MISO: New Outage Rules Boosted Mich. Capacity Prices

MISO confirmed last week that a new rule prohibiting resources on extended outages from offering capacity contributed to the historic spike in Lower Michigan prices in April’s Planning Resource Auction (PRA).

Zone 7 cleared at the cost of new entry (CONE) price of $257.53/MW-day for the 2020/21 planning year that began June 1, while all other zones cleared under $7/MW-day. Zone 7 fell 123 MW short of its nearly 22-GW local clearing requirement and had to turn to other zones for capacity procurement, activating the CONE price. (See Michigan Prices Soar in 8th MISO Capacity Auction.)

MISO Outage rules impacted Zone 7 in the PRA — MISO’s Zone 7 | *MISO*

MISO now restricts extended planned outages to a cumulative 90 days in the first 120 days of the planning year — June 1 to Sept. 30 — which it deems the most critical months for demand and loss-of-load risk. Resources that will be unavailable for more than 90 days are disqualified from PRA participation.

MISO Manager of Capacity Market Administration Eric Thoms told the Resource Adequacy Subcommittee on Wednesday that if the long-term outage policy had also been in effect for the 2019/20 PRA, Zone 7 would have fallen short of its local clearing requirement then as well.

Zone 7 also would have come up short by nearly 222 MW, Thoms said. Last year, Zone 7 had a 21.8-GW local clearing requirement and received slightly more than 22 GW from capacity offers and utilities’ fixed resource adequacy plans. However, about 474 MW of capacity wouldn’t have qualified for the auction based on planned outage schedules.

Under the new outage rule, MISO analysis showed a loss of load in Zone 7 occurring one day in six years in 2019. If the zone had not imported capacity this year to meet its local clearing requirement, the risk would have been one day in eight years. MISO adheres to a one-day-in-10-years standard.

MISO adopted the rule after the Independent Market Monitor last year criticized the RTO for allowing a large generator in Michigan to clear the PRA even though it was slated to be on outage the entire planning year. (See Emergencies Prompt MISO to Re-examine LMR Protocols.) Had MISO disqualified the generator from the auction, prices in Zone 7 might have hit $243.37/MW-day instead of the $24.30/MW-day clearing price in 2019, the Monitor said.

Coalition of Midwest Transmission Customers attorney Jim Dauphinais said MISO’s analysis shows the importance of the new rule.

June 14, 2020

MISO Seeks Extension on Midwest-South Tx Limit

Without a viable alternative on the horizon, MISO will likely extend its settlement agreement for flows on the Midwest-South subregional transmission constraint through early 2023.

“Until there’s a longer-term solution in place … the recommendation is to extend that settlement agreement until Jan. 31, 2023,” MISO Director of Seams Coordination Jeremiah Doner told stakeholders during a Market Subcommittee teleconference Thursday.

Doner said discussions with SPP and the other parties to the agreements on its future are in the early stages.

MISO Transmission Limit — Parties to the settlement agreement for MISO’s Midwest-South subregional transmission constraint | *MISO*

Starting Jan. 31, 2021, the settlement may be terminated by any party with a year’s notice. Without a replacement settlement, flows would be limited to MISO’s original 1,000-MW contract path in either direction. The settlement limits MISO to 3,000 MW of flows in the north-to-south direction and 2,500 MW of flows in the other.

Earlier this year, the parties signed a memorandum of understanding that they wouldn’t propose changes to the settlement until Feb. 1, 2022. Doner said an extension until 2023 will buy time for them to explore eventually changing the terms of the agreement.

Stakeholders asked if MISO would consider negotiating an increase in its transfer capability.

“I think it’s fair to say everything is on the table at this point,” Doner said, adding that MISO hasn’t ruled out a transmission project to increase transfer capability between its South and Midwest regions. After completing a special study, MISO last month said it wouldn’t recommend any upgrade to secure more transfer capability to its Board of Directors this year. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)

Doner said that while some aspects of the settlement discussions are confidential, MISO will share what it can with stakeholders in upcoming public meetings.

A two-year extension would keep in place MISO’s current cost allocation for transmission above 1,000-MW flows. MISO’s payments to the other parties for such flows are recovered from market participants through a combination of load ratio calculations and flow-based beneficiary allocations.

The load-based share declined every year since 2016 as the flow-based portion increased. From Feb. 1, 2016, to Jan. 31, 2017, the allocation was 45% load-based and 55% flow-based. From Feb. 1, 2020, to Jan. 31, 2021, the mix is 10% load-based and 90% flow-based. Doner said MISO would keep the current allocation under the extension.

Because of the declining importance of the load-based allocation, some stakeholders said MISO’s next logical step would be to use a 100% flow-based allocation through early 2023.

Doner took no position on the suggestion but noted MISO would have to win FERC approval for a Tariff revision to either change the cost allocation or pursue an extension of the current rate schedule.

“If all of the parties are good with the terms of the agreement, that settlement agreement can continue in perpetuity, essentially,” Donner said. He said the settlement also contemplates an extension of the original terms, with 2% annual cost escalations written in for use of the regional directional transfer.

However, if any changes to the settlement agreement are made before the Jan. 31, 2023, extension is up, it would trigger a requirement to also review the existing rate schedule.

Doner asked for written stakeholder comments on the extension by July 2.

June 14, 2020

MISO Drafts COVID-19 Waiver for LMRs

MISO last week said it will file a one-time waiver with FERC to make sure market participants can replace load-modifying resources (LMRs) impacted by the coronavirus pandemic.

Some LMRs that cleared in the Planning Resource Auction in April “may be unable to perform at their full accredited value as a result of COVID-19-related temporary — or, in some cases, permanent — closure of businesses that constitute their LMR assets,” MISO Manager of Capacity Market Administration Eric Thoms said during a Resource Adequacy Subcommittee teleconference Wednesday.

Thoms said market participants that manage a cleared LMR that is directly impacted by the pandemic must attest via email that the asset can no longer fulfill capacity obligations.

If FERC accepts MISO’s filing, those market participants will have the opportunity to use new LMRs with MISO to “bolster their portfolio,” Thoms said.

The waiver won’t allow members to change existing LMR registration records, Thoms said. Instead, market participants must make a replacement registration in MISO’s capacity tracking tool. That way, the RTO will have an “audit trail of replaced LMR resources and modified underlying assets,” Thoms said.

MISO plans to make the filing this month and will ask the commission for a July 1 effective date. From there, market participants will have 90 days through September to register replacement LMRs.

Usually, MISO market participants must register existing LMRs by Feb. 1, new LMRs for use in fixed resource adequacy plans by Feb. 15 and new LMRs not used in fixed resource adequacy plans by March 1 for the upcoming planning year.

“We’ll have an ability to reassess the effects of the pandemic after 90 days,” Thoms said, adding that MISO will have the “option to request a renewal of the waiver” if the pandemic is still affecting LMRs’ ability to respond.

But stakeholders argue that MISO isn’t considering the full gamut of difficulties wrought by the pandemic.

Xcel Energy’s Kari Hassler asked how the waiver could help a large LMR that permanently closes, taking with it both load and some measure to control it.

Thoms said MISO isn’t currently considering any reductions in planning reserve margins from load losses caused by the pandemic.

Multiple stakeholders argued that reserve margins should also be lowered because the load that needed to be curtailed no longer exists.

“I agree that there’s a mismatch here,” Customized Energy Solutions’ Ted Kuhn said.

Thoms said MISO does not yet know what LMR closures might be temporary or permanent.

“We have a financially binding construct that is already settled,” he explained. He also said impacted market participants are not obligated to use the waiver and can instead notify the RTO through the MISO Communications System that their LMRs are less available. LMRs are required to respond to at least five emergency events per year.

Alliant Energy’s Mitch Myhre said his utility has had difficulties even performing the MISO-required LMR testing, as some large commercial and industrial customers haven’t been operating as usual. Other stakeholders said they were experiencing similar testing difficulties.

This is MISO’s second filing for a waiver of Tariff requirements in response to the pandemic. FERC granted the RTO’s request for a 60-day extension of its June 25 site control demonstration deadline late last month as the pandemic slowed construction and shuttered government offices (ER20-1794). (See “Queue Waiver Request Before FERC,” Wary of Contagion, MISO Bars Visitors for 2020.)

June 14, 2020

PJM MRC/MC Preview: June 18, 2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committee meetings on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

Members will be asked to endorse the following manual changes:

B. Manual 14A: New Services Request Process, Manual 14E: Upgrade and Transmission Interconnection Requests and Manual 14G: Generation Interconnection Requests.

Periodic review, including clarifying and administrative changes.

Endorsements/Approvals (9:10-9:35)

1. Emerging Technologies Forum (9:10-9:20)

Members will be asked to endorse the charter of a new group to provide transparency for PJM’s Advanced Technology Pilot Program (ATPP), a testing ground to study the technologies to enhance system reliability, operational and market efficiency, and resilience. The group was changed to a forum after stakeholders expressed concerns about adding another subcommittee. It will provide reports to the MRC, as well as the Planning, Operating and Market Implementation committees. (See “Emerging Technologies Subcommittee Proposed,” PJM MRC Briefs: April 30, 2020.)

2. Stakeholder Group Sunsets (9:20-9:35)

Members will be asked to endorse the sunsetting of eight stakeholder groups, which PJM determined were either dormant or had implemented their original tasks. (See “Task Force Sunset,” PJM MRC Briefs: May 28, 2020.)

Members Committee

Consent Agenda (10:35-10:40)

B. Members will be asked to endorse Tariff revisions to allow surety bonds as a form of collateral. The proposal, originally endorsed in October 2018 at the MIC, allows the use of surety bonds for all market purposes except financial transmission rights, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer. (See “Surety Bond Proposal Endorsed,” PJM MRC Briefs: May 28, 2020.)

Endorsements/Approvals (10:40-11:35)

1. PMA Credit Requirements (10:40-10:50)

Members will be asked to endorse proposed Tariff revisions related to peak market activity credit requirements for federal, state and/or local law transfer of charges or credits. The revisions address a regulatory change in Ohio concerning the billing of network integration transmission service. (See “PMA Credit Requirements,” PJM MRC Briefs: May 28, 2020.)

2. Transparency and End-of-life Planning (10:50-11:35)

Joint stakeholders, including American Municipal Power, Old Dominion Electric Cooperative, LS Power and members of the PJM Industrial Customer Coalition, will ask for a vote on their transparency and end-of-life (EOL) planning proposal for revisions to the Tariff. The EOL proposal narrowly failed last month at the MRC meeting. (See PJM End-of-life Proposals Fail at MRC.)

June 14, 2020

WECC Seeks to ‘Invent’ Future with RA Forum

The Western Electricity Coordinating Council last week kicked off a resource adequacy initiative that revealed as much about how the organization hopes to position itself for the future as it does about its efforts to address a looming RA shortage.

WECC’s new Resource Adequacy Forum is the product of a half-day reliability workshop held in Seattle in February, where industry stakeholders from across the West engaged in a series of group exercises to help the NERC regional entity identify its near-term priorities.

During a “walk-around” exercise at the workshop, participants were encouraged to circulate throughout a conference room decorated with posters showing descriptions of NERC-identified risks. The largest contingent clustered around the “Resource Adequacy and Performance” poster when it came time to vote on what risks WECC should prioritize. (See WECC Should Keep it Regional, Stakeholders S ay.)

During a kick-off webinar that attracted nearly 170 participants Thursday, WECC staff emphasized the loose structure of the RA forum, saying it won’t report to any committee, establish a charter, keep meeting minutes or produce binding rules. WECC hopes to convene the forum in person twice a year, including this fall.

So why is WECC advancing the effort?

“The first ‘why’ really has to do with WECC’s identity as an organization,” said Vic Howell, the RE’s director of reliability risk management.

“WECC has been undergoing a very purposeful and deliberate transformation initiative that began a few years ago, where we’ve begun to ask ourselves some hard questions about our identity as a company,” Howell said.

After examining its “default future,” he said, WECC sought a different, “invented” future “characterized by a partnership where we put a strong focus on collaborating with stakeholders to strive for what we consider to be our common goal of having a reliable and secure interconnection.”

(In an email to ERO Insider, WECC Manager of Communications and Outreach Julie Booth defined the default future as “our future with no intervention or attempt to change the course of that future. WECC acknowledges that our future will happen, but we choose to shape what that future looks like.”)

“We really see this forum as a manifestation of that invented future, because we’re partnering with you folks to collaboratively address the reliability topic of resource adequacy,” Howell said. “That’s really the foundational reason why we’re creating this forum. Also, many of you know that recent studies have shown that resource adequacy is an emerging reliability risk in the interconnection.”

Turning to more concrete goals, Howell said WECC intends to “supplement” NERC’s annual Long-Term Reliability Assessment (LTRA) with its own RA assessment.

“We learned that there are several aspects of the NERC LTRA that really could use some improvement to better meet the needs of policymakers in the West,” Howell said. Rather than changing the NERC process, WECC would perform a separate RA study or set of studies that allow for more flexibility in assumptions and reporting assessment techniques, as well as inclusion of a wider range of scenarios, he said.

“This way we’re able to meet our obligations to NERC and adhere to their rules while at the same time producing a separate work product that’s more tailor-made for the West.”

Howell said WECC also aims to “partner” with its entities to support their RA work, which could include:

reviewing and comparing study assumptions;
assisting entities with their assumptions on their seams;
providing insight and education as entities develop RA programs; and
helping with model-building and interpretation of results.

WECC also hopes its forum will become a “hub” for RA discussions.

“When it comes to resource adequacy assessments, we have a good wide-area view,” Howell said. “In our reliability-focused studies, we’re looking at the entirety of the Western Interconnection, while others are looking at their specific areas. We believe that this broader view can supplement — not replace — the resource adequacy studies that are currently being done at the entity level.”

Howell touted WECC’s position of policy neutrality as being a “big deal.”

“We believe that positions us well for serving as a hub for adequacy discussions — that independence aspect of WECC that we bring,” he said.

‘Honest Broker’

WECC’s new vice president of strategic engagement and general counsel, Jordan White, picked up on the theme of the RE being an “honest broker” of information.

“As a regulator who was formerly charged with making resource planning decisions, I know that unbiased and transparent information and analysis are really key and essential in making sound decisions that impact long-term resource adequacy in the region,” said White, who joined WECC in May after serving on Utah’s Public Service Commission since 2015. “I know the same is true for policymakers, resource planners and utility executives who all rely on sound information to inform their respective resource adequacy roles.”

White said WECC wants to better understand the “world” of its stakeholders.

“What are the drivers and levers of your planning and decision-making? What are your modeling tools, planning cycles, data sources and assumptions? We want to know what keeps you up at night and how we can help. In turn, we hope you gain a better understanding of WECC’s methodologies, data sources and tools, and where there might be potential collaboration opportunities,” White said.

He also urged regional stakeholders “to break down unproductive information silos and to allow facts and analysis to drive sound decisions that promote reliability for the entire Western Interconnection.”

Looking ahead to brighter days post-pandemic, WECC Manager of Performance Analysis and Resource Adequacy Matt Elkins said, “What we want is a forum where we can all get together and discuss, for multiple days, and have different topics of discussion.

“We want this to be a place where people can come and present their processes. They can come and present the projects they’re working on … the results they’re finding. It’s just a place where subject matter experts can get together,” he said.

In response to a participant’s question, Elkins clarified that the forum is not intended to replace or duplicate the Northwest Power Pool’s nascent RA efforts to ensure sufficient capacity in eight Western U.S. states and two Canadian provinces. While WECC would welcome NWPP’s contributions to the forum, WECC’s RA models will remain at a “very high level,” focusing on balancing areas, he said. (NWPP’s effort will drill further down to the needs of the 18 entities currently funding the program.) (See Western Resource Adequacy Program in the Works.)

“It’s just for us to kind of pinpoint where risk is in the system,” Elkins said of WECC’s approach.

Another participant asked whether WECC has a desire to set a minimum reserve standard to ensure that no utilities are “leaning” on the capacity of others.

Elkins acknowledged stakeholder concerns that the region is “double-counting” its capabilities in some areas, with some market participants unknowingly relying on the same capacity.

But he said, “I don’t know that we need to have a standard.

“I think everyone’s doing a great job. I think we need to communicate more on what our model assumptions are and those kinds of things, and that’s really the point of this resource adequacy forum.”

Survey Says …

WECC wrapped up the webinar with an anonymous survey that elicited real-time participant responses to a handful of questions about the RA effort. The comments provided a flavor of stakeholder concerns — and wishes — regarding RA in the Western Interconnection.

One said WECC should set minimum RA standards for utilities in the region. Another called for the “need to connect the dots between policymaking and its effect on resource adequacy.” A third said regional coordination should “include different pathways to move to a Western RTO.”

One participant asked that WECC provide both in-person and virtual options for participants from companies that will not soon allow staff to travel because of COVID-19 concerns.

Another hinted at the paradox in WECC’s desire to help “invent” a future while maintaining its position of neutrality on the RA issue. “While the forum doesn’t have any defined ‘outputs,’ does WECC have the intention of anything more than information exchange? I think WECC might want to consider a related effort to host a technical RA inter-model comparison effort to understand different approaches to RA assessment and perhaps move toward a regional consensus.”

June 14, 2020February 12, 2025

Debate Continues as New England Awaits ESI Ruling

It’s been almost two months since ISO-NE presented FERC with its Energy Security Improvements proposal, a generator-backed plan nearly two years in the making that split stakeholders so much that the RTO agreed to also submit an alternative supported by load interests.

The time since the filing has done nothing to bring the two sides closer, it appears, based on a panel discussion webcast by the Northeast Energy and Commerce Association on Wednesday.

Tom Kaslow, vice president of market policy for generator FirstLight Power Resources, and Andy Weinstein, Vistra Energy’s director of ISO-NE market policy, joined Andrew Gillespie, ISO-NE’s senior market designer of market development, in defending the RTO’s proposal.

Jeffrey Bentz, director of analysis for the New England States Committee on Electricity (NESCOE), and David Cavanaugh, vice president of regulatory and market affairs for Energy New England, which serves 35 municipal utilities, made the case for NESCOE’s three amendments to reduce the plan’s cost to consumers.

Karen Iampen, vice president of trading and origination for Repsol, complained that neither of the plans work for the company’s Canaport LNG terminal in New Brunswick because they are focused on the day-ahead market.

ESI would allow the RTO to procure energy call options for three new day-ahead ancillary service products. ISO-NE detailed the plan in a 2,123-page filing April 15 in response to FERC’s July 2018 ruling that the RTO’s Tariff is not just and reasonable because it lacks a way to address fuel security concerns. The Tariff currently allows cost-of-service agreements only to respond to local transmission security issues (EL18-182, ER18-1509). (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

New England’s fuel security is a particular concern in winter, when prioritized heating demand can leave natural gas-fired generators without supplies. FERC’s order noted that reliability violations could occur as soon as 2022.

ESI is intended to incent generators to provide fast-start and fast-ramping operating reserves, replacement reserves for long-duration supply losses, and energy to fill the gap between the RTO’s day-ahead energy awards and real-time load forecasts. Option awards will be co-optimized with all energy supply offers and demand bids in the day-ahead market.

ISO-NE’s proposal received only 40% of a sector-weighted vote of the New England Power Pool Participants Committee in April, with support from Generation, Suppliers and Alternative Resources and unanimous opposition from the other sectors.

The PC approved amendments by NESCOE to limit replacement energy reserve (RER) purchases to the winter months, remove the RTO’s ability to adjust reserve levels to account for load forecast errors, and create a $10/MWh adder to the strike price. The amendments were endorsed by almost 62% of the PC, with unanimous support from the Transmission, Publicly Owned Entity and End User sectors and unanimous opposition from the Generation sector. ISO-NE submitted them to FERC along with the RTO’s proposal. (See ISO-NE Sending 2 Energy Security Plans to FERC.)

‘Using a Tank to Block a Mousehole’

Cavanaugh said the NESCOE amendments allow the region to comply with the FERC order while minimizing costs.

Bentz repeated a line from the protest NESCOE filed in response to ISO-NE’s filing. “We think the ISO is using a tank to block a mousehole,” he said.

“ESI is a novel approach for day-ahead reserves without any precedent elsewhere,” he said. “The potential impacts on energy security and cost to consumers are and remain uncertain, notwithstanding the impact analysis efforts of the A nalysis G roup and the ISO,” he said. “We’re just not sure this solves the fuel security problem.”

Bentz said the states would have preferred exploring a seasonal forward market with “a more conventional approach” to day-ahead ancillary services based on the best practices of other RTOs. “We think it could be potentially easier: more efficient at addressing fuel security and less risky than ESI,” he said.

State regulators are concerned that consumers will pay high prices if ESI fails to produce competitive outcomes, “which could happen potentially through physical withholding or inadequate incentives to participate,” Bentz said. The RTO has not yet “demonstrated [an] ability to mitigate market power effectively.

“We think it’s going to overcharge [through] incentives that fail to account for any diminishing marginal reliability value and are grossly disproportionate to fuel holding costs, according to the ISO’s own independent impact analysis study,” he added.

Bentz noted Analysis Group’s impact report showed 70 oil-burning combustion turbines would collect $7,385/MW in increased revenue for an investment of $134/MW. “We think that’s excessive,” he said.

Novelty Nothing New for New England

FirstLight’s Kaslow insisted FERC will ensure that the RTO has effective market mitigation procedures to protect consumers. And he said ISO-NE should not hesitate to try new solutions.

“NEPOOL and ISO have prided themselves on … being the first to do something, not because they wanted to be first, but because there was nothing better out there,” Kaslow said. “We’ve done that with our demand curve design. … We’ve done that with Pay-for-Performance,” which, he noted, PJM used as the basis of its Capacity Performance rules.

Kaslow also noted the RTO was “the first to have a capacity auction to sponsor policy resources,” a reference to the Competitive Auctions with Sponsored Policy Resources (CASPR). “So being first and being novel isn’t a new thing in New England.”

Bentz responded that ESI seeks to address the same problem “Pay-for-Performance was supposed to solve.”

Of CASPR, he said, “the states are sitting here with thousands and thousands of megawatts wanting to get into the market. And so far — I know it’s been only two auctions … we’ve only transacted a total of 54 MW. Next auction isn’t looking so good either. So, I’d say from the states’ perspectives, we’re looking at these novel designs and going, ‘OK, they sound good on paper. But do they actually work in reality?’”

Bentz said NESCOE and the Massachusetts attorney general had sought a three-year “lookback” to see if ESI is working as designed. Depending on their experience, Bentz said, the states could consider RER for summer months later. “Our pitch was, ‘start out slow,’” he said.

Unfair to Generators

Kaslow said it is generators that would be at risk if the commission agrees with NESCOE’s call to set RERs’ value to zero in the non-winter months.

“We’re troubled by the fact that NEPOOL proposes simply not to pay [for] replacement energy reserves in the non-winter months. Nothing in the NEPOOL filed amendments removes the ISO’s ability to schedule those reserves. As an owner of a resource relying on merchant revenues … that just doesn’t seem to be a fair outcome.

“When you have a market that’s relying on the marginal price of the reserves to set the price, that determines whether or not — and to what extent — we get paid. If there’s an element of that supply that the ISO ends up scheduling that isn’t accounted for in the demand that’s used to price it, the prices drop to zero.

“ISO will always maintain reliability. Unless they’re handcuffed or prevented from scheduling that reserve, they’re going to do it. And our concern is if they do that and it isn’t reflected in the market, it just suppresses the real-time prices — with the feedback loop [to] the day-ahead — and we just end up in a problem.”

LNG complaint

Repsol, a global “multi-energy company” that owns 75% of Canaport, thinks the RTO is seeking the wrong solution, Iampen said.

“In our opinion, the ESI filing … inappropriately replaced the fuel security with an energy security construct. So instead of the focus being on securing firm fuel or having secure fuel, it became about energy, which … wasn’t what the ISO was directed to submit Tariff revisions on.”

Iampen said securing LNG supplies requires firm forward contracting. “Compensation that is contingent on the generator’s option offer clearing on a day-ahead basis does not incent generators to procure the firm forward fuel supplies necessary to assure fuel security,” she said.

“We don’t contract forward for LNG speculatively. There is an awful lot of advance planning that is required. All LNG is not the same. You have to have a certain quality that shows up. You have to have a certain ship that can come alongside on your jetty. Not every ship can go into Everett, [Mass., where Exelon’s LNG terminal is located]. The bridge is too low for a good portion of the fleet that’s out there. Those logistics require more than a day-before cost certainty.”

ISO-NE’s Gillespie agreed with Iampen that the RTO’s goal with ESI is — as the title suggests — “energy” not “fuel” security.

“Fundamentally, the ISO really only cares about electrical energy. We really don’t want to be in the business of managing fuel for different power plants across the region,” he said. “So, our focus in this process [has been on] the outputs of these plants. These are the services that the system needs — the standby capability.”

Non-winter Incidents

Kaslow contended that NESCOE’s focus on winter is “designing by looking through the rear-view mirror.” Three losses of large baseload resources in the prior two weeks showed that energy security concerns are not limited to winter, he said.

On May 27, the region lost the Phase II transmission line with Quebec to a lightning strike while it was supplying almost 2,000 MW of power to New England.

Two days later, the region lost the Seabrook nuclear plant and Phase II again, then carrying more than 1,300 MW of imports.

On June 6, the RTO lost Seabrook again. In both cases, the plant shut down when control rods moved into the reactor when they weren’t supposed to.

“We need to be clear that we can’t predict the future, and ISO needs to keep the system operating every day. And the resources they need to rely on actually need to have compensation … to continue to provide that service,” Kaslow said.

ENE’s Cavanaugh countered that none of the recent events involved fuel issues. Nor did they result in reserve shortages, he said.

“Prices went to about $120[/MWh],” Bentz agreed. “The system handled it well.”

Cavanaugh said the probability of needing RER in the summer is “very low,” making the ISO-NE plan “a very huge insurance bill for covering something that we think is outside the scope of what the FERC asked.”

Gillespie said that although the RTO’s energy security vulnerabilities are currently most acute in winter, that will likely change as renewables increase their penetration.

“Right now, it’s mostly a concern in the wintertime, [but if] a lot of these resources that are providing these standby capabilities end up leaving that could spill out into months outside the winter,” he said. “If a pipeline is down for maintenance. If it’s a cloudy day. All these different things can occur. … It will be, I think, a broader problem than just the winter” because of system changes.

Starting Over?

Repsol’s protest of ISO-NE’s proposal asked FERC to order the RTO to make a compliance filing to address the “fuel security” concerns the company says were ignored in the ESI filing.

Iampen said Repsol is not asking FERC to reject the two proposals and is encouraged by the RTO’s commitment to develop a “longer-horizon seasonal fuel security framework.”

Kaslow observed that it took almost two years to develop a plan in response to the FERC order, “and then we still have another four years to implement” it.

“A delay, or going back to what I would call a blank page, I think is just impractical at this point,” he said.

“It’s critical that we give ESI time to work … rather than immediately looking for the next shiny object,” said

Weinstein, who joined Vistra a year ago after nine years at FERC, including a stint as former Commissioner Cheryl LaFleur’s legal adviser, said, “I think there should be concern about how FERC proceeds going forward. FERC could decide it’s obligated to find a solution on its own. It could be prescriptive.”

“I don’t know that we want to restart,” Bentz said. “But our original approach two years ago was, ‘Can’t we do a conventional approach that’s in place in other places?”

June 12, 2020

NERC RSTC Briefs: June 10, 2020

NERC’s Reliability and Security Technical Committee (RSTC) held its first full meeting via conference call on Thursday following the official dissolution of the Planning, Operating and Critical Infrastructure Protection Committees.

RSTC Transition Plan Updates

Although the RSTC officially assumed the functions of the earlier committees at its first meeting in March, the new body is still working to develop its own strategic plan for carrying on the work of its predecessors. (See RSTC Tackles Organization Is s ues in First Meeting.) According to a timeline shared at Wednesday’s meeting, this process is expected to be completed by the end of the year.

One of the biggest challenges facing the transition team is bringing on the various subcommittees and working groups it inherited from the retiring committees. While RSTC leadership confirmed at the last meeting that the short-term plan is for those groups to continue their existing projects and report to the RSTC in lieu of their previous committees, a more in-depth review is currently underway to develop a more effective project pipeline. Transition team members said that review is taking longer than expected but is still expected to be completed by August.

nerc rstc — Timeline for RSTC transition. | *NERC*

“Our main focus has been on defining what that future state organizational structure and operating model might look like for all of the different subgroups,” said Kayla Messamore of Evergy, a member of the transition team. “We’ve tried to think through the specific processes that are outlined in the RSTC charter and also the different activities that have been outlined in the RISC report and other forums as we align the different organizational structures.”

The team also acknowledged that the ongoing COVID-19 pandemic has complicated the transition due to the inability of subcommittee and working group members to meet face to face. The committee has already converted its next scheduled meeting from 1-4 p.m. Sept. 15 to a webinar, and may do the same for the following session — currently planned for Dec. 15-16 — based on the situation at that time. At that meeting, the transition team plans to present the completed operational plan to the full committee.

July Release Targeted for State of Reliability Report

NERC’s 2020 State of Reliability Report shows overall improvements in reliability across the North American electric grid, according to John Moura, NERC’s director of reliability assessment and performance analysis. The drafting team is currently targeting a release date in mid-to-late July.

“Last report I said it was the best year yet, and 2019 actually beats that,” Moura said. (See NERC Seeks Resilience M etrics, Focus on Resource Shifts.) “We definitely have a good trend.”

Specific figures for 2019 have not been released yet, but the positive developments cited by Moura include the following:

No category 3, 4 or 5 events (unintended loss of load or generation of 2,000 MW or more) compared to two category 3 events in 2018;
Declining rates and severity of generation and transmission outages; and
Stable or improving frequency response in most areas.

Moura said 2019 did see a “slight uptick” in the number of energy emergency alerts called, with the greatest increase in the Western interconnection, indicating that “we’re getting closer to the edge … operationally.” He also said that the changing resource mix, along with growing cyber and physical security threats, continues to present significant headwinds for the industry.

Committee Endorses MOD-025 Revisions

The committee voted to endorse a proposal by NERC’s Power Plant Modeling and Verificati o n Task Force (PPMVTF) to revise reliability standard MO D -025-2 (verification and data reporting of generator real and reactive power capability and synchronous condenser reactive power capability).

The shortcomings of MOD-025-2 were the subject of a white p aper released earlier this year by the task force after several years of work. Currently, the standard requires generator owners to verify their resources’ real and reactive power limits via stage tests and report the results to transmission planners every five years. However, the standard does not specify how the resulting information is to be applied, leading to widespread inaccuracies in planning models.

“This raw data is supplied to the transmission planners, who at this point don’t really know what to do with it,” said PPMVTF Chair Shawn Patterson. “They either have to trust that the generator owners have given them a good representation of their plant and this test doesn’t produce that, or in some cases … planners have been substituting these test points as the capacity limits … which would be incorrect.”

Patterson asked the committee both to endorse the white paper and to authorize the drafting of a standard authorization request (SAR) that would revise MOD-025-2 to specify what types of data may be used to represent generating resources in transmission planning models and how the data acquired in stage testing can be used. Both motions were approved unanimously.

IRPTF SARs Pass After Debate

The RSTC also voted to approve four SARs requested by the Inverter-b a sed Resource Performance Task Force (IRPTF) based on its Review of NER C Reliability Standards white paper, approved by the Planning and Operating Committees earlier this year.

IRPTF’s suggested SARS would apply to the following standards:

FAC-00 1 -3 (Facility interconnection requirements) and FAC-0 0 2-2 (Facility interconnection studies) — Clarify which entity is responsible for determining which facility changes count as material modification; clarify that generator owners should notify affected entities before making a material modification; revise the term “materially modifying” to avoid confusion between FAC standards and FERC’s interconnection process.
MOD-0 2 6-1 (Verification of models and data for generator excitation control system or plant volt/VAR control functions) and MOD-0 27-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions) — Revise or replace with a new model verification standard that accounts for inverter-based resources.
PRC-00 2 -2 (Disturbance monitoring and reporting requirements) — Require disturbance monitoring equipment in areas not covered by existing requirements.
VA R -002-4.1 (Generator operation for maintaining network voltage schedules) — Clarify the applicability of the requirement for reporting status changes in voltage controlling devices.

The SARs covering the MOD and VAR standards passed without debate from the committee, but those covering the FAC and PRC standards were challenged by Brian Evans-Mongeon of Utility Services Inc. While in both cases Evans-Mongeon agreed with the need to clarify the relevant standards, he objected to the use of the standard drafting process on the grounds that it would take a significant amount of time and that “not everything needs to be resolved by SAR.”

“NERC has had plenty of documents over the past that have provided for clarifying confusing terms,” Evans-Mongeon added. “It just seems to me that … by going forward with a SAR on this particular set of standards … we would be postponing a relatively resolvable action [of] the creation of either implementation guidance or [a] reliability [guideline].”

Evans-Mongeon moved to have the FAC and PRC changes remanded to IRPTF for further study and alternative proposals. Both motions were defeated, in the first case through lack of votes and in the second because the motion did not receive a second.

June 12, 2020

California PUC Approves Microgrids, Fire Plans

The California Public Utilities Commission adopted measures Thursday to prepare for this year’s fire season by accelerating the deployment of microgrids and approving the wildfire prevention plans of investor-owned utilities.

The commissioners also approved a controversial proposal to ensure the state’s community choice aggregators meet resource adequacy requirements through a central procurement mechanism. And they passed rules governing the way utilities shut off power to customers who cannot pay their bills.

The wildfire measures were a priority, with the state’s summer-and-fall fire season looming.

Pacific Gas and Electric’s decision to shut off power to vast swaths of its service territory last year to prevent wildfires spurred the microgrid measure, Commissioner Genevieve Shiroma said.

Legislation passed two years ago, Senate Bill 1339, directed the CPUC to “facilitate the commercialization of microgrids for distribution customers of large electrical corporations.” The commission established a new section in its energy division focused on microgrids and opened rulemaking on the matter in September 2019.

“Shortly thereafter, on Oct. 26, 2019, in the face of winds approaching almost 90 mph, we experienced PG&E turning off power to almost a million customers across 38 counties in an effort to minimize the risk of catastrophic wildfires,” Shiroma said. “From this experience, we learned that not only was PG&E’s execution of the public safety power shutoff protocols inadequate, but that the commission would have to use a multi-pronged approach to mitigate the effects of PSPS.

The CPUC retooled its rulemaking to focus on microgrids and resiliency ahead of the 2020 fire season, along with the long-term commercialization of microgrids under SB 1339. (See CPUC Proposal Would Promote Microgrids.)

california fire season — Commissioner Genevieve Shiroma | *CPUC*

Shiroma called the microgrid effort “a sprint and a marathon.”

The measure adopted Thursday orders investor-owned utilities to streamline and expedite interconnection processes for microgrid resiliency projects and to work with local and tribal governments to bring the projects online by late summer to keep electricity flowing during power shutoffs.

The state’s peak fire season typically lasts from early September into November, when rain returns after months of drought in California’s Mediterranean climate.

The plan calls for utilities to standardize application processes for microgrids, to expedite signoffs on installed projects and to increase staffing to accelerate interconnections.

The CPUC approved controversial plans by PG&E to deploy hundreds of diesel generators to power substations and key facilities but only for the 2020 fire season. Commissioners expressed dismay at the idea of using diesel fuel amid the state’s push for clean energy but said it was the only immediate solution to widescale power shutoffs.

PG&E praised the CPUC’s decision.

“As PG&E continues our enhanced and expanded efforts to reduce wildfire risks, we are also working to reduce the scope, duration and impact of future PSPS events,” Andrew Vesey, the utility’s CEO, said in the statement. “A key piece of this strategy is developing and deploying microgrids.”

Wildfire Mitigation Plans

The CPUC also criticized PG&E during a vote on the 2020 wildfire mitigation plans of the state’s IOUs — all of which were approved but some with provisos.

PG&E equipment started conflagrations in 2017 and 2018 that were among the state’s deadliest and most destructive blazes, forcing it to file for bankruptcy in January 2019.

PG&E met minimum requirements in its latest wildfire prevention plan, said Caroline Thomas Jacobs, director of the CPUC Wildfire Safety Division, established last year. The utility’s main causes of fire ignition were objects contacting its power lines and equipment failures.

PG&E plans to install covered conductors to enhance vegetation management to harden its grid to deal with the problems, but the company failed to provide specifics on how its measures would curtail risks, Thomas Jacobs said.

In her written assessment, Thomas Jacobs said, “PG&E outlines improvements being made to its risk assessment tools, but it is unclear how these tools are used to drive prioritization of specific wildfire mitigation initiatives to minimize wildfire risk and PSPS.”

The CPUC ordered PG&E to correct its deficiencies in the coming weeks.

Commissioners also praised the division’s newly developed wildfire risk measurement tools, including a “Maturity M odel” that “evaluates the utilities’ wildfire risk mitigation efforts across 10 categories and 52 specific capabilities and helps identify utility best practices and current strengths and weaknesses,” according to a CPUC press release.

“The Wildfire Safety Division’s approach has enhanced the state’s ability to conduct oversight of utility wildfire risk reduction by imposing clear requirements and expecting improvement each year,” the release said.

Central Procurement

The CPUC approved another controversial proposal that names PG&E and Southern California Edison as central buyers to procure local, multi-year resource adequacy for load-serving entities in their service territories.

The measure addressed the difficulty some community choice aggregators have had procuring sufficient resources to meet demand, with the state facing a potential capacity shortfall starting next year. (See Calif. Lawmakers Revea l Growing Divisions over CCAs.)

The CPUC rejected a settlement among entities, including the CCAs and CAISO, that would make CCAs primarily responsible for procurement with a “residual” central buyer to step in where needed. The CPUC instead adopted a hybrid approach that tasks the two big investor-owned utilities with ensuring reliability but allows CCAs to procure RA when possible.

CCAs remained opposed to the measure.

CalCCA, the main advocacy group for CCAs, said in a statement that it was “disappointed that the commission has adopted a central procurement framework for local resource adequacy that puts investor-owned utilities, rather than an independent entity, in the powerful role of central buyer.”

Shutoffs for Nonpayment

With COVID-19 wreaking financial havoc, the CPUC approved a major initiative to limit the circumstances in which utilities can cut off power to customers who can’t afford to pay their bills.

It ordered four major IOUs — PG&E, Southern California Edison, Southern California Gas and San Diego Gas & Electric — to implement policies and rule changes that protect customers from disconnections.

The changes include a program that forgives customer debt in return for future on-time payments and a cap on charges based on customer income. Individuals with medical conditions can qualify for increased assistance.

“Disconnecting utility services has significant societal and health impacts, and now more than ever we need to ensure the lights are staying on,” Commissioner Martha Guzman Aceves said in a statement after the vote.

June 12, 2020November 30, 2023

ERCOT Board of Directors Briefs: June 9, 2020

The COVID-19 pandemic and the associated economic crash has forced ERCOT to lower its financial forecasts for this year and into 2025, but the Texas grid operator said it is still in a “sound financial position.”

“We’re feeling comfortable with where we’re getting to in 2020 and 2021,” CEO Bill Magness told his Board of Directors during a June 9 videoconference.

ERCOT is facing a $29.3 million budgetary shortfall this year, primarily because of a $16.2 million drop in interest income that is part of a 10% unfavorable variance in net available revenues. Expenses are up $4.5 million as a result of “timing differences” related to a data center refresh and major software projects.

The ISO’s system administration fee collections are down $8.5 million through April, forcing staff to revise its expectations for the year. Based on revised weather forecasts and economic conditions, ERCOT now expects to bring in $218 million in administrative fees and interest income, down from original projections of $242.6 million.

“That’s similar to historical performance,” CFO Sean Taylor said as he detailed future expectations for the board. “There’s not yet a reason for large concerns.”

Taylor said ERCOT’s administrative fee of $0.55/MWh still seems “appropriate, given current projections.”

There were no questions from board members after Taylor’s presentation. Director Peter Cramton did urge Magness to continue moving forward with the data center refresh and “innovative” software solutions.

“I don’t want to slow down at all,” Cramton said.

Demand Down, but Record Peak Expected

Staff said it still expects a record demand peak this summer, albeit about 1.5 GW lower than earlier forecasts. ERCOT’s final seasonal resource adequacy assessment reduced its projected peak demand to 75.2 GW, still above last year’s record of 74.8 GW. (See ERCOT’s Summer Reserve Margin up to 12.6%.)

The grid operator will begin the summer with a 12.6% reserve margin. ERCOT survived last summer with an 8.6% reserve margin, calling two emergency alerts when wind resources unexpectedly dropped during the early afternoon amid above-average forced outages.

“We’re still in the range where we could call energy emergency alerts because of higher-than-expected demand, a larger number of forced outages or lower-than-expected wind, but we don’t expect any reliability concerns,” said Dan Woodfin, ERCOT’s senior director of system operations.

Woodfin said that while the ISO has seen lower demand in the early-morning hours while Texans sheltered at home, it hasn’t experienced much of a shift from normal peak demand. “That’s largely driven by air conditioning load,” he said.

Consumer demand, down 3 to 4% during the early weeks of the pandemic, is now down 1 to 2%.

Mark Ruane, ERCOT’s director of settlements, retail and credit, reminded the board that the market’s operating reserve demand curve will operate with a 0.25 standard deviation shift this summer, the second of two such shifts directed by the Texas Public Utility Commission in 2018. That will result in higher and more frequent price adders, he said.

ERCOT’s daily average August forward prices on the Intercontinental Exchange have dropped from almost $100/MWh in mid-March to just above $80/MWh by mid-May.

Michigan PSC’s Talberg Among Director Nominees

The directors unanimously approved a special meeting of ERCOT’s corporate members to consider three nominees for the ERCOT board, including Michigan Public Service Commission Chair Sally Talberg and retired ISO –NE General Counsel Ray Hepper.

Talberg and Hepper have been put forward by the board’s Nominating Committee to serve three-year terms as unaffiliated directors. The COVID-19 pandemic has hampered the committee’s ability to complete interviews for the third nominee.

Assuming their approval by corporate members followed by that of Texas’ Public Utility Commission, the nominees will replace Board Chair Craven Crowell, Vice Chair Judy Walsh and Karl Pfirrmann, whose terms all expire on Dec. 31. The meeting has been scheduled for Jul y 10.

The Nominating Committee also recommended unaffiliated director Terry Bulger receive a second term after his current term expires March 30, 2021.

Talberg was appointed to the Michigan commission in 2013 by former Governor Rick Snyder and became chair in 2016. Her term ends in July 2021, but Talberg said she would step down from the PSC should she be appointed to the ERCOT board. She has previously worked in an advisory capacity with Texas’ Public Utility Commission, served on the Organization of MISO States’ board (and as its president) and holds a master’s degree in Public Affairs from the University of Texas’ Lyndon B. Johnson School of Public Affairs.

Hepper retired from ISO-NE in 2018 and serves on the Board of Trustees for the Perkins School for the Blind in Watertown, Mass. He spent time with the U.S. Department of Justice during part of his career.

Walker Reminds MPs of PUC’s Role

PUC Chair DeAnn Walker again brought up her concerns that commission staff’s anonymous comments on an ERCOT change request are not being considered by some market participants, a repeat of her comments during a May 14 open meeting. (See “Commissioners Defend PUC Staff,” Texas Public Utility Commission Briefs: May 14, 2 020.)

Walker said she had since talked to one of the market participants involved and received further information on the May 13 Protocol Revision Subcommittee meeting, where stakeholders discussed a Nodal Protocol Revision Request (NPRR) seeking to clarify battery-storage technologies’ interconnection and operations.

She said a meeting summary she had read showed a market participant had asked for the names of the commission staff that provided comments on the change request. Walker added that the market participant indicated staff’s comments “hold little bearing” and that the NPRR would not be considered until they heard from the commissioners.

“I find it totally unacceptable that a market participant or multiple market participants believe they can demand action from this commission prior to the ERCOT market participants doing their duty as market participants,” she said. “I wanted to address this here so people are clear that ERCOT market participants don’t dictate to this commission what this commission does.”

Walker suggested ERCOT stakeholders read the Texas Pu b lic Utility Regulatory Act to correct their “basic misunderstanding” of the commission’s — and its staff’s — role in ERCOT proceedings and the PUC’s “exact authority over ERCOT in any market matters.” She said in reviewing the grid operator’s Protocols, she found language indicating commission staff may comment on revision requests.

“That’s exactly what this staff did, was comment on a revision request,” Walker said. “I could get into trouble if I keep going.”

“I couldn’t agree more with your comments,” Crowell said, noting he was unaware of what Walker planned to say. “I’m assuming your comments will serve to correct the situation going forward.”

Crowell opened the phone call to further comments, but there were none.

Parakkuth Approved as ERCOT’s New CIO

The board approved Jayapal “JP” Parakkuth as vice president and chief information officer, effective with his May 11 start date.

According to his LinkedIn pro f ile, Parakkuth, a power engineer, has more than 24 years of experience in “successfully visualizing, designing and implementing software solutions” for the grid. He has spent more than 20 years with Siemens, specializing in the digital grid and delivering major projects to P J M and C A ISO.

Parakkuth has a master’s degree in power systems and electronics from the Indian Institute of Technology in Bombay and an MBA in information systems and finance from the University of Minnesota. He replaces Jerry Dreyer, who left ERCOT on May 1.

Parakkuth “hit the ground running here,” Magness said.

Corpus Christi Tx Project Gets OK

The directors approved the Regional Planning Group’s (RPG) $219 million Corpus Christi North Shore Project, which addresses more than 1 GW of future industrial load growth expected by 2024 on the north shore of Corpus Christi Bay. (See “Corpus Christi Tx Project Gets OK,” ERCOT Technical Advisory Committee Brie f s: May 27, 2020.)

The RPG classified the project as a Tier 1 project because its price tag exceeds the $100 million threshold. Previously endorsed by the Technical Advisory Committee, the project is comprised of 36 miles of 345-kV lines, 8 miles of new and upgraded 138-kV lines, two new 345-kV substations and three 345/138-kV transformers.

An independent staff review found multiple NERC and ERCOT reliability planning criteria violations in the area. Staff identified several options that supported voltage needs but was unable to analyze the dynamic characteristics of the coming load. ERCOT and American Electric Power, the project’s owner, agreed to re-visit reactive compensation needs as short lead-time projects, once the load dynamic characteristics information becomes available.

Board Approves Bylaw Amendments, 13 Changes

During their July 10 special meeting, corporate members will consider bylaw amen d ments that widen the definition of “urgent matters” to allow virtual board and committee meetings by various electronic means. The board approved the amendments, along with other voting items, through a series of roll call votes.

ERCOT’s legal staff has approved the use of electronic votes by stakeholders during the national emergency, asking only that such meetings use communications equipment that allows attendees to hear each other. If necessary, votes can be validated after the meeting, staff said.

The directors also approved a consent agenda that included nine NPRRs, a change to the Nodal Operating Guide (NOGRR), another binding document revision request (OBDRR) and two system change requests (SCRs):

- - NPRR 9 3 3: Adds specific timing requirements for retail electric providers and non-opt-in entities to notify ERCOT of the demand response and price-response programs they offer to customers, the level of participation in those programs and the deployment events associated with those programs.
  - NPRR 9 7 5: Clarifies that load forecast models will be used to select the seven-day load forecast based on expected weather and requires ERCOT operations to explain its selection, improving transparency for market participants.
  - NPRR 9 87: Includes the contribution of energy storage resources (ESRs) to physical responsive capability and real-time online reserve capacity in the ancillary service imbalance calculation.
  - NPRR9 8 9: Establishes ESRs’ technical requirements for voltage support service (including reactive power capability) and primary frequency response.
  - NPRR 1 006: Returns ERS resources in a linear curve over a four-and-a-half-hour period following recall, instead of 10 hours, and changes the process for annually updating the parameter.
  - NPRR 1 0 18: Clarifies several provisions regarding the termination and suspension of a qualified scheduling entity (QSE) and the ability of a load-serving entity or resource entity to act as a “virtual” or “emergency” QSE.
  - NPRR 1 0 19: Addresses switchable generation resources (SWGRs) moving from a non-ERCOT control area to the ERCOT control area by creating a proxy energy offer curve with a price floor of $4,500/MWh for each RUC-committed SWGR and including a lost revenue cost component to the switchable generation cost guarantee.
  - NPRR 1 0 21: Shortens the default uplift invoice’s issuance timeline from 180 days to 90 days and allows ERCOT to use the best available settlement data when calculating each counterparty’s share of the default uplift.
  - NPRR 1 022 : Modifies how QSEs and congestion revenue right account holders (CRRAHs) submit banking information changes to ERCOT by removing the ability to submit the information with a Notice of Change of Information via email or fax. Creates a new form, Notice of Change of Banking Information, that a QSE/CRRAH must execute and submit through the market information system’s certified area.
  - N OG R R 204 : Together with NPRR989, codifies concepts described in the Battery Energy Storage Task Force key topics and concepts No. 4 (K T C 4) and establishes ESR technical requirements.
  - OBD RR 0 1 7: Aligns language within the operating reserve demand curve’s methodology for calculating the real-time reserve price adder with protocol revisions under NPRR987 and changes the real-time operating reserve calculation to consider an ESR’s state of charge when calculating the resource’s contribution to the online operating reserves.
  - SC R 8 0 7: Increases the CRRAHs’ total CRR transaction limit by 33% to 400,000 market transactions during CRR auctions.
  - SC R 8 0 9: Updates the validation rules imposed on ERCOT’s external telemetry and used in the resource limit calculator.

June 12, 2020

Exelon Challenges ISO-NE RFP in Bid to Extend Mystic

Seeking to extend Mystic Generating Station’s cost-of-service contract for an additional year, Exelon on Wednesday accused ISO-NE of violating its Tariff by shortcutting its transmission security review and prematurely culling bids received in response to its Boston competitive transmission solicitation.

In a complaint filed with FERC Wednesday, Exelon alleged that the RTO is putting the reliability of the Boston area at risk “by prematurely substituting the uncertain outcome” of its transmission request for proposals “for the certainty provided by Mystic” (EL20-52).

The filing came two days after ISO-NE surprised many by announcing it had narrowed 36 responses to its first competitive RFP under FERC Order 1000 to a single finalist, a $49 million project by incumbent utilities National Grid and Eversource Energy. (See National Grid, Eversource Finalist for Boston Tx Plan.)

The RFP was issued to address transmission violations expected after the shuttering of Exelon Mystic Units 8 and 9, whose retirement was extended to May 30, 2024, under a two-year, $400 million cost-of-service contract to preserve the region’s reliability. The project recommended by the RTO Monday has a projected in-service date of Oct. 1, 2023, eight months before the end of the contract.

Mystic Generating Station | *Anbaric Development Partners*

In its complaint, Exelon alleges that ISO-NE is violating its Tariff by prematurely rejecting the other bids and modifying its planning procedures to qualify the National Grid-Eversource project in time for Forward Capacity Auction 15 in February 2021, which will procure resources for capacity commitment period 2024/25.

“Twice in the last eight months, ISO-NE has sought permission from the commission to alter its Tariff to prevent the retention for reliability of … Mystic 8 and 9, and twice the commission has said that those efforts were premature,” Exelon said, referring to FERC rulings on Feb. 14 (ER20-645) and March 6 (ER20-89). (See FERC Rejects ISO-NE Fuel Security Tariff Revisions.) “Now ISO-NE has revised its planning procedures to do the same thing, but this time, without asking the commission.”

Exelon cited ISO-NE’s changes to Planning Procedure 10 (PP10) to modify the rules for determining whether planned transmission can be included in the network model for the studied capacity commitment period.

The new language said projects proposed in response to an RFP that “are reasonably likely to be in service prior to the relevant capacity commitment period … may be determined to be timely and sufficient to meet the reliability need.” It was approved by the New England Power Pool Participants Committee over Exelon’s opposition on June 4. (See “Order 1000 Questions on Tx Planning,” NEPOOL Participants Committee Briefs: June 4, 2020.)

Exelon said the change, which was not filed with FERC, violates the Tariff’s “strict rules” for determining whether planned transmission can be included in the network model. “Unless a transmission project has been certificated or executed a binding construction contract, and met important milestones, and been vetted and selected through an extensive process, the project cannot be included in the modelling,” Exelon said. It said the changes to PP10 will shorten the amount of time for project construction by as much as two years.

“We strongly disagree with Exelon’s complaint, and we look forward to addressing a number of inaccuracies contained therein,” ISO-NE spokesman Matt Kakley said Thursday. “Exelon requested to retire its Mystic plant, and we have worked diligently to accommodate their request while maintaining system reliability in the region. We are moving forward in solving the reliability issues caused by Mystic’s retirement in a timely and cost-effective manner.”

Expedited Ruling Sought

Exelon asked FERC to limit answers to its complaint to 14 days and issue an order by Aug. 4. “Expedition is crucial because ISO-NE will perform its transmission security review from June 11, 2020, through Aug. 18, 2020,” Exelon said. “Action by Aug. 4 will allow a reasonable amount of time (two weeks) for ISO-NE to correct its transmission security analysis by the Aug. 18 deadline.

“Whether ISO-NE follows the merchant approach or the incumbent approach, it is unlikely that the analysis will be completed, and a project selected and committed, before the FCA 15 auction is run in February of 2021,” it continued. “Put differently, because the transmission security analysis will be completed in August of 2020, ISO-NE will not have a vetted, approved and committed project in place in time to conduct that review. The revision to Planning Procedure No. 10, and likely the truncating of the RFP, are intended to circumvent this problem, but in taking these actions, ISO-NE runs afoul of the Federal Power Act, the ISO-NE Tariff and commission ‘rule of reason’ precedent.”

Exelon also claimed that ISO-NE “has unduly rushed” its RFP analysis, saying “its elimination of some projects based on project installed cost alone bypasses the detailed weighing of factors required for viable projects in Phase Two … and exceeds ISO-NE’s authority to cull the list of proposals in Phase One.”

The RTO sai d it cut the candidates down to one project on the basis of installed cost and the speed of completion.

“That is unwarranted,” said the complaint. “To be sure, the Phase One information that project sponsors are to submit includes cost information but only ‘estimated life-cycle and installed costs of the proposed solution, including a high-level itemization of the components of the cost estimate, a description of the financing being used and any cost containment or cost cap measures.’”

By contrast, Phase Two requires “detailed cost component itemization and life-cycle cost,” and permits “clarifications to cost containment or cost cap measures that were not included as part of the Phase One Proposal,” the complaint said in quoting the Tariff.

Long and Litigious

Exelon announced in 2018 that it would retire the 2,001-MW Mystic plant’s units 8 and 9, which began a long and litigious process of the RTO working to keep the plant running for “fuel security” reasons rather than for reliability, the only rationale then allowed under the Tariff.

Wednesday’s complaint is the latest move by Exelon to extend Mystic’s life after announcing in 2018 that it would retire the plant as uneconomical, citing its dependence on LNG, which is more expensive than natural gas from pipelines.

The “fuel security” cost-of-service agreement for Mystic Units 8 and 9 and the Exelon-owned LNG terminal that supplies them pays Exelon an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24, subject to true-ups for fuel costs.

In April, Exelon filed interconnection requests to keep the two combined cycle units running beyond 2024. asking the RTO to treat the units — with combined capacity of 1,600 MW in summer and 1,700 MW in winter — as “new” resources. (See Exelon Bid to Keep Mystic Units Running Provokes Outrage.)

Kakley emphasized Tuesday that the RTO has “not selected” the National Grid-Eversource project but is only proposing to advance it to further review under Phase 2. RTO staff will discuss their review of the proposals with stakeholders at the Planning Advisory Committee on June 17.