Page 1382 – RTO Insider

May 9, 2018

Report: Customer Needs Should Lead Resilience Effort

By Tom Kleckner

With the deadline for filings in FERC’s resilience docket looming, two aides to former FERC Chairman Pat Wood III last week sought to reset the definition — saying resilience is about transmission and distribution, not generation.

In a report funded by the Natural Resources Defense Council and the Environmental Defense Fund, Alison Silverstein and Rob Gramlich say resilience should be measured from the customers’ perspective: the number of outages (frequency), customers affected per outage (scale) and length of time before restoration (duration).

“Customers pay the ultimate price for power outages, whether through their electric bills or their own personal losses and expenditures,” says the study, whose third author is Michael Goggin, who worked with Gramlich at the American Wind Energy Association and has since joined Gramlich’s consulting firm.

DER FERC Resilience Walkemeyer-North Liberal transmission project — Silverstein | © *RTO Insider*

Silverstein, the former senior energy policy advisor to Wood, made headlines last year when, after helping coauthor the Department of Energy’s grid study, she denounced DOE Secretary Rick Perry for using it as a pretext for price supports for struggling coal and nuclear plants. (See Author of DOE Grid Study Disputes Recommendations.)

The DOE NOPR sought “resilience” payments to power plant with 90 days of fuel on site.

In rejecting the NOPR in January and initiating the resilience docket, FERC offered its own definition of the term: “The ability [of the grid] 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.”

RTOs made filings in the docket in March. Comments on the RTO filings are due May 9 (AD18-7). (See RTO Resilience Filings Seek Time, More Gas Coordination.)

The Silverstein-Gramlich-Goggin report was filed in the docket Tuesday. [Editor’s Note: RTO Insider will have coverage of the filings later this week.]

“I’m a customer, you’re a customer. We operate the grid for the customer, not just for our jollies,” said Silverstein, in an interview. “It seemed to me that if the point of preventing outages is protecting the customer, as NERC and others assert, we should look at the most effective ways of measuring resilience.”

The report notes the vast majority of outage events occur at the distribution and transmission levels because of weather events — which has only led customers to expect more outages.

The authors cite a Rhodium Group study that found less than 0.1% of customer-outage minutes in 2012-16 were caused by generation shortfalls or fuel supply issues. The study found most outages can be attributed to routine causes such as local storms, vegetation, squirrels and equipment problems, with high-impact, low-frequency events such as hurricanes and winter storms causing about half of customer outage-minutes.

“We cannot prevent and mitigate all the hazards and threats that cause outages, and we can mitigate some but not all of their consequences,” the authors write. “So which risks should we take, what level of resilience and mitigation cost are we willing to bear and how should we choose among resilience measures?”

The paper doesn’t answer the risk question, but it does offer a path for “assessing and selecting resilience regulatory policy options.” The report suggests regulators and stakeholders ask how each remedy “might reduce the frequency, magnitude and duration of customer outages relative to the entire scope of customer outages, not just those resulting from generation- or transmission-level causes.”

In attacking the problem, Silverstein said she borrowed from the Rocky Mountain Institute’s co-founder and chief scientist, Amory Lovins, who has said you can solve the energy problem by enlarging it. By carving problems into bite-sized chunks, Lovins has said, “you don’t have a big enough design space to have enough options, degrees of freedom and synergies.”

“There’s a big difference between generation resilience and the resilience of the power system and resilience from customers’ perspective,” Silverstein said. “When you look at resilience from the customer’s perspective, there’s a whole lot of ways to solve the problem quickly. If I spend a fortune on reducing generation failures, that’s a whole lot of money that could have been spent on tree trimming or strategic spare equipment. Tree trimming and situational awareness are not addressed by a generation resilience proposal.”

Because most outages occur at the distribution level, Silverstein, Gramlich and Goggin write, “it logically follows that measures that strengthen distribution and hasten recovery would be highly cost-effective.”

One example of this would be mobile substations, which proved invaluable during Hurricane Harvey’s restoration effort. Other examples include hardening distribution poles, physical security, outage-management systems, mutual assistance, and emergency planning and drills.

Silverstein said this will become even more important as severe weather events continue to increase in the years ahead. According to the report, the United States weathered 16 “disaster events” last year, each incurring at least $1 billion in damages. Most of the events damaged some electric system infrastructure and caused service disruptions, totaling more than $350 billion in damages.

“We really need to take that threat seriously and think about how to design power system architecture and assets for the long-term threat,” she said. “A lot of the designs today were developed in the early 1900s. The weather is going to be a lot more severe and meaner 10, 20 and 30 years in the future. We designed the grid for Ozzie and Harriet weather. What’s coming at us is Mad Max.”

May 9, 2018March 25, 2025

Don’t Rush on Resilience, Commenters Urge

Warn Against PJM Overreach, Abandoning Stakeholder Process

By RTO Insider Staff

FERC should let RTO stakeholder processes work and not issue broad and costly new mandates on grid resilience, commenters told the commission in its proceeding to examine the resilience of the bulk power system in the nation’s RTOs (AD18-7).

RTO Insider’s review of more than 40 of the dozens of comments filed ahead of the May 9 deadline indicated widespread support for RTOs’ requests in their initial filings in March for time to discuss the issues with stakeholders, more coordination with natural gas operators and more information on cyber threats. (See RTO Resilience Filings Seek Time, More Gas Coordination.)

But many commenters criticized PJM’s call for setting firm deadlines for rule changes, saying the RTO’s proposals would increase costs without necessarily improving resilience.

In a joint filing, CAISO, MISO, NYISO, SPP and ISO-NE asked FERC not to impose PJM’s proposals in their regions.

“The record in this proceeding does not support any universal resilience standard or tariff changes requirements to be applied to all RTOs/ISOs. To the contrary, the record demonstrates that RTOs/ISOs have different resilience issues and priorities, and requiring all RTOs/ISOs to follow PJM’s proposed schedule on the issues pertinent to PJM will undermine each RTO/ISO’s efforts to address the specific challenges within its region,” they said. “Thus, the commission should reject PJM’s requests and allow individual RTOs/ISOs to pursue the resilience-related issues and initiatives they have identified in their region through collaborative efforts with their stakeholders and pursuant to the timeframes they have established.”

Others, including the Advanced Energy Management Alliance, agreed that RTOs should continue their existing efforts to address their unique challenges. “PJM’s explanation of the need for changes to certain energy and ancillary market rules is helpful to inform the commission as to areas PJM is working on, but PJM cannot ask FERC to require rule changes to be filed in pre-emption of the stakeholder process or development of an evidentiary record that change is necessary.”

After rejecting the Department of Energy’s call for price supports for coal and nuclear generators in January, the commission asked its six jurisdictional RTOs and ISOs to respond to two dozen questions on resilience. This week’s deadline was for responses to the RTOs’ comments.

The comments touched on topics including FERC’s jurisdiction, fuel security, cyber threats and climate change, as well as individual regional issues.

Jurisdictional Concerns

Several commenters raised jurisdictional issues, noting that states, not FERC, have authority over distribution systems where most outages occur. Arizona Public Service said NERC’s reliability standards already address resilience.

“Before taking any additional steps to address resilience, the commission [should] consider the … comprehensive federal, state and industry efforts [that] address all levels of the electric grid and significantly contribute to ensuring” resilience, APS said. The utility criticized proposals it said “are clearly focused upon expanding the role of ISOs and RTOs and are, without understanding efforts at the state level and among utilities commercially, premature.”

The Pennsylvania Public Utility Commission as k e d FERC to “clearly articulate” its jurisdiction regarding resilience, saying it disagrees with PJM’s assertion that resilience is “‘within the commission’s existing authority with respect to the establishment of just and reasonable rates under the Federal Power Act.’ Therefore, clear and precise justification of FERC’s authority on this matter will be beneficial prior to any initial steps in regulating resilience,” the PUC said.

Entergy also disagreed with PJM’s “overly broad” interpretation of the commission’s jurisdiction.

The Large Public Power Council (LPPC) agreed with commission’s proposed definition of resilience but urged that “to the extent further rules or standards are considered, FERC must be mindful of the statutory limits on its authority,” saying the Federal Power Act does not provide the agency a general grant of authority “to take action on reliability or resilience outside its specific statutory role in the approval and enforcement of standards.”

The LPPC also contended there is “no basis” for applying any rule governing resilience to non-RTO areas, as had been recommended by MISO and PJM. “This is not an issue within FERC’s domain in non-RTO regions, where states and localities maintain authority over generation investment decisions and cost recovery,” the group said.

Cyber Threats

PJM’s Transmission Owners Agreement-Administrative Committee (TOA-AC) said their members need more information from the government on potential cyber threats. “The threat data that resides at, for example, the Department of Energy, Department of Homeland Security, National Security Council and Department of Defense is vital for the RTO/ISOs to have access to for developing and implementing effective protection mechanisms,” they said.

“Therefore, it is essential that the commission develop a process by which PJM may receive verification concerning the reasonableness of vulnerability and threat assessments based on internal government data that has not been made available to RTOs on national security grounds.”

Climate Change’s Role

The Center for Climate and Energy Solutions said that FERC’s scope of grid resilience lacks an acknowledgment of climate change and how it could hinder resilience.

The environmental nonprofit said that although it would prefer FERC order “an economy-wide pricing mechanism” to absorb the economic impacts and even prevent some physical impacts of climate change, it said the commission should at least ensure that wholesale power markets are “internalizing the costs of carbon emissions” through carbon pricing.

The center added that increasing regularity of droughts threatens cooling systems for generating stations and rising temperatures will impede the capacity of bulk transmission lines to transport power. The nonprofit called on FERC to convene a technical conference to explore best practices for an industry coping with global warming.

Fuel Supplies

Numerous commenters cited the certainty of fuel supplies as an essential element of resilience.

NERC said FERC should consider encouraging firm transportation, multiple pipeline connections and dual-fuel capability for gas generators. “Further, the commission could consider requiring that resource adequacy assessments account for potential reliability ramifications associated with the ‘just-in-time’ natural gas fuel delivery model.”

“Fuel security risk is the most important factor to include in the commission’s definition of resilience and in its evaluation of grid resilience generally,” the American Coalition for Clean Coal Electricity said. The American Coal Council said coal generation retirements are a threat because intermittent resources can’t always be counted on.

Basin Electric Power Cooperative said its fossil generating units continue to be affected by markets “that fail to adequately compensate resources” for providing “essential electric service” in the wholesale markets.

The North Dakota co-op called for “equity across all fuel types,” saying the RTOs’ comments did not address the “preferential treatment” wind generation receives. It said a new ramp product, “if structured appropriately,” could reflect the value of stand-by products and provide “sufficient mitigation for assets that must stay online and incur losses” to backfill wind.

Americans for a Clean Energy Grid, a coalition supporting a “fully electrified” society, noted that this winter’s “bomb cyclone” forced Northeast grid operators to rely on more expensive generation such as coal, oil and dual-fuel units, even while wind output — stranded by transmission constraints — was higher than normal during the weather event. “Thus, while wind power can be more reliable than other resources during extreme winter weather, it is limited by interregional transmission constraints,” the group said.

PJM Comments Under Scrutiny

PJM’s March filing was the subject of numerous commenters, including David Patton, whose company Potomac Economics provides market monitoring services to MISO, ISO-NE, NYISO and ERCOT. Patton said adopting PJM’s proposal to allow inflexible generators to set clearing prices would have boosted MISO’s system marginal prices by 30%, based on analysis of the 12 months ending in October 2017. (See Critics Slam PJM’s NOPR Alternative as ‘Windfall’.)

“This plan is a fundamental departure from the efficient locational marginal pricing framework that has been the foundation of all successful wholesale markets in the U.S.,” Patton said. “It would, for the first time, introduce fixed costs into real-time pricing that are clearly not marginal in the real-time dispatch horizon. In effect, PJM would be requiring that the average costs of all resources needed to service load be reflected in every five-minute interval.”

The Pennsylvania PUC said it supported some of PJM’s proposals but feared that some “offered in the name of resilience may shortchange or even bypass normal PJM stakeholder deliberative processes” and warned against giving RTOs “a license to ‘gold-plate’ the generation, transmission and cyber assets of its members to achieve standards of resiliency that are disproportionate to a particular vulnerability or threat assessment.”

The regulators said they were concerned over the potential scope and costs of PJM’s proposals. “Some of PJM’s recommendations, especially in the market design arena, appear to utilize the grid resilience docket as another forum to advocate for specific market modifications, such as energy price formation, that are not immediately germane to the resilience discussion,” the PUC said.

It agreed with PJM that FERC may need to “revisit” NERC reliability standards. “However, revision of NERC standards is a complex, time-consuming process that should be allowed to proceed on its own timeline without an accelerated impetus from this docket.”

The PJM Power Providers Group (P3), on the other hand, praised the RTO’s “thoughtful recommendations” for addressing “antiquated energy price formation structures.”

“However, the stakeholder deliberations regarding this issue have been unproductive to date. Commission direction may be required for energy price formation goals to come to fruition as a means to support the commission’s resilience aims,” it said. P3 expressed concern over PJM’s proposal to permit non-market operations during emergencies, saying the commission should require the RTO to submit Tariff revisions to allow the change.

PJM also received support from American Electric Power, Dayton Power and Light and East Kentucky Power Cooperative, which made a joint filing as the PJM Utilities Coalition.

The coalition said it agrees with PJM’s recommendation that all RTOs be required to submit proposed Tariff changes to implement resilience planning criteria and develop processes for the identification of vulnerabilities.

“No meaningful steps towards a resilient system can begin without appropriate direction given by the commission that explicitly grants power to the RTO to establish resilience planning criteria and other aspects of the process,” it said. It also questioned whether the stakeholder process could address the issues. “If PJM reverts to a stakeholder process to determine resilience criteria, the process may get mired in political debates and cost allocation, and not focus on the necessary task of determining objective resilience criteria. For this reason, clear direction from FERC to guide that process is requested.”

PJM also filed reply comments, saying it wanted to provide additional information on its fuel security initiative announced April 30, clarify its proposals regarding gas-electric coordination and “provide context for its approach to this docket relative to the approach taken by certain other RTOs and ISOs.” (See PJM Seeks to Have Market Value Fuel Security.)

The Organization of PJM States Inc. (OPSI) said PJM’s filing did “not address the prudency and affordability of measures that may be implemented as a result of” the RTO’s recommendations, which it said indicate “extensions of its current mandate.”

“While not the stated intent, a future PJM could be positioned to drive transmission planning and craft new market structures in its mandate to address perceived low-probability, high-impact threats,” OPSI said. “The prospect of this expanded authority, with planning and decision-making impacting billions of dollars in investments with cost recovery from end users, may require a re-examination of PJM’s scope, governance and oversight.”

Industrial energy users, consumer advocates for Delaware, New Jersey and D.C., and American Municipal Power, filing jointly as PJM Consumer Representatives, said the inconsistencies between the positions of PJM and those of other RTOs indicate the need for regional flexibility.

“Unlike the comments of the other RTOs/ISOs, PJM’s comments embark on an aggressively activist course, advocating positions that could result in substantial changes to PJM energy and capacity market rules, in addition to whatever changes may be necessary in transmission planning and system operations rules,” they said.

They called for a cost-benefit analysis or “prudence assessment” of any new resilience rules and said neither the 2014 polar vortex nor the 2017-2018 cold snap “justify subsidizing uneconomic coal and nuclear units … in the name of resilience.”

ISO-NE

ISO-NE’s response to FERC’s identified fuel security as its resilience risk. It said potential responses include additional gas pipeline or LNG capacity, relaxing rules on dual-fuel resources and additional investments in renewables and transmission.

The New England Power Pool Participants Committee stressed that resilience solutions be worked out in the stakeholder process, calling it “a prerequisite to yield the solutions that work best for New England.”

The New England States Committee on Electricity shared ISO-NE’s perspective that fuel security presents the primary challenge to the resilience of the region’s power system. NESCOE recommended additional analysis of potential risks and cautioned “against prescriptive actions or further processes” that could impede regional or state efforts to mitigate fuel security challenges.

The New England Power Generators Association said ISO-NE’s Operational Fuel Security Analysis (OFSA) “neither captures market participant behavior in response to price signals nor the probability of any particular outcome … and therefore should not be the basis for the market solutions to be developed and later filed for acceptance with the commission.” (See Report: Fuel Security Key Risk for New England Grid.)

Eversource Energy said ISO-NE’s fuel security study “may understate the magnitude and scope of the challenges.”

“This could lead one to falsely conclude that only minor changes are required, and that commission action may be unneeded at this time. To the contrary, time is not on New England’s side,” the company said.

The company urged the commission to convene a New England-specific technical conference to determine state and federal actions to improve the region’s infrastructure, citing additional gas pipeline capacity from the Marcellus shale deposit and electric transmission to carry Canadian hydropower and on- and offshore wind.

The attorneys general of Massachusetts, Rhode Island and Vermont also cautioned against overreliance on the OFSA, which they said “relies on underlying assumptions that do not present a realistic or complete view of either the present or the future bulk power system.”

“The OFSA presents a deterministic (as opposed to probabilistic) analysis that provides no context about whether modelled events are likely to occur,” they said.

They also said the study’s approach to resilience is overly narrow, failing to consider “cyber and physical adversarial threats, technological accidents, and extreme heat and other weather events.”

The region’s local gas distribution companies recommended FERC “consider expedited review of and decisions on new natural gas pipeline certificate applications in critical fuel security regions.”

NYISO

NYISO told FERC in March that it does not face “imminent resilience concerns that require immediate action.”

The New York Public Service Commission said it agreed that ISO and stakeholder efforts to address bulk system resilience “are comprehensive and continuous,” asking for no other FERC measures beyond its “continued attention.” The PSC also agreed with the ISO’s suggestion for the commission to host a technical conference on bulk system resilience.

The Independent Power Producers of New York also supported the ISO’s approach and said FERC should not force it to abide by PJM’s suggested deadlines. “Efforts to ensure resilience should not be rushed to meet some arbitrarily short time frame unless they are justified by the evaluation of the ISO/RTO,” the group said.

The New York Transmission Owners also called on the commission to respect regional differences. “Any requirement to change course could impede resilience efforts already underway in the stakeholder process,” they said.

MISO

The MISO Transmission Owners emphasized that RTOs have only part of the answer to resilience, noting the role of distribution systems.

“MISO and its utility members have developed an integrated electric system that is currently sufficiently resilient, and MISO has identified no imminent resilience crises requiring commission action,” they said. “Notwithstanding MISO’s and its members’ regional efforts, enhancements to interregional coordination will promote greater resilience. Thus, while seams issues are broader than the concept of resilience, MISO is correct that the commission should not ignore the benefits of greater, more effective and efficient interregional cooperation in this proceeding.”

Entergy said it saw no need for a federal role in determining the proper long-term resource mix — “at least in MISO.”

The company called for resource adequacy to “continue to be a shared responsibility in MISO,” with state and local regulators determining the fuel mix.

“In this way, state and local regulators ensure diversity of fuel resources consistent with each area’s needs and those regulated utilities’ customers bear the cost burden and the reliability and resiliency benefits of those local regulators’ decisions,” Entergy said. “Direct federal action to regulate the long-term resource mix also could jeopardize utilities’ continued participation in MISO.”

In a joint filing, the Coalition of MISO Transmission Customers and Illinois Industrial Energy Consumers said that resilience is already central to the RTO’s reliability assessments. “The commission should not carve out resilience and treat it as a discrete characteristic of wholesale electricity markets,” they said, adding that any resilience requirements should be subject to cost-benefit analyses.

SPP

SPP’s Market Monitoring Unit emphasized the importance of creating standards and metrics to quantify and measure resilience.

“We recommend that in addition to defining resiliency, the commission and the parties should also engage in discussions to measure resiliency in order to assess whether an area has or has not attained resiliency. This measurement may also contribute in creating new market mechanisms to promote resiliency,” the Monitor said.

It pointed to SPP’s 30 to 36% capacity margins over peak needs but said that those high levels do not necessarily equate to resilience.

The MMU also said the resilience discussion should not be used “as a venue to promote certain price formation proposals.”

CAISO

The California Public Utilities Commission said the state “has made substantial efforts to ensure grid reliability and resiliency by ensuring redundancy and coordination in its energy planning efforts,” citing the deployment of distributed energy resources and smart inverters.

It also noted the state “continues to aggressively plan for a changing climate to ensure Californians have safe, affordable and reliable access to electricity.”

Nevada Hydro, which develops pump storage projects, said CAISO’s transmission planning process has fallen short in properly valuing hydropower. CAISO’s “transmission economic assessment method (TEAM) has not fully applied the method to storage projects and has not quantified the grid reliability and resiliency benefits of the projects it has examined,” the company said. It said FERC should direct RTOs to include pumped storage hydro in transmission studies and resource adequacy planning.

Southern California Edison said FERC should consider regional differences and costs. It said it shares CAISO’s view that FERC’s proposed definition of resilience is lacking.

It said the use of the term “‘disruptive events” is indistinguishable from “‘contingencies,’ which, per NERC reliability standards, refers to unexpected failures or outages of a [Bulk Electric System] component.”

Contributing to this article were Robert Mullin, Jason Fordney, Amanda Durish Cook, Tom Kleckner, Michael Kuser and Rich Heidorn Jr.

May 8, 2018March 25, 2025

PJM Operating Committee Briefs: May 1, 2018

VALLEY FORGE, Pa. — The PJM Operating Committee last week unanimously approved revisions to Manual 14D to tighten the notification rules for transferring the ownership of generation units.

Generation owners and PJM staff hammered out the language over the past month after owners expressed concerns over an earlier proposal. (See “Gen Transfer Vote Postponed,” PJM Operating Committee Briefs: April 3, 2018.)

Stakeholders consider revisions to PJM procedures at last week’s Operating Committee meeting. | © RTO Insider

PJM’s Rebecca Stadelmeyer presented the revised proposal, which sets deadlines on how long prior to the sale the buyer and seller must provide the RTO with certain information. Sellers must now simultaneously provide PJM with the application they submit to FERC to change ownership, which starts a clock on several other submissions.

At least five days before closing on the sale, sellers must provide PJM with information including the name and W9 form of the buyer, and a list of its current officers.

GT Power Group’s Dave Pratzon, who organized generation owners’ engagement on the issue, said the result addresses owners’ concerns about commercial realities and the need for flexibility that earlier drafts did not.

Synch Reserve Changes

PJM’s Eric Endress presented proposed Manual 11 revisions that would change how the RTO estimates the synchronized reserve maximums for Tier 1 units. The revisions would set a unit’s maximum at the lesser of the economic maximum or synchronized reserve maximum, though an owner could submit a request for a synchronized reserve maximum less than the economic maximum if a physical limitation exists. The economic maximum can be updated intra-hour as necessary.

PJM is targeting a July 1 implementation of the changes.

Carl Johnson, who represents the PJM Public Power Coalition, was one of several stakeholders who voiced concerns about “moving the earth under our feet” while several other larger issues related to the topic are being debated in other stakeholder forums — notably the Energy Price Formation Senior Task Force and PJM’s initiative to increase grid resilience.

He acknowledged that the proposal “makes sense” but cautioned that “we may be changing this entirely.”

Pratzon asked staff to analyze how the different initiatives overlap because they could “benefit from better coordination.”

PJM’s Chris Pilong acknowledged the concern but urged stakeholders to “make sure we don’t just sit on our hands” and not implement a solution to the issue. The RTO has been analyzing stakeholder concerns about significantly overestimated Tier 1 reserves. (See “Changing Tier 1 Reserve Estimates,” PJM Operating Committee Briefs: March 6, 2018.)

“In the interim, I think we still need to make sure that the reserves are accurate,” Pilong said.

PJM’s Eric Hsia confirmed that a “very limited amount of resources have a spin max greater than [its economic] max.” The RTO agreed to Johnson’s request to provide comparisons of units’ spin max versus economic max for all operating states, not just during synchronized reserve events.

Davis | © RTO Insider

Later in the meeting, PJM’s Becky Davis explained that the RTO uses the synch reserve ramp rates that units specify if they’re greater than specified energy ramp rates. However, generators aren’t required to provide either of those. If neither is specified, PJM uses the default ramp rate.

She noted an analysis of events over the past two years that showed 10% of units with synch reserve ramp rates greater than their energy ramp rates met or exceeded PJM’s Tier 1 estimate. The RTO contacted the other units to either remove the synch reserve ramp rates, match them with the energy ramp rates or justify why it should remain higher by submitting actual unit performance following a synch reserve event.

In response to a question from Pratzon, Davis said that most generators’ reserve rates match their energy rates.

Black Start Fuel Assurance

PJM’s David Schweizer presented proposed fuel-assurance requirements that will be required of black start units starting next year. The requirements would go into effect at the end of the year following the finalization of PJM’s current black start request for proposals and be in place for any incremental solicitations and the next RTO-wide RFP in 2023, he said.

Units would have to show one of the following:

Dual-fuel capability with onsite fuel storage for a 16-hour run-time at its rated black start output;
Onsite fuel storage for a 16-hour run-time at its rated black-start output for units that can store fuel, such as pumped hydro, batteries or oil;
Connection to multiple interstate gas pipelines with primary firm transportation contracts on at least two lines. This wouldn’t include local distribution company lines, which don’t offer firm service; and/or
That run-of-river hydro units can run at their black start rating for 16 hours.

Existing units would be entitled to a five-year transition plan starting in delivery year 2020/21. Units would be allowed to include the capital costs in the incremental black start capital cost component in their costs and would convert to the base formula rate after capital costs have been recovered.

Schweizer suggested that addressing previous concerns about the minimum tank suction level (MTSL) might be “more relevant” now. David Mabry, who represents the PJM Industrial Customer Coalition, agreed and requested a concrete proposal from PJM, but Calpine’s David “Scarp” Scarpignato argued against rehashing the issue. Prompted by the Independent Market Monitor, stakeholders spent several months earlier this year debating revisions to the MTSL calculation but eventually decided there were other issues of potentially greater significance to address. (See “MTSL ‘Not Going Away,’” PJM MRC/MC Briefs: Oct. 2, 2017.)

Pratzon asked if existing black start units that begin but don’t complete upgrades required by the new rules would have to voluntarily cancel the black start contract or if PJM would cancel it. He said his concern is if the difference will affect whether such units are able to recover their costs fully. Staff weren’t prepared to respond definitively; Pratzon asked that it be determined “sooner rather than later” so generators can make decisions about participating in the current RFP. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: April 3, 2018.)

Base Becomes CP

All capacity resources will be subject to Capacity Performance requirements at the beginning of the new delivery year on June 1. PJM’s Susan Kenney provided a preview on what changes regarding unit-specific parameters those resources will experience.

She noted that parameters will be updatable from May 25 through 10:30 a.m. on May 31 and that updates will transfer through to following days. Any parameters that don’t comply with new limits will be rejected by the system, she said.

Kenney also reviewed real-time value reporting procedures.

Fuel Security

PJM’s Dave Souder addressed the RTO’s initiative to analyze fuel security, which was announced April 30. (See PJM Seeks to Have Market Value Fuel Security.)

Souder said staff will analyze the grid under “stressed conditions” that include an extended cold spell, nuclear and coal retirements and the lack of availability of dual-fuel or onsite storage.

The plan has created concern on all sides of the industry.

Joe DeLosa, who represents the Delaware Public Service Commission, voiced “major concerns about the amount of time that’s going to be able to be devoted to this over the next year.”

“End-use customers especially have communicated to PJM their lack of a desire for criteria in the resilience field. I think that’s been pretty unanimous from customers, as well as substantial discussions about competing priorities in the stakeholder process,” he said.

“My mind’s racing,” FirstEnergy’s Jim Benchek said. “You’ve already got CETO/CETL [capacity emergency transfer objective/capacity emergency transfer limit] constraints. … It sounds like you’re planning to put an additional layer of constraints on the system.”

Later, PJM’s Brian Fitzpatrick explained the progress in staff’s analysis of gas-pipeline risks. The analysis is part of PJM’s ongoing effort to prepare for potential interruptions on the pipeline system. (See “Additional Reserves Needed?” PJM MRC/MC Briefs: March 22, 2018.)

Staff have held five meetings with pipelines within its footprint and have three more planned. While PJM had initially identified 63 contingencies that mostly involved potential compressor failures, pipeline companies said those were lower risk and recommended focusing on the ends of lines and laterals connected to main trunk lines.

“Right now, we have about seven [contingencies], so really, really decreased that list quite a bit,” Fitzpatrick said. “And that number will change because we’re still meeting with pipelines.”

Additional analysis will occur over the next six months.

PJM’s Augustine Caven said conditions during January’s “bomb cyclone” cold snap hit triggers to evaluate the need for any contingencies but that none were necessary. Caven also explained PJM’s plan to add detail to its operational parameters for gas units. The expanded parameters will help support automating PJM’s response to contingencies.

PJM is also planning to expand its ability to track units’ limitations on run time, including fuel inventory, emissions limitations, and supplies of demineralized and cooling water. PJM’s Natalie Tacka explained plans to add ways for units to report “hours remaining” for specified time windows and for RTO dispatchers to keep track of those potential restrictions. PJM is seeking generation owner input and asks those interested to let it know by May 11.

Automating Generator Notification

PJM’s Aaron Baizman explained a plan to automate the dispatch of resources onto the system. The current procedure involves calling the generator directly, but PJM plans to have that notification and verification process become electronic.

The transition will start with combustion turbines through a pilot planned to begin at the end of the year and ramp up in 2019. PJM plans to expand it to all units but has not yet set a target date.

Baizman said the plan is similar to programs at ISO-NE, CAISO, SPP and MISO.

CIR Questions

PJM wants to switch from using average to median capacity factors to calculate units’ unforced capacity. The RTO says the median is closer to units’ actual performance but acknowledges it will reduce units’ capacity injection rights (CIRs). (See “CIR Revisions,” PJM Operating Committee Briefs: April 3, 2018.)

The proposal has created concern among some stakeholders, and PJM’s plan to address the unease has only created additional concerns. PJM’s Jerry Bell outlined the current plan, which gives generation owners until Aug. 31, 2024, to notify the RTO that they plan to convert the CIRs that will be lost into incremental deliverability rights (IDRs) that they will use in an interconnection queue project within one year of the notice to PJM. The CIRs will convert to IDRs on Sept. 1, 2024. The plan is like the procedures already in place for reusing CIRs from retiring generators.

Initially, after stakeholders questioned the value of CIRs without a project, Bell suggested they could be sold at the point of interconnection, used to expand the existing project or allocated to a new project in the same area. However, he eventually conceded that “I don’t know what you’d do with them.”

Stakeholders also questioned why PJM would want to force generators to purchase less transmission capacity than they otherwise would. Bell said he’d have to come back later with an answer.

30-Minute Reserves Target Set

PJM has determined that it should secure roughly 3,800 MW of 30-minute reserves in real time, PJM’s Vince Stefanowicz said. The determination comes after analyzing how other RTOs/ISOs handle such longer-term reserves. Stefanowicz noted that ISO-NE, NYISO and the Tennessee Valley Authority all have a similar requirement.

Staff came to the number by considering several factors and making some assumptions. First, they assumed the largest unit would be about 1,500 MW and determined that the appropriate reserve should equal 200% of that. They added the load, wind and solar forecast errors for each season and came up with a value for each season. They averaged to 3,784 MW.

The number would be recalculated annually, and Stefanowicz said it’s often already online much of the time. PJM’s emergency management system calculates 30-minute reserves and found that, over the past four years, the system has been below 5,000 MW of reserves less than 10 hours total.

“We don’t expect this to come into play a lot,” he said. “In reality, the number we’re proposing is not overly aggressive. It’s realistic to what we’ve seen. … We have those reserves on the system normally, through our normal scheduling processes today.”

He noted that resources with a start time of less than 30 minutes could qualify.

PJM’s synchronized reserve requirement is 100% of the largest energy contingency and the primary reserve target is 150%, but the 30-minute “operating” reserve is currently undefined. Stefanowicz said the proposed calculation produces a number like the 30-minute reserve that PJM procures in day-ahead and is comparable to the calculations other RTOs/ISOs make.

“Each area has a different set of numbers, but a very similar methodology for securing their reserves,” he said.

Mabry asked why the target requirement wasn’t dynamic based on the largest unit online at the time. Stefanowicz said they would consider that.

— Rory D. Sweeney

May 8, 2018

PPL Looks to Raise $2B in Equity for 5-6% Annual Growth

PPL last week said it expects to need to raise only about $2 billion from equity sales through 2020, which would enable the company to come in near the top of its projected 5 to 6% compound annual earnings growth per share over that time.

During its first-quarter earnings call, the company also said it expect calls for nationalization of electric utilities in the U.K. to fade and that it isn’t interested in fully or partially divesting its business there.

PPL q1 2018 earnings equity sales — PPL CEO Bill Spence says his company is looking for organic growth. PPL expects to need raise $2 billion in equity sales through 2020. | *PP&L*

PPL earned $452 million ($0.65/share) on revenue of $2.13 billion in the first quarter, as opposed to $403 million ($0.59/share) on revenue of $1.95 billion in the first quarter of last year. Its adjusted earnings were 74 cents/share, beating the Zacks consensus estimate of 66 cents. The difference stemmed from a one-time impact of 9 cents/share from foreign currency hedges.

PPL expects to use its “at the market” offering program for most of its equity sales. CFO Vincent Sorgi said the company has a shelf offering that would allow it to sell up to $3 billion in stock.

The company isn’t looking to perform acquisitions, but rather to pursue organic growth, with midsized transmission projects such as Project Compass being the kind of opportunities it envisions after 2020, according to CEO Bill Spence.

Quotes courtesy of Seeking Alpha.

— Peter Key

May 8, 2018

Exelon to Push for Laws, Rules to Boost Profitability

By Peter Key

Exelon’s plans for its generation subsidiary rely heavily on a push for new legislation and market rule changes that ensure profitability for plants the company is threatening to close, officials said last week.

During a first-quarter earnings call last week, CEO Chris Crane said Exelon plans to push for subsidies for its nuclear plants in Pennsylvania similar to the zero-emission credit (ZEC) programs in Illinois and New York, and the one recently passed by the New Jersey Legislature but not yet signed by Gov. Phil Murphy.

Crane also said he expects Exelon’s generation business to benefit from PJM’s adoption of new price formation rules and FERC’s resilience initiatives.

Although Crane didn’t mention it, Exelon’s Pennsylvania nuclear plants could also earn subsidies from a New Jersey plan that takes into account how plants affect the state’s air quality, regardless of where they’re based. (See Izzo: Nukes Outside NJ Likely Eligible for State ZECs.) Efforts to enact nuclear subsidy programs in Pennsylvania have so far failed to gain much traction.

Crane also said Exelon will work with ISO-NE to develop market reforms allowing it to keep open the four units of its Mystic Generating Station in Charlestown, Mass., that it said it would close in June 2022.

Exelon Everett Marine Terminal Q1 2018 earnings — Exelon CEO Chris Crane says his company will work with ISO-NE on market reforms. Exelon has said it will close the Mystic Generation Station without market reforms.

The company is “going to look to get to the right reforms to make these assets more economic in the future,” Crane said. He noted that ISO-NE “put out a study recently saying that there were five assets in New England needed to ensure reliability into the future, one being the Everett Marine Terminal and the others being the Mystic [units].”

On the same day it said would close Mystic, Exelon announced it was buying the Everett Marine Terminal, an LNG import facility in Everett, Mass., which provides Mystic and other power plants in the area with fuel.

ISO-NE last week asked FERC for permission to waive certain Tariff requirements to allow the RTO to retain Mystic Units 8 and 9 to maintain fuel security, following up on a plan the RTO outlined in an April memo. (See ISO-NE Moves to Keep Exelon’s Mystic Running.)

Crane, along with Joe Dominguez, the company’s vice president of governmental and regulatory affairs and public policy, also addressed a PJM plan announced April 30 to help ensure fuel security. (See PJM Seeks to Have Market Value Fuel Security.)

Dominguez said Exelon would like to see PJM incorporate environmental impacts associated with different fuel mixes, pointing out that during the cold snap last winter, New England had to rely heavily on oil to produce power.

“In 2018, emissions need to be going down,” he said. “And any resolution of this issue that results in emissions going up is going to continue to create incentives for state actions and, indeed, for other federal actions to correct the flaws in those market.”

Crane said that while consumers have benefited from low-cost gas, the industry needs to either build redundancy into the gas delivery system or limit its dependency on gas to make the power production and delivery system more secure.

Exelon had net income of $585 million ($0.60/share) on revenue of $9.69 billion in the first quarter, down from $990 million ($1.06/share) and $8.75 billion in revenues a year earlier. The company’s operating earnings were 96 cents/share, beating the Zacks consensus estimate of 93 cents.

Crane said the company plans to target a 7.4% rate base growth for its utilities and 6 to 8% earnings per share growth through 2021.

Exelon is still on the prowl for acquisitions, if it can find smart ones, according to CFO Joseph Nigro.

“To the extent we can add something that we think will be accretive to the bottom line and fits with the value proposition that we’re trying to bring both to our shareholders and our customers, we’re going to be aggressive with doing that,” Nigro said.

Quotes courtesy of Seeking Alpha.

May 8, 2018

FERC Denies Bayonne NYISO Tariff Waiver Request

By Michael Kuser

FERC last week denied Bayonne Energy Center in New Jersey a waiver of several NYISO Tariff provisions, which the plant said it needed to enter the ISO’s monthly installed capacity (ICAP) auction in June.

NYISO clusters project developers that have achieved similar milestones into a “class year,” and evaluates the cumulative impacts of all of the projects in a given class year through an interconnection facilities study. The ISO recently adopted process changes authorizing it to bifurcate a class year in order to minimize delays for project developers unaffected by additional upgrade studies, allowing those developers an earlier “exit ramp” from the interconnection process.

Bayonne last month asked FERC permission to waive 11 provisions and add two new natural gas-fired units with approximately 120 MW of summer capacity to its existing 512 MW of capacity in time for the June ICAP auction.

The plant said that its 2017 class year study, originally scheduled for completion in December, was now slated to be completed in April. Bayonne would then be potentially subject to an additional 30-day delay while the ISO determined whether it needed to bifurcate the class year, jeopardizing the ability of the new capacity to participate in the June auction. Bayonne contended that it was not seeking waiver of any substantive requirements, but of the timing of certain requirements to allow for timely participation.

The commission’s May 4 order (ER18-1301) found that, in seeking waiver of 11 Tariff provisions, “Bayonne’s waiver request is not limited in scope,” and that granting the request could possibly harm third parties by delaying the ISO’s completion of the class year 2017 process for other projects. The commission also pointed out that “it is unclear whether Bayonne will even need waiver of these provisions given that it is not clear yet that whether class year 2017 will bifurcate.”

“We also note that Bayonne assumes, without support, that both NYISO and its Market Monitoring Unit can expedite their processes if the commission grants the waiver request,” the commission said. “In this way, it is unclear whether granting the waiver request would even provide Bayonne the relief it seeks.”

May 8, 2018

Profits Down, PG&E Fights Wildfire Liability

By Jason Fordney

While the wildfires that ravaged California last year have long burned out, the financial implications for Pacific Gas and Electric are just beginning to surge as the utility works to reduce the impact on shareholders.

PG&E last week reported first-quarter profits of $468 million ($0.91/share), compared with $544 million ($1.06/share) in 2017, falling short of expectations of Wall Street analysts. The utility reported $21 million in wildfire-related costs in the quarter under “items impacting comparability.”

Central to PG&E’s woes is the legal concept of “inverse condemnation,” which makes a utility potentially liable for wildfire-related property damage caused by utility equipment even in cases when that equipment has passed inspections and utility negligence isn’t proven.

During an earnings call and presentation Thursday, PG&E CEO Geisha Williams said the current treatment of the company’s wildfire responsibility is “a strict liability approach that presumes a commensurate cost recovery path for investor-owned utilities that just isn’t true.” She said that utilities cannot raise rates without regulatory approval, so applying inverse condemnation to utilities “undermines the premise” of the concept.

California’s courts have set a precedent of applying the state’s inverse condemnation provisions to IOUs, and a state trial court last week denied PG&E’s challenge of inverse condemnation related to the 2015 Butte Fire.

PG&E — Aerial view of fires in Napa and Sonoma Counties, October 2015

The state’s IOUs have banded together on the wildfire issue, pressing on legislative, regulatory and legal fronts to change the approach to inverse condemnation. Newly introduced legislation would revise wildfire liability provisions by allowing utilities to recover wildfire costs through rates if they conform to state-regulated safety plans. (See Calif. Legislation Shields Utilities from Wildfire Costs.)

Fitch Ratings downgraded PG&E’s stock in February because of wildfire risk. Utility liability for wildfires over the last 10 years has created worries among state lawmakers and the California Public Utilities Commission over the potential for IOU bankruptcies. (See Picker Seeks Guidance on IOUs, Aliso Canyon.) PG&E awaits other legal rulings regarding inverse condemnation associated with the 2017 fires, and the utility says climate change is playing a larger role in the conditions that led to the massive blazes.

The utility said that is has been working to harden its systems against wildfires, increasing its spending on vegetation management to $440 million in 2017 from $190 million in 2013, increasing inspections in high fire risk areas and acquiring two helicopters to assist in wildfire response, with plans to acquire two more. It plans to add 200 new weather-monitoring stations this year.

Williams also discussed the growth of community choice aggregators (CCAs), which has left remaining bundled customers to foot the costs for legacy contracts. The issue is becoming more prevalent as CCAs grow. She said the California energy landscape is in a period of “dynamic change,” mentioning climate change, CCA growth, increasing use of electric vehicles, and growth in carbon-free and renewable energy resources.

May 8, 2018

Infrastructure Spending ‘Biggest Driver’ of NiSource Earnings

By Amanda Durish Cook

NiSource is seeking rate hikes across multiple states to cover hefty infrastructure investments after the company delivered a 13% increase in earnings during the first quarter.

The Merrillville, Ind.-based utility last week reported first-quarter earnings of $259.7 million ($0.77/share), compared to $230.6 million ($0.71/share) over the same period in 2017.

“Our systems performed well throughout the prolonged winter heating season, and we’re on pace to deliver on our earnings, capital investment and customer commitments in 2018,” CEO Joseph Hamrock said during a May 2 call with investors and analysts.

NiSource filed several rate hike applications with different regulators during and after the quarter, hoping to recoup the approximately $1.8 billion it plans to spend on infrastructure this year.

“The biggest driver of our strong financial performance continues to be the impact of our long-term infrastructure modernization investments, supported by solid regulatory outcomes and established infrastructure trackers,” CFO Donald Brown said.

Hamrock said NiSource expects to continue to invest $1.6 billion to $1.8 billion in its utility infrastructure every year until 2020. The investments should boost operating earnings 5 to 7% per year, he said.

Subsidiary Northern Indiana Public Service Co. filed a settlement last month in its pending base rate case with the Indiana Utility Regulatory Commission. Brown said the request is NIPSCO’s first natural gas base rate increase in more than 25 years and will improve pipeline safety and reliability (44988). If approved, the settlement would result in an annual revenue increase of $107.3 million through fixed charges on customer bills. NiSource expects a commission decision in the second half of this year.

CIP ERCOT NiSource earnings — NIPSCO employees finish a substation project in March in Northern Indiana | *NiSource*

NIPSCO also filed a seven-year gas infrastructure modernization plan with the IURC in early April that proposes $1.25 billion of investments through 2025. The program would recover the costs of modernizing underground natural gas infrastructure through a customer bill charge (44403). NiSource similarly expects a ruling in the second half of 2018.

NiSource subsidiary Columbia Gas of Pennsylvania also has a $47 million per year rate increase request on file with the Pennsylvania Public Utility Commission as of mid-March.

Brown said the case would “provide the company with an opportunity to earn a fair return on its infrastructure capital investments and enhance pipeline safety.”

In late April, the Public Utilities Commission of Ohio approved a rate increase allowing NiSource-owned Columbia Gas of Ohio to begin recovery on about $207 million of infrastructure investments made in 2017. Columbia Gas of Massachusetts also filed a request with the Massachusetts Department of Public Utilities to increase revenues by about $24 million annually in an effort to recover costs incurred from regulatory mandates and gas distribution infrastructure upgrades. The DPU on April 30 also allowed the Massachusetts subsidiary to recover $84 million of capital investments in its rates. Finally, Columbia Gas of Maryland is seeking a $6 million per year rate hike with that state’s regulators as of April 13 for make pipeline upgrades.

Hamrock said corporate tax cuts at the beginning of the year helped to lower its rate hike requests in Indiana, Pennsylvania, Maryland and Massachusetts, as well as the rate request for its gas infrastructure replacement program in Ohio.

May 8, 2018

Eversource Looks to Offshore Wind, New Rates for Growth

By Michael Kuser

Eversource Energy said Wednesday that it will seek to support earnings growth through offshore wind contracts from its Bay State Wind partnership and a new rate plan in Connecticut that increases the average customer’s electricity bill by 3.8%.

The company reported first-quarter earnings of $269.5 million, compared with $259.5 million in the same period a year ago.

Eversource’s transmission unit earned $107.4 million in the quarter, up 11.4% from a year earlier because of additional investment in its electric transmission system.

The company’s electric distribution and generation business earned $104.2 million in the first quarter, down 6.5% from last year primarily because of the sale of generation assets, as well as higher depreciation, property tax, and operations and maintenance expenses, which were partially offset by higher electric distribution margins. Exceptional storm-related costs drove O&M expenses higher.

CFO Phil Lembo said in an analyst call May 3 that “we had significant storm activity in March this year, very significant, particularly in eastern Massachusetts, as a result of a series of nor’easters that hit us over an 11-day span.”

“The vast majority of the restoration costs, about $150 million, was deferred under regulatory mechanisms for future recovery,” Lembo said.

Regulatory Updates

Lembo noted the “good news” of a FERC administrative law judge’s March 27 ruling that municipal utilities and commission staff failed to prove that the New England Transmission Owners’ (NETOs) base return on equity of 10.57% (11.74% with incentives) is unjust and unreasonable. (See ALJ Rules New England Tx Owners’ ROEs not Unjust.)

FERC last October rejected a bid by NETOs, including Eversource, to increase their ROE to the levels in place before being reduced by a 2014 commission order that was vacated by an appellate court early last year. The commission said it would address the actual rate in a later remand order but has yet to do so (ER15-414, EL11-66).

Executives also discussed the New Hampshire Site Evaluation Committee’s (SEC) March 30 decision to formalize its rejection of Northern Pass, a joint venture between Eversource and Hydro-Quebec for a 1,090-MW transmission line to bring up to 9.4 TWh of Canadian hydropower to New England each year. Massachusetts had chosen Northern Pass, but in light of the rejection selected as an alternative a transmission project proposed by Avangrid subsidiary Central Maine Power. (See Mass. Picks Avangrid Project as Northern Pass Backup.)

Lee Olivier, Eversource executive vice president for business development, said the SEC has scheduled a May 24 meeting to hear Eversource’s request to reconsider the rejection. If rejected again, “the next step would be to appeal to the New Hampshire Supreme Court,” Olivier said.

Offshore Wind Hopes

Eversource partnered with Orsted to form Bay State Wind for a offshore wind solicitation in Massachusetts, and in December the company proposed a 400- or 800-MW wind farm 25 miles off New Bedford to be paired with a 55-MW battery storage facility.

Olivier said Massachusetts officials delayed by a month the date to select projects for negotiation, to May 23, 2018, now to be followed by submission of contracts to the Department of Public Utilities by July 31.

Connecticut is also conducting a request for proposals for offshore wind, and the company bid approximately 200 MW last month, Olivier said. A winning bidder is expected by midyear, he said.

Olivier said Bay State Wind can produce up to 2,500 MW of wind energy from its 300-square-mile lease area south of Martha’s Vineyard and interconnect it to surrounding states and Long Island, even extending over land to New York City with relatively minor upgrades to existing infrastructure.

“We’ll also have returns on these assets, transmission-like returns,” Olivier said. “Clearly once you get in, if you’re one of the first selected, you’ll have a first-mover advantage in every other solicitation.”

May 8, 2018

Stakeholders Urge MISO to Reconsider Seasonal Market

By Amanda Durish Cook

CARMEL, Ind. — The Reliability Subcommittee’s effort to explore how MISO should address increasingly uneven availability of resources could revive a discussion on developing a capacity market divided by season, stakeholders learned last week.

MISO kicked off its “resource availability and need” effort last month with a white paper on changing availability and an announcement that it would devise specific rules to counter the effects of increasing generation retirements, poor outage coordination, growing volumes of emergency-only capacity and the rising use of intermittent resources. (See MISO Looks to Address Changing Resource Availability.)

During a May 3 RSC meeting, MISO Executive Director of Market Operations Jeff Bladen said the new effort has prompted some stakeholders to ask the RTO to revisit its 2015 proposal to create seasonal capacity auctions, a move that was put on indefinite hold last year after stakeholder pushback.

At the time, seasonal capacity auctions seemed like “a single point solution to a broader set of issues that called for a more holistic approach,” Bladen said, noting that the new effort wasn’t intended to preclude a re-examination of the possible need for the auctions.

Near-term Solutions

Bladen also said several stakeholders urged MISO to focus on near-term solutions to ensure that an adequate amount of resources is at the ready, including improving outage coordination, modifying the rules of emergency-only resource types and creating forecasts that provide a better picture of resource availability in the footprint.

A utility’s cash flow influences the lumping of outages, Bladen said, with fleet operators grouping outages when they expect low energy prices, especially in spring and fall.

MISO Seasonal Capacity Resource Availabiliity — Bladen | © *RTO Insider*

“When prices are low, operators tend to take outages. It’s expected,” he said. “This is not as simple as, ‘well, everybody takes outages throughout the year.’ It’s much more complicated than that.” MISO said that most of its planned outages are scheduled less than a week before they are taken.

MISO might turn to a solution that requires more accountability from operators, Bladen said.

“Maybe there’s some expectation for generators to replace themselves [during an outage]? That’s pretty extreme,” Bladen said, stressing that MISO has not seriously discussed that measure.

Bladen said MISO could examine its existing load-modifying resource contracts to include staggering availability times and provide incentives to resources that offer during emergencies outside of summertime.

“Does it make sense to expect non-summer participation when it’s not compensated like in summer?” Bladen asked.

He pointed out that this summer, MISO faces an 80% chance of entering emergency conditions. (See MISO: Summer Reserves Adequate, but Emergency Likely.) He also said that a reduction in zonal resource credit offers has reduced the number of uncleared zonal resource credits in capacity auctions since the 2014/15 planning year.

“While we don’t think the platform is burning, the temperature is certainly rising,” Bladen said. “I want to be clear. The system is not unreliable. There’s just a better chance of emergencies.”

Storage Mentions

The Advanced Energy Management Alliance and other stakeholders called out MISO’s white paper for not explicitly mentioning the help energy storage could provide during tight operating.

Bladen said the omission was deliberate in order to remain technology- and resource-neutral.

“I would say that was intentional. We didn’t intend to reference technologies, but rather we were recognizing the resource availability profiles without going to where solutions could be found,” Bladen said.

Nevertheless, Bladen said MISO must consider the impacts that FERC’s Order 841 may have on its resource availability.

DTE Energy and the Organization of MISO States also asked the RTO to consider revising its loss-of-load expectation (LOLE) study process to include more availability risks associated with its resource mix.

Bladen said MISO envisions more stakeholder discussion before proposing changes to the LOLE study. He said altering study methods could produce a larger planning reserve margin requirement.

“It raises the prospect of socializing the risk by requiring everyone to procure more capacity,” Bladen said. “That’s a choice we can make as a community, but we have to be completely transparent about that choice.”

Consumers Energy’s Jeff Beattie cautioned MISO against risking some of its value proposition to its members by creating an insurance-sharing pool.

Bladen agreed that MISO needs to carefully consider balancing the sharing of resources in the footprint. “I’m glad you raised it because that’s something that needs to be front and center in the conversation,” he said.

He also said the RTO must also investigate shifting loss-of-load risk as part of resource availability. A recent renewable integration study by MISO found that as more intermittent renewable resources join the fleet, the loss-of-load risk becomes shorter but steeper, occurring later in the day after sundown. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)

Developing solutions to MISO’s resource availability issues could stretch well into 2019, Bladen said, and he expected that parts of the solution will be handled by the Market Subcommittee and Resource Adequacy Subcommittee as well as the RSC. He asked for more stakeholder opinion on what approaches the RTO should take.