affect the potential development of NERC reliability standards, to which ERCOT is subject.

The two entities agreed with FERC’s concept of resilience. “Any disturbance to the bulk power system that impairs the continuous provision of electric service has, to that same extent, impaired reliability,” they said. “ERCOT and the PUC view resilience as an important subset of their existing reliability responsibilities.”

They urged FERC to look beyond “high-impact, low-frequency events” such as cyberattacks, fuel-supply disruptions and extreme weather events. “The ultimate goal of policymakers should be to ensure that all foreseeable threats to the reliability of the bulk power system are identified and addressed in the most cost-effective way,” they wrote.

ERCOT and the PUC also underscored the importance of Texas’ energy-only market design in ensuring system resilience, saying it “is inextricably linked to long-term system reliability.” As an example, they referred to February 2011, when cold temperatures knocked several generators offline and market prices hit the cap ($3,000/MWh, which has since been raised to $9,000/MWh).

“This resulted in severe financial consequences to generators with day-ahead commitments that failed to generate in real time, just as it greatly rewarded those generators that stayed online during the event,” ERCOT and the PUC said. Subsequent improvements in plant weatherization resulted in “substantially fewer generators suffering equipment failures” during similar events in 2017 and 2018.

“In short, ERCOT’s scarcity pricing mechanisms are designed to alleviate the need for many resilience-based regulatory controls,” they wrote in the 22-page filing.

ERCOT and the PUC said they address resilience concerns in operating and planning the grid, noting the “greater penetration of renewable resources … compared with most other ISOs” and the “greater vulnerability” they pose to certain extreme weather events.

“ERCOT has robust processes in place to ensure the ERCOT system will be operated in a way that can resist and recover from a variety of foreseeable disturbances,” they wrote. “These processes will continue to identify other areas for improvement as the system evolves.”

ISO-NE Sees Growing Fuel Security Risks

ISO-NE filed a 61-page response citing winter fuel security as its most significant resilience challenge and asking FERC to allow it until the second quarter of 2019 to develop a long-term solution through its stakeholder process.

The RTO said the stakeholder discussions will build on the sobering findings of its Operational Fuel Security Analysis (OFSA) report issued in January, which found the region would face energy shortfalls because of inadequate natural gas supplies in almost every fuel-mix scenario by winter 2024/2025, “requiring frequent use of emergency actions to fully meet demand or protect the grid.” (See Report: Fuel Security Key Risk for New England Grid.)

ISO-NE said potential solutions range from “changes to Pay-for-Performance parameters to market designs that increase incentives for forward fuel supply and resupply to inclusion of opportunity costs associated with scarce fuels and emission allowances.”

“New England’s fuel-security challenges do not lend themselves to easy solutions. Thus, the proposed time frame is necessary to allow for a systematic and deliberative regional process for examining the risks and possible solutions — a complex undertaking,” the RTO said. “A key question to be addressed in these discussions will be what level of fuel-security risk ISO-NE, the region, policymakers and regulators are willing to tolerate.”

The RTO noted that New England lacks indigenous fossil fuels production, leaving it reliant on imported fuels, including from five interstate natural gas lines whose winter capacity is mostly consumed by local distribution companies for heating. Generators are dependent on capacity released by utilities in the secondary market.

ISO-NE said it has made changes to its market design, operating procedures and systems since identifying fuel security as a problem during a cold spell in 2004. The RTO noted corrective actions it has taken, citing a change in the timing of the day-ahead market to give generators more time to procure gas; allowing market participants to modify their offers on an hourly basis to reflect changing fuel costs; Pay-for-Performance rules, which will take effect June 1; and the winter reliability program that Pay-for-Performance will replace.

But the problem has worsened as generators with onsite fuel have retired, largely replaced by natural gas-fired generators relying on just-in-time deliveries.

Changing Fuel Mix

In 2000, oil- and coal-fired power plants produced 40% of the electricity generated in New England, while natural gas fueled just 15%. Since then, the region added 16,000 MW of gas-fired generation while losing 4,600 MW of non-gas generating capacity.

By 2016, gas-fired generation was responsible for 49% of the RTO’s power, with coal and oil reduced to 3% of production, although they remain almost 30% of the region’s capacity. Natural gas’ generation share is expected to grow to 56% in 2026 while another 5,000 MW of coal- and oil-fired generation is at risk for retirement.

During the December 2017-January 2018 cold spell, oil and coal plants, which had been producing only 2% of the region’s electricity, were called on to supply one-third of New England’s power. Natural gas-fired generation dropped from almost half to less than one-quarter.

“With oil-fired generation operating at or near capacity, oil supplies, as well as emission allowances, at power plants around the region began to deplete rapidly over the two-week period, making system operations extremely challenging and significantly increasing the reliability risk to the system,” ISO-NE said.

The region, which has relied on dual-fuel capability in previous winters, said that option is becoming less viable “as emissions restrictions are tightening dual-fuel generators’ ability to use the oil-firing capability.”

The OFSA report was the first time ISO-NE had performed a deterministic analysis that looked at the entire three-month winter season between December and February as opposed to a single forecast winter peak day.

The study found that load shedding would be needed to maintain system balance in 19 of the 23 scenarios considered and that extended outages of any key energy facilities — the Distrigas and Canaport LNG terminals; the Millstone nuclear plant; or an interstate pipeline compressor station — would result in as much as 138 hours of load shedding.

The analysis said load shedding could be minimized with higher levels of LNG, imports and renewables, changes that would require new transmission and “advanced arrangements for LNG with assurances for winter delivery.”

While most of its response focused on fuel security, ISO-NE also cited as risks cybersecurity, physical security and geomagnetic disturbances, issues it said were being addressed “in other forums.”

MISO: Work Already in Progress

MISO’s filing focused on the practices it already has in place to promote resilience and pointed out that its stakeholder processes and projects have been geared toward resilience “for nearly two decades.” The RTO said it doesn’t have any “imminent or immediate” resilience concerns.

“MISO’s core foundation of ensuring regional reliability needs are met at the lowest possible cost has facilitated the creation of robust planning, operations, markets and security mechanisms that are utilized to not only identify, assess and avoid resilience threats, but also to mitigate any impacts that may occur from high-risk events,” the RTO said.

Vice President of System Planning Jennifer Curran said MISO already works with stakeholders to ensure daily grid reliability and resilience.

“Grid resilience is core to our foundation and day-to-day activities at MISO,” Curran said in a statement that the RTO issued in addition to the 52-page response to FERC. “We constantly evaluate our operations and look for opportunities to strengthen our systems, reduce risk and contribute to the dialogue and knowledge-sharing that benefits the industry and the power grid.”

MISO said it addresses resilience through its biennial Market Roadmap, a process in which it and its stakeholders identify the most pressing market improvements to undertake. (See MISO Accepting Market Roadmap Ideas.) The RTO also said it enhances resilience through gas-electric coordination, drills on severe weather and other emergencies, and its annual Transmission Expansion Plan process. It currently studies “approximately 6,500 extreme events impacting loss of multiple facilities on the transmission grid” and maintains a cyber operations team to monitor critical systems.

In researching disruptive events, it said it found only one scenario that would violate the one-day-in-10-years planning criteria: “the extreme and long-term event of the loss of the largest natural gas pipeline for the entire summer peak season.”

During January’s extreme cold snap, MISO said it was armed with a better understanding of the limitations of the natural gas supply. (See MISO in 2018: Storage, Software, Settlements and Studies.)

It also said the replacement for its market platform computer system was selected following a “comprehensive assessment to determine the system performance and security requirements that will be necessary to meet MISO’s long-term needs.” (See MISO Makes Case for $130M Market Platform Upgrade.)

While MISO said it generally agreed with FERC’s definition of resilience, it urged the commission to add a nod to the “changing nature of the electric grid.”

For FERC to facilitate a resilient grid, MISO said the commission should make sure “inflexible” critical infrastructure protection compliance standards do not limit cybersecurity measures. It also urged the commission to research how to value resilience in the transmission planning process and “actively support” more efficient interregional operations that can respond to disruptions.

MISO called for “broader introduction of advanced operational tools” that can improve situational awareness and congestion management. “Current limitations in both processes and tools restrict the efficient use of transmission and redispatch opportunities to fully leverage available infrastructure. These limitations result in fewer operational options to address unplanned events that may test grid resilience,” the RTO said.

As an example, it said, using the interregional transmission load relief (TLR) process to manage congestion may become inadequate as more intermittent resources join the grid. “RTO/ISO energy market advancements have facilitated the development of superior market-based congestion management tools, including redispatch, seams coordination and market-to-market processes that improve reliability and reduce costs (particularly when compared to TLR),” it said. It cited its coordination with PJM as “the model for seams operation” that could be applied “to advance interregional operations more broadly.”

But MISO also said resilience planning shouldn’t rest with RTOs and ISOs alone.

“The commission’s evaluation of resilience issues should not be limited to just RTOs and ISOs; rather, grid resilience is a national issue that broadly impacts the bulk power system. Additionally, to the extent the commission is interested in addressing concerns at the distribution level, the commission should work in partnership with state regulators to help ensure a coordinated effort,” MISO said.

NYISO Cites ‘Track Record,’ Current Initiatives

NYISO’s 26-page response noted that its most recent Reliability Needs Assessment concluded that the ISO will meet its transmission security and resource adequacy requirements through 2026.

It also identified six initiatives it is pursuing to respond to challenges resulting from “technological developments, economics, environmental considerations and public policies” transforming the grid: re-evaluating its ancillary services products and shortage pricing; ensuring that market price signals incentivize compliance with dispatch instructions; considering changes to the measurement of capacity to reflect resource performance during critical operating periods; evaluating deliverability and performance requirements for external capacity resources; potential enhancements to interregional transaction coordination; and better integration of energy storage and distributed energy resources.

It also said it will perform a “comprehensive re-evaluation” of its planning process to ensure it “stands ready to facilitate the transmission infrastructure additions and upgrades and other resources necessary to meet the evolving needs of the grid.”

In addition, the ISO said its markets “inherently value and support elements of resilience,” including the use of shortage pricing in the day-ahead and real-time markets. Since the 2013-2014 winter, the ISO said it has boosted the statewide 30-minute reserve requirement by 655 MW to 2,620 MW and implemented a new reserve region for Southeastern New York with a 1,300-MW operating reserve requirement.

It also cited its fuel inventories, gas-electric coordination and improved situational awareness from phasor measurement units added to the grid in recent years.

NYISO also pointed to the importance of its interconnections with neighboring regions, saying its exports helped ISO-NE survive fuel supply challenges during the cold weeks surrounding New Year’s Day and “provided significant levels of emergency energy” to PJM for five hours on Jan. 7.

The ISO said its public policy planning process could result in changes to require additional resilience beyond that necessary to achieve minimum reliability requirements or additional infrastructure to improve energy delivery capability. Thus far, the process has identified two transmission needs: the 345-kV transmission project in western New York, expected in service in 2022; and AC transmission additions to relieve congestion on the UPNY-SENY and Central East interfaces.

The ISO said that because there are differences of opinions regarding the definition of resilience, “the commission could potentially facilitate this dialogue through a technical conference to explore near-term concepts being considered across the diverse regions of the country.”

It also asked FERC to trust its stakeholder process, saying it “has a proven track record of success in addressing the challenges and opportunities facing the bulk power system and wholesale energy markets in New York.”

“In recognition of this success, the NYISO respectfully requests that the commission allow the NYISO to continue to work with its stakeholders in assessing and developing the enhancements necessary.”

PJM Seeks More Coordination with Pipelines, LDCs

PJM says its grid is stable and secure but urged FERC to demand changes to improve identification and mitigation of current vulnerabilities and future grid resilience challenges. The RTO also touted itself as a good example in several areas and asked FERC to make other grid operators follow its lead.

The RTO’s 84-page response also offered revisions to FERC’s proposed definition of resilience: “The ability to withstand or reduce the magnitude and/or duration of disruptive events, which includes the capability to identify vulnerabilities and threats, and plan for, prepare for, mitigate, absorb, adapt to and/or timely recover from such an event.” The RTO said the definition needs to “accurately reflect” grid operators’ capabilities without imposing “additional liabilities and … a new duty and standard of care.” FERC should also stipulate that enhancing resilience is one of grid operator’s responsibilities within regional planning, the RTO said, and that the commission has authority over resilience under its responsibility under the FPA to ensure “just and reasonable rates, terms and conditions of service.”

While acknowledging the risks of high-impact, low-frequency events, PJM also warned about “addressing vulnerabilities that evolved over time and threaten the safe and reliable operation.” It asked that FERC develop a process for grid operators to receive a review and feedback on their threat and vulnerability assessments based on national security information the commission has access to that grid operators don’t.

PJM said it has already begun addressing flaws within its operating reserve, shortage pricing, black start, energy price formation, and integration of DERs and storage. (See “Stakeholders Challenge PJM Decisions on Reserve-Shortage Identification,” PJM OC Briefs.)

Restoration Needs

Interestingly, PJM also asked that it be required to develop procedures to “permit non-market operations during emergencies, extended periods of degraded operations or unanticipated restoration scenarios … including provisions for cost-based compensation when the markets are not operational or when a wholesale supplier is directed to take certain emergency actions by PJM for which there is not an existing compensation mechanism.”

PJM said work like it’s doing to require dual-fuel capability at all black-start units should be extended throughout the country to identify “critical restoration units” and fuel-assurance criteria for them. (See “Black Start RFP,” PJM Operating Committee Briefs: Feb. 6, 2018.)

Pipeline Coordination

PJM also sought help in improving information sharing and coordination with gas pipelines, asking FERC to:

• Require information sharing by pipelines by revising the “voluntary nature” of Order 787;
• “Encourage” pipelines to share their threat and vulnerability analyses with grid operators, along with real-time contingency modeling and restoration-planning coordination;
• Encourage development of additional pipeline services tailored to the flexibility needs of gas-fired generation “beyond today’s traditional firm/interruptible paradigm”;
• Work with the Transportation Security Administration and the Pipeline and Hazardous Materials Safety Administration to improve “harmonization of cyber and physical security standards between the electric sector and the natural gas pipeline system”; and
• Support more communication and coordination with local distribution companies supplying generators, perhaps by imposing obligations on local distribution companies through interstate pipeline tariffs.

Grid operators should also be required to show how they’re coordinating with other “critical interdependent infrastructure systems” like telecommunications and water utilities, PJM said.

SPP: One-Size-Fits-All Approach ‘Not Appropriate’

SPP agreed with the commission’s approach to evaluating resilience, saying FERC should continue its holistic approach and “consider the roles and relationships all participants in the electric industry, not just RTOs and ISOs, have with respect” to the grid’s resilience.

In its 21-page response, SPP wrote that it “agrees with the commission’s premise that a one-size-fits-all approach to resilience is not appropriate given the differences that can exist between the various regions.”

It stressed the importance of weighing the potential benefits against the costs in considering changes to current requirements. “Changes to requirements to address resilience could increase the costs of transmission owners’ systems, and those increased costs would ultimately impact transmission customers and their end-use customers,” SPP said.

“Accordingly, SPP respectfully submits that the perspectives and practices of non-RTO entities, including, without limitation, transmission owners, generation owners and state regulators, should be sought out and considered, as different participants in the electric industry can provide valuable insight regarding their experiences.”

The RTO said FERC’s definition of resilience is “a reasonable way to capture the concept” and said it is consistent with a framework NERC is using. The reliability organization’s Issues Steering Committee told the Board of Trustees in February that most resilience definitions have two common elements: that resilience is “time-dependent” and differs from business-as-usual operations, and that it cannot be measured in a single-unit metric. (See “FERC’s McIntyre Says Resiliency Still of Interest in DC,” NERC MRC/Board of Trustees Briefs: Feb. 7, 2018.)

The committee’s framework includes four outcome-focused capabilities:

• Robustness: the ability to absorb shocks and continue operating.
• Resourcefulness: the ability to skillfully manage a crisis as it unfolds.
• Rapid Recovery: the ability to restore services as quickly as possible.
• Adaptability: the ability to incorporate and improve with lessons learned from past events.

SPP said its approach is based on “(1) resolving potential problems before they have a chance to disrupt daily operation … and (2) restoring daily operation as quickly and seamlessly as possible in the event a disruption does occur.”

It cited the resilience benefits of new transmission. “The construction of new transmission facilities pursuant to modern design standards enhance the robustness of the system,” SPP said.

“Continually evaluating risk and upgrading equipment, tools and procedures … facilitates rapid recovery by minimizing the extent and impact of disruptions.”

SPP said its approach remains adaptive, “as it is based on historical experience … combined with forward-looking evaluation of new risks and evolving technologies used in the industry.”