Can New England Conserve Like California?

New England state and grid officials are refining their plans to use conservation pleas in the case of an energy emergency, buoyed by the success of California’s call to action during this summer’s heatwave.

ISO-NE hasn’t had to employ a conservation request since 2013, when a July heatwave led it to ask energy consumers to raise their AC temperatures, turn off lights and appliances, and defer chores like laundry.

But increasing worries about winter resource adequacy in the case of extended cold weather has ISO-NE thinking about the next time it might have to ask New Englanders to voluntarily cut back, and what might be different this time.

At a regional tabletop exercise that the grid operator organized earlier this month, communication with the public about its ability to help was a central topic, said Matt Kakley, spokesperson for ISO-NE.

ISO-NE’s lead energy security analyst Mallory Waldrip speaks at a regional tabletop exercise. | ISO-NE

“A lot of what we talked about in the tabletop and in our standard emergency planning and discussions is how do we coordinate those messages? How do we make sure that everyone from the ISO to the utilities to the government folks is in the loop on things and understand what’s going on and what the ask is?” Kakley said.

ISO-NE would be the entity that would make the decision to call for energy conservation, based on its near- and medium-term forecasts.

But with its limited reach, the grid operator would rely on help from state governments and utilities (which already have customers’ email addresses and phone numbers) to get the message out.

“Close coordination with stakeholders such as our regional grid operator, emergency management officials and our fellow utilities among others is fundamental to any emergency response, and participation in regional trainings and exercises helps us to be ready in the event ISO-NE must take emergency action,” said William Hinkle, an Eversource spokesperson.

Learning from California’s Success?

Policymakers in New England see California’s recent experience as a strong example of the power of conservation.

The state’s urgent text to residents shortly before a period of impending record electricity demand, coordinated by the Governor’s Office of Emergency Services, was widely hailed as a successful, if drastic, step to stave off potential rolling blackouts. (See California Runs on Fumes but Avoids Blackouts.)

CAISO saw demand drop by 2,000 MW just 20 to 30 minutes after the text went out.

To ISO-NE, it was “comforting,” said Kakley.

“They were able to keep demand under the level they were able to serve, and not have to resort to the extreme measure of controlled power outages,” he said. “What that really drove home, what we’ve always known, but seeing it in a real-world example, was that if you ask the public to do something, and you’re clear in what you’re asking to do, they will respond.”

New England state officials have called for the region to employ that sort of call to action if needed.

June Tierney, commissioner of the Vermont Department of Public Service, made that point at the FERC forum in Burlington, Vermont, last month.

“Let’s not underestimate the people of the United States, she said. “Let’s not underestimate the people of New England. If they’re called upon, as millions of Californians were on their cell phones, to reduce demand immediately, they will respond.”

But ISO-NE has also acknowledged that the scenario presented in an energy emergency in the New England winter takes on a different shape: Rather than a capacity crisis lasting just a couple hours, it could be a fuel shortage that lasts as long as multiple days.

It’s a nightmare possibility that the region has been wrestling with for years, with increasing anxiety each winter, as the region continues to rely on volatile LNG markets.

“We spent a lot of time talking about how that call for conservation would be different,” Kakley said. “It’s a different kind of request and one that people haven’t spent a lot of time thinking about. We’re realizing that our messaging needs to be very clear.”

October 25, 2022

FERC: Rush Island Plant’s Extension Essential to MISO Reliability

FERC on Monday approved an agreement that will keep an Ameren Missouri coal plant online beyond its planned retirement date to maintain MISO grid reliability (ER22-2691).

In a separate order, the commission also said that Ameren might be overcharging customers to keep the plant operating and set the matter to hearing (ER22-2721).

MISO in August filed a 12-month system support resource (SSR) designation for the 1.2-GW Rush Island plant’s two units. The grid operator said that its analysis found “no alternative available at this time to avoid the need” for an SSR agreement and said that without the agreement, it could face severe voltage stability issues that might set off cascading outages.

MISO uses SSR agreements as a last-resort measure to sustain system reliability. It said it explored generation additions, dispatch changes, system reconfiguration, operation-guideline changes, amplifying demand response or load reductions, and adding new transmission projects, all to no avail.

The Illinois Municipal Electric Agency and the Wabash Valley Power Association lodged protests at the commission, alleging that MISO’s consideration of alternatives to the agreement was unsatisfactory. The commission said the grid operator properly arrived at a “determination that no feasible alternative exists at this time that could be implemented to allow suspension of the Rush Island Units by the requested September 1, 2022, suspension date.”

FERC found that both Rush Island units are necessary despite the stakeholders’ claims that one unit will suffice. The commission said MISO’s retirement study showed transient voltage recovery issues that would violate both NERC standards and Ameren’s local planning criteria and “pose a risk to the St. Louis metro area and Peoria, Ill.” It concluded the RTO presented “sufficient support” for the SSR agreement through next summer.

However, FERC agreed with Wabash Valley and Illinois Municipal that Ameren’s proposed $9.3 million monthly SSR payment could be too steep and ordered a hearing with possible refunds. The commission also rejected Ameren’s inclusion of a 50-basis point return-on-equity adder in the monthly payment calculation, saying the ROE adder for RTO membership is reserved for transmission owners, not generation facilities.

In the interim, MISO will assign proposed SSR costs associated with the Rush Island units to load-serving entities that require their continued operation.

Ameren last year fast-tracked the plant’s closure rather than install a court-ordered wet flue gas desulfurization system by March 31, 2024, to correct Clean Air Act violations. The utility originally intended to operate Rush Island until 2039, but the 2019 ruling from the U.S. District Court for the Eastern District of Missouri cut its plans short (19-3220).

Rush Island’s units date back to 1976 and 1977. Together, they currently emit approximately 18,000 tons of sulfur dioxide annually.

MISO recommended in this year’s transmission planning cycle $120 million of new static synchronous compensators to reinforce the system with Rush Island’s retirement. Those transmission solutions aren’t expected to be in-service until mid-2025, making it likely that the grid operator will renew the SSR, which it can do on an annual basis. However, the RTO has committed to a yearly re-examination of alternatives to the SSR. (See MISO’s 2022 Tx Planning Cycle Exceeds $4B.)

October 24, 2022March 6, 2024

Full Requirements Customers Win Right to Use Own Storage

FERC last week ruled that three municipal power providers would not violate their full requirements power contracts by installing battery storage, which the commission determined does not count as the sort of generation they are obligated to purchase exclusively from Appalachian Power Company (APCO).

Under their agreements with APCO, Craig-Botecourt Electric Cooperative and the Virginia cities of Radford and Salem are obligated to purchase their power exclusively from the utility, aside from some pre-existing generation in the two cities.

The three entities rely on the services of Blue Ridge Power Agency, a non-profit formed to negotiate wholesale electric power purchase contracts and monitor their performance for its members. Blue Ridge filed an instant petition with FERC on Aug. 10, 2021, asking that the commission rule that use of storage is permissible within the terms of the contracts because it is not a form of generation and is not prohibited under the agreements (EL21-97).

APCO argued that, because the contracts do not allow for the installation of behind-the-meter generation for the purpose of peak shaving, they should be read with the understanding that other methods of reducing peak load, such as demand response programs, are not permissible.

APCO estimated that $8.5 million in expenses would be shifted to its other customers should the petitioners be allowed to install batteries and use them for peak shaving, largely the result of costs associated with building the transmission the utility was required to meet peak demand, but which it could not recoup through demand charges based on the highest hourly usage in a billing month.

Blue Ridge argued that, since the contracts with APCO address the potential for variation in their energy use and both cities have already participated in PJM’s demand response program, the methods of shifting their load are permissible under the contract, as long as the energy is ultimately procured from APCO.

Blue Ridge additionally contended that the contracts do not preclude its members from reducing demand, “but rather only preclude meeting that demand from sources other than APCO, and that the Blue Ridge Members accordingly retain ‘the right to use storage, demand response, load management, or other peak-shaving technologies or programs,’” the order noted.

FERC agreed with Blue Ridge with respect to the contracts with the cooperative and two cities.

“While these three agreements do not expressly mention battery storage investments, when read in context and in their entirety, these agreements support Blue Ridge’s position that such investments are permitted under the agreements,” the commission wrote.

“The agreements focus exclusively on generation, and the exclusive nature of both APCO’s status as sole provider, and each customer’s obligation to purchase generation during the delivery period from APCO alone,” the commission continued. “The contracts define full requirements electric service as ‘the supply of firm energy to be provided by [APCO] to the customer at the delivery points, as the same may fluctuate in real time to serve customer’s retail load . . .’”

However, FERC ruled that a fourth party to the petition, Virginia Polytechnic Institute and State University, would be in violation of its full requirements agreement with APCO should it install batteries which, together with generation, would amount to more than 2.35 MW — the highest amount of behind-the-meter generation the university’s full requirements agreement allows for.

Unlike the other three contracts, the university’s agreement with APCO specifies that storage is to be considered a form of generation, a categorization the majority of the commissioners disagreed with but determined does subject batteries to the same contractual limitations as traditional generation.

Commissioners Danly, Christie Dissent

Commissioners James Danly and Mark Christie dissented from the ruling on the grounds that they did not believe that FERC should exercise its jurisdiction in a matter they believed was a contractual dispute that could have been resolved by the Virginia courts, an argument APCO made in its filings as well.

“The fact that the subject of the contract dispute happens to be battery storage units instead of bucket trucks or office equipment is no reason for us to assert jurisdiction and impose a preferred result,” Christie wrote.

The issue of jurisdiction largely centered on interpretation of three factors laid out in the Arkansas Louisiana Gas Co. v. Hall case, in which FERC declined to take jurisdiction in 1979. The majority in the Blue Ridge order determined that the commission met each requirement: possession of special expertise that makes the case peculiarly appropriate for commission decision; a need for uniformity of interpretation; and a case that is important in relation to the regulatory responsibilities of the Commission.

Danly also argued that each of the contracts should be read in the context of the Virginia Tech agreement, which was agreed upon in 2019, two years after the other three, since it was drafted prior to subsequent FERC rulings on the distinctions between generation and storage. The order, he said, could create a pathway for future petitions to seek to introduce new provisions to their contracts through the commission.

“The import of this order is that if your full requirements contract is silent as to this or that matter or if it fails to expressly prohibit a particular thing, then any such practice, might it later be at issue, can now be permitted by the commission, when it wants. This is absurd; this is not how contracts work. This decision will inevitably lead to confusion and disruption of other full requirements contracts and will encourage a slew of future petitions for declaratory orders seeking to reform extant contracts by inserting unnegotiated, uncontemplated, and unanticipated elements,” he said. “Contracting parties beware.”

October 24, 2022

FERC Clarifies CAISO, NYISO Order 2222 Rulings

FERC on Thursday declined to rehear a case on NYISO’s Order 2222 compliance filing but clarified its comments from a June order on aggregated distributed energy resources providing ancillary services in the ISO (ER21-2460).

The commission reached a similar conclusion in CAISO’s Order 2222 compliance in an order also approved Thursday, during its monthly open meeting (ER21-2455). It denied a rehearing request by environmental and consumer groups but responded to a request by California utilities to clarify that its June order did not “modify or reverse commission precedent that wholesale sales by net metering customers are subject to commission jurisdiction.”

CAISO and NYISO were among the first to submit compliance filings last year under Order 2222, which FERC approved in September 2020 to remove barriers to the participation of DER aggregations in the capacity, energy and ancillary service markets of RTOs and ISOs.

In the NYISO case, FERC partially accepted NYISO’s Order 2222 compliance filing on June 16 but directed the ISO to file revisions related to small utility opt-in requirements, interconnection rules and other issues. (See FERC Partially Accepts NYISO Order 2222 Compliance.)

NYISO responded on July 18 with a request that FERC clarify the discussion in its June order on aggregated DERs providing ancillary services or grant it a rehearing. The ISO had proposed in its compliance filing that aggregations could provide certain ancillary services only if all of the individual DERs in the aggregation were able to provide the same ancillary service.

In its June 17 order, FERC said that “so long as some of the DERs in the aggregation can satisfy the relevant requirements to provide certain ancillary services (e.g., the one-hour sustainability requirement), we find that those DERs should be able to provide those ancillary services through aggregation, in accordance with the goal of Order No. 2222 to allow distributed energy resources to provide all services that they are technically capable of providing through aggregation.” Being “‘technically capable’ of providing a service means meeting all of the technical, operational and/or performance requirements that are necessary to reliably provide that service.”

NYISO said its system software allows aggregated DERs to provide only one ancillary service at a time, such as operating reserves, and asked FERC if it intended otherwise.

FERC said the ISO’s software limitations meant the resources were technically incapable of providing certain services and that its June 17 order did not “require NYISO to allow a heterogeneous aggregation to simultaneously make available multiple operating reserve products.”

The commission denied rehearing requests by clean energy and consumer advocates, including the Natural Resources Defense Council and Advanced Energy Economy, which argued that NYISO’s definition of a DER was not technology-neutral, as required by Order 2222, and could prohibit energy efficiency and other passive-demand resources from participating in its capacity market even though they are technically capable of doing so.

FERC disagreed with that argument, as it had in its June decision.

“NYISO’s proposal includes a technology-neutral definition for DER and therefore does not prohibit any type of technology from participating in an aggregation,” it said.

Commissioner Allison Clements dissented in part “because [the decision] affirms the majority’s prior finding that [NYISO] may exclude energy efficiency from participating in distributed energy resource aggregations without running afoul of the requirements of Order No. 2222.”

“I disagree with that decision and therefore would have granted the request for rehearing on this issue submitted by [the] clean energy and consumer advocates and found that NYISO’s definition of DER does not comply with Order No. 2222,” Clements wrote.

CAISO Clarification

In June, FERC asked CAISO to file a further Order 2222 compliance filing addressing concerns about its model for aggregated distributed energy resources, rules for participation of DERs that are customers of small utilities and other matters. (See CAISO Order 2222 Filing Needs Some Work, FERC Says.)

On July 15, Southern California Edison, Pacific Gas and Electric, and San Diego Gas & Electric submitted a request to FERC for clarification of the compliance order, which the commission granted.

The “California utilities seek clarification that the compliance order does not modify or reverse commission precedent that wholesale sales by net metering customers are subject to commission jurisdiction,” FERC said. “They argue that clarification is needed because a wholesale sale is a sale for resale in interstate commerce subject to commission jurisdiction, whether the seller is behind or in front of a retail meter. …

“They contend that, if commission policy is modified or overturned, then wholesale sales may no longer be subject to commission jurisdiction.”

In its order, FERC said that “as [the] California utilities request, we clarify that … the compliance order does not reverse or otherwise modify commission precedent.”

FERC also denied AEE’s request for rehearing of the CAISO compliance order. AEE argued that “the barriers created by the 24-hour settlement requirement run afoul of the provisions of Order No. 2222 requiring each RTO/ISO ‘to allow distributed energy resource aggregators to register distributed energy resource aggregations under one or more participation models in the RTO’s/ISO’s tariff that accommodate the physical and operational characteristics of the distributed energy resource aggregation,’” according to FERC.

The commission said it had already addressed AEE’s argument in its prior rulings, and “we remain unpersuaded by its claims on rehearing.”

October 24, 2022

A Massachusetts Climate Group Takes its Message to NEPOOL

Another climate organization in New England has joined NEPOOL membership as it looks to add a regional lens to its work.

The Massachusetts Climate Action Network (MCAN) on Oct. 1 became the newest member of the end user category of stakeholders in the ISO-NE stakeholder organization. It joined a small group of climate and environmental advocates who have been trying to make a dent in a process they say sometimes seems tilted against them.

MCAN’s focus is largely local; its model is to support municipal chapters that often focus on specific projects within their footprint.

But the group’s advocacy against the Peabody peaker, a contentious gas and diesel plant under construction north of Boston, has led it down a rabbit hole of regional debate that its leaders felt they could not ignore.

“We’re really focused on supporting residents and taking local action,” Logan Malik, the group’s interim executive director, said in an interview. “But in order to do that, sometimes you need changes to take place at the statewide or regional level.”

Starting with the debate around ISO-NE’s minimum offer price rule (MOPR), and more recently discussions around capacity accreditation, MCAN has been paying more attention to the regional dynamics that help shape the projects they’re focused on.

“We saw this as an opportunity to engage with the various stakeholders across the region who are working on these issues day in, day out,” Malik said.

He added that one of the organization’s goals of participating is to make the information coming out of ISO-NE and NEPOOL more accessible.

“I think there’s still definitely a challenge in translating these very complex discussions into things that people understand and people can engage in,” Malik said. “Residents care about this stuff. Residents care about these decisions. And it’s very hard for residents not working fulltime in an organization like MCAN to actually understand the material that’s coming out.”

Taking on ‘Entrenched’ Fossil Interests

MCAN won’t be without friends as it starts navigating its way through what can be a confusing and intimidating stakeholder process. There are a handful of other environmental groups, like the Acadia Center, Conservation Law Foundation and Natural Resources Defense Council, that have increasingly seen NEPOOL as an important venue for their advocacy and a necessary part of their work. Malik cited all of those groups and others as allies that have helped the organization get up to speed on the regional level.

The NEPOOL stakeholder process MCAN is joining hasn’t historically been an easy place for environmental groups to gain a foothold. It’s a big time commitment, with complex meetings that take place during the week for as long as multiple days at a time. Some groups, like NRDC, have elected to hire consultants to help stay on top of the process and present their ideas.

“It’s a question of resources. The technical committees meet regularly, and the meetings can be lengthy,” said Phelps Turner, a senior attorney for CLF.

There’s also an incumbency effect that gives many of the longer-standing members advantages.

“I think that the way that the system is set up, in the way that the voting structure and [NEPOOL] operation works … there is a certain bias towards incumbency and the existing system. Trying to move in a new direction isn’t always easy,” said Bruce Ho, a deputy director at NRDC who represents the organization within NEPOOL.

Ho’s experience with the MOPR debate and other changes that he argues are needed to enable the clean energy transition and decarbonization has featured lots of pushback, he said.

“I think there’s a lot of entrenched value, a lot of entrenched economic investments and interests in the current fossil system.”

There are just six environmental organizations out of more than 500 NEPOOL members, although they also often align on issues with renewable developers and suppliers, or state officials and consumer advocates.

“I think those voices can serve as an important counterbalance in the stakeholder process, to stakeholders from the fossil fuel industry, who have historically dominated the conversation and who have a vested interest in maintaining the status quo at all costs,” Turner said.

Whether they have a meaningful impact on ISO-NE’s decision-making in the region is an open question though.

“I think there’s always room for more participation, and more diverse participation,” said Turner. “Until then, it may be hard to influence the ultimate outcome of various decisions.”

The View from NEPOOL

Groups like MCAN are welcome, encouraged and appreciated in the stakeholder process, said David Cavanaugh, chair of the NEPOOL Participants Committee.

He said that the climate and environmental groups that have previously participated in meetings have represented their interests well.

“We welcome others who are similarly willing to invest the time to understand and work collaboratively in seeking ways to address creatively the many interests and concerns at the table, and to find enduring solutions to the challenges we are now facing, including prominently the need to reliably serve the region’s energy load while addressing climate change by reducing carbon emissions from the industry,” Cavanaugh said.

He acknowledged that joining NEPOOL can be a challenge for new members.

“There is unquestionably some ramp-up time to learn about the members and their various interests and concerns, and to understand the issues facing the region and alternative ways to address those issues,” Cavanaugh said.

But he laid out a series of ways that the organization aims to get them up to speed, from targeted orientation sessions and trainings, to elected sector officers tasked with helping new members in their sector.

“In my experience, new members will find that representatives of the NEPOOL participants and NEPOOL counsel who have been in the region for decades are generally very willing to educate and fill in knowledge gaps,” he said.

October 24, 2022January 1, 2024

FERC Clarifies When Board Appointees Make Companies Affiliates

FERC on Thursday ruled that it will deem companies it regulates as affiliates if one nominates its own members, investors or employees to another’s board of directors.

The commission issued two orders regarding separate transactions that both required it to determine whether the companies involved — TransAlta (NYSE:TAC) and Brookfield Asset Management (BAM) (NYSE:BAM) in one, and Bluescape Energy Partners and Evergy (NYSE:EVRG) in the other — were affiliates of each other. FERC applies stricter oversight of affiliated companies and their transactions to, for example, determine market-based rate authority and screen against market manipulation.

“It’s very important that we have the kind of insight to understand when parties are affiliated so we can do a better job of regulating” them, FERC Chair Richard Glick said during the commission’s monthly open meeting. “If one company … essentially names board members to another company [who are] affiliated with the first company, then we’re going to deem that an affiliate relationship.”

TransAlta and Brookfield

In one of the orders (EC22-45), the commission addressed an application for a change in control affecting Canada-based TransAlta, based on a shift in company holdings controlled by BAM, a global investment firm.

TransAlta has an extensive presence in U.S. electricity markets through its two power marketing divisions and its ownership of several wind assets and the 730-MW coal-fired Centralia Generation Station in Washington. BAM is affiliated with six power marketing companies in the U.S. and with other entities that own or control generation assets across the country.

In 2019, BAM affiliate Brookfield BRP Holdings (Canada) Inc. purchased debt securities in TransAlta with an option for converting to an equity interest in TransAlta’s hydroelectric assets in Alberta, Canada.

In their application to FERC, filed in March 2022, TransAlta and BAM said the debt securities did not confer any equity voting rights in TransAlta and are not convertible into an equity interest in any of TransAlta’s U.S. assets. But the transaction did result in the expansion of TransAlta’s board from 10 members to 12, two of which would be nominated by BRP while it holds the debt securities.

The debt securities agreement also included a “standstill agreement” that established barriers to control during a “standstill period” expected to end around May 1, 2022. That agreement included a number of provisions, including a restriction on BRP or its affiliates (including BAM shareholders) acquiring more than 19.9% of TransAlta’s shares, engaging in any takeover activities, effecting other restructurings and asset sales, and seeking to obtain additional representation on the board, among other activities.

“In addition, applicants state that the standstill agreement provides that any voting rights associated with shares in TransAlta owned by [BRP] or its affiliates must be exercised in favor of the board’s management nominees and voted in accordance with any recommendations by the board on all other proposals and matters, including director appointments and removals, at annual shareholder meetings,” FERC noted in its order. “Applicants argue that as a result, [BRP], shareholders and other BAM affiliates currently have no discretion to vote any common shares, except solely with respect to a board-recommended extraordinary transaction that would result in a person acquiring more than 50% of the outstanding common shares.”

The companies told FERC that BAM shareholders increased their aggregate holdings in TransAlta’s common shares to 10.1% in March 2020 and now own 13% of the shares. Before expiration of the standstill agreement, they sought the commission’s approval for BAM affiliates to own, with power to vote, 10% or more of common shares.

“Applicants state that because termination of the standstill agreement would result in a change in control over the TransAlta companies if shareholders, together with any other BAM affiliates, own 10% or more of the common shares, applicants request commission authorization for the proposed transaction and associated change in control over the TransAlta companies,” FERC wrote.

The companies contended that, despite BAM affiliates already exceeding 10% ownership, the standstill agreement ensured that BAM and its affiliates could not control TransAlta or its subsidiaries.

“Therefore, applicants argue that a change in control requiring prior commission approval will not occur until the expiration of the standstill provisions, anticipated to occur on or about May 1, 2022,” FERC wrote. “We disagree.”

The commission specifically disagreed with TransAlta and BAM citing FERC’s 2009 decision in Cascade Investment, L.L.C. (EC09-78) to support their contention that the initial investment that elevated BAM and affiliate ownership above 10% did not result in a change of control because of the limitations set out in the standstill agreement. It noted that the Cascade proceeding involved a standstill agreement that included provisions intended to restrict Cascade Investment’s ability to control a public utility through ownership in a holding company, Otter Tail Corp. Those provisions included limiting Cascade’s holding to less than 20% of Otter Tail’s voting securities, a commitment not to seek a seat on board of either Otter Tail Corp. or Otter Tail Power, and a commitment not to influence Otter Tail’s operations or the price at which it sold power.

The TransAlta/BAM proceeding differed in key ways, the commission said:

The application in Cascade was filed before the acquisition of 10% or more voting securities in Otter Tail, whereas BRP and other BAM affiliates had acquired 10.1% of TransAlta in March 2020, which is above the threshold provided in FERC’s blanket authorization of such transactions.
Unlike in Cascade, the BAM affiliates have placed two directors on TransAlta’s board, arguing that holding two seats is insufficient to gain control of the board given its large size and independent composition. But the commission pointed out that it has concerns with structures where the investor itself will be represented on the board, “which confers rights, privileges and access to nonpublic information, including information on commercial strategy and operations,” as noted in FERC’s other decision issued Thursday (see below).
Although the TransAlta standstill agreement contains limitations on the ability of the affiliates to vote shares, it does not contain explicit prohibitions regarding the ability to influence the day-to-day operations of TransAlta, unlike in Cascade.

“We find that contrary to the requirements of [Federal Power Act] Section 203, applicants failed to file a timely request for the disposition of a public utility and acquisition of securities,” the commission wrote. “Specifically, applicants were required to receive commission approval prior to the acquisition by shareholders of greater than 10% of the outstanding TransAlta shares. While we take no further action here, applicants are reminded that they must submit required filings on a timely basis or face possible sanctions by the commission.”

Still, the commission did approve the companies’ application, finding the change in control would have no impact on competition, rates and regulation, nor would it result in cross-subsidization.

Bluescape and Evergy

In a similar proceeding, the commission found that Dallas-based Bluescape is “individually an affiliate” of Evergy and directed the Midwest utility’s operating companies to submit additional information within 30 days so that FERC can process a notice of change in status (ER20-67, ER20-113, ER20-116).

FERC said that Evergy’s appointment of C. John Wilder, Bluescape’s executive chairman, to its board of directors presented a “concern” the commission previously expressed in a proceeding involving CenterPoint Energy. The commission said then that it had an issue with “structures where the investor itself would be represented on the board through the appointment of the investor’s own officers or directors, or other appointee accountable to the investor, in order to support a finding of control.”

“Where an investor’s own officer or director … is appointed to the board of a public utility or holding company that owns public utilities, the investor itself will have those rights, privileges and access, and thus the authority to influence significant decisions involving the public utility or public utility holding company,” FERC said. “As a result, we find that the appointment of a non-independent director from Bluescape to the Evergy board rebuts the presumption of lack of control … and that Bluescape is deemed to be an affiliate of Evergy.”

The commission directed Evergy’s subsidiaries to update their asset appendix with all of Bluescape’s energy affiliates and their associated assets, as well as their horizontal and vertical market power analysis with their affiliates’ generation and transmission assets and inputs to electric power production.

Evergy’s subsidiaries in September 2020 filed a notice of change in status regarding changes to their upstream ownership. This came shortly after Evergy said it would remain a standalone company after exploring several purchase offers by other companies. (See Evergy Releases Standalone Plan Details.)

FERC twice filed deficiency letters in 2021 requesting more information on the upstream ownership. Public Citizen and the Communications Workers of America filed a joint protest in November 2021.

In its Thursday order, the commission found another investment management firm, Elliott Management, was not an Evergy affiliate. It said the record indicated Elliott owns less than 10% of Evergy’s outstanding voting securities and said Public Citizen did not present enough evidence to rebut the presumption of lack of control under federal regulations.

FERC ruled that Elliott’s appointment to Evergy’s board, former U.S. Sen. Mary Landrieu (D-La.), is independent and not compensated by Elliott.

Wilder and Landrieu were named to the board in February 2021, with Wilder also chairing the Finance Committee.

Tyson Slocum, director of Public Citizen’s Energy Program, still applauded the ruling as a “a win for consumers, market integrity and protection from corporate raiders.”

“For utilities with captive ratepayers, all affiliates can only engage in financial transactions with the utility at arm’s length,” Slocum said in a statement. “This prevents an investor from selling services at inflated costs, and then having the utility recover those inflated costs from ratepayers. Today’s order ensures that banks, hedge funds and private equity funds that seek to control a utility’s board cannot engage in such abusive practices.”

Speaking to reporters after the commission’s meeting, Glick said, “This is about consumer protection. If you have affiliates engaging in self-dealing, and we have no way of knowing it or seeing it because we don’t consider two entities affiliates, we’re not going to be able to protect consumers adequately enough.” He also said the rulings would provide certainty to companies so that they know when they would be considered affiliates.

October 24, 2022June 14, 2023

RFF Summit Seeks Effective, Efficient, Equitable Paths to Net Zero

WASHINGTON, D.C. — Resources for the Future (RFF) CEO Richard Newell opened his organization’s Net Zero Economy Summit on Thursday by zeroing in on why international goals to limit global warming and climate change have been so hard to translate into action.

“No single nation directly controls atmospheric concentrations or, indeed, the Earth’s temperature. These are byproducts of something else — emissions,” Newell told the audience of about 300. “This is why targeting emissions such as carbon dioxide and methane is so important, because emissions are something we can control and drive down.

“Net zero brings the challenge of climate change down to the level of a balance sheet: emissions in, removals out,” he said. “The same economic forces that contributed to a problem could be harnessed to fix it.”

Newell’s comments provided a focus for the daylong summit, which dug into the complex nexus of economics and politics surrounding net-zero initiatives in the U.S. and worldwide, the progress being made and the systemic inertia that continues to slow the transition.

Richard Newell 2022-10-20 (RTO Insider LLC) FI.jpg

Richard Newell, RFF | © RTO Insider LLC

On the progress side, Newell said, setting net-zero goals, as 139 countries have done, “focuses everyone’s attention on an outcome that can be directly controlled, something that’s scientifically consistent with stabilizing the environment and something that’s technology-inclusive, open to innovation and ready to harness the power of incentives.”

“Net zero is also scalable at multiple levels for a wide range of decision makers” — from national to state to individual cities and businesses, he said.

But, even with the billions in new funding to advance the U.S. energy transition in the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, the gap between aspiration and action still remains, said Ali Zaidi, White House national climate advisor.

“Code red is no longer a line in an IPCC report,” Zaidi said, referring to the most recent report from the UN International Panel on Climate Change, which predicted potentially catastrophic impacts from climate change without “deep reductions” in greenhouse gas emissions in the coming decades.

“The big, defining question of this moment is not whether we acknowledge that this is the decisive decade; science has acknowledged that for us,” Zaidi said in his summit keynote. “The question is, are we going to put the steel in the ground? Are we going to make the decisions?

“We have gotten very used to analyzing and aspiring and failing to take action,” Zaidi said. “If we fail to do that, no matter how beautiful our model looks in 2040 or in 2050, that’s not going to solve the problem, and we will have failed to meet the moment.”

“We have gotten really, really good at stopping things from happening,” agreed Matt Rogers, former CEO of the Mission Possible Partnership, an alliance of organizations working on decarbonizing heavy industry, such as steel, cement and chemicals. “Now we need a whole new muscle that says, ‘How do we make things happen? How do we build projects … at scale?’ That is an essential element at the federal level, at the state level, at the local level.”

The steel industry, for example, has a major opportunity for decarbonization, Rogers said, during a session on industrial decarbonization. Coal-fired steel blast furnaces need to be refurbished or rebuilt every 15 years “because you’re operating at such a heat level, the bricks get brittle,” he said.

“Between now and 2035, every blast furnace in the world has to go through turnaround,” which could allow all those plants to convert from coal to some form of clean hydrogen, Rogers said.

“That, all of a sudden, is a very different economic model … [but] it doesn’t work if we spend another decade on permitting,” he said. “We need to be able to execute quickly. It’s about speed and scale; those are the key markers.”

‘Block Decarbonization’

A failure to take necessary actions to reduce GHG emissions now could mean a 3-10% drop in U.S. gross domestic product by the end of the century — a potential revenue loss of up to $2 trillion per year — Zaidi said, citing figures from the Office of Management and Budget.

Both he and Newell said hitting net-zero targets — while ensuring an effective, efficient and equitable transition — will require a mix of economic and policy drivers.

For Newell, the three core components are “market incentives, technology innovation and international collaboration, with each of these forces guided by well-designed policy.”

“We need innovation in the market policy and financial structures that must underpin a net-zero economy, and we need these structures to be more equitable in delivering the benefits and distributing the costs of actions taken,” he said. “In short, we need the economy to work for the climate.”

Looking back over RFF’s 70-year history, Newell cited the organization’s early role in the development of the cap-and-trade system, established in 1990, that helped the U.S. reduce the sulfur dioxide emissions that caused acid rain.

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Matt Rogers | © RTO Insider LLC

Putting a price on that pollution meant “we could improve on traditional approaches to regulation by creating incentives to find the most effective and efficient ways to drive that pollution down,” he said.

While recognizing that any kind of national carbon cap-and-trade market is not, at least at present, politically viable, RFF continues to support the idea “because it has so many benefits,” said Alan Krupnick, the organization’s industry and fuels program director. “It levels the playing [field] by having every emitter in the economy subject to a single price.”

Building on President Biden’s climate agenda, Zaidi’s three drivers for net zero are irresistible economics, irreversible progress and visible impact, backed up with a list of administration actions. Examples include the domestic content provisions of the IRA’s solar investment tax credits, U.S. automakers’ ongoing retooling as they ramp up production of electric vehicles, and the impact on community and child health from the rollout of electric school buses funded by the IIJA.

The challenges ahead are, first, avoiding delay, and “taking federal policy and making sure the system metabolizes it as quickly as possible to figure out how to use it,” he said. “For folks in the private sector, the time to make decisions is now. Boards can’t commission study committees; they’ve got to greenlight capital projects. …

“When we delay, costs go up, the risk on implementation goes up, and the people who hurt the most are the poorest and least able to adapt,” Zaidi said.

Rogers said the IIJA’s funding for hydrogen hubs could serve as a model for the mix of policy, economics and accounting for regional differences, which will be needed to get projects done and emissions reduced.

“The right mix of projects in Los Angeles or San Francisco is different, and the way you go about doing it is different in LA or San Francisco than it is in Houston,” he said. “The incentives the DOE has put out in terms of these hydrogen hubs [have] provided a great focusing mechanism on how we get communities to come together and say, ‘Alright, so how do we do this where we live?’”

The hubs could also open the way for a more holistic approach to permitting, in which a cluster or block of projects could be evaluated together rather than one by one “so local leaders can make decisions about block decarbonization,” Rogers said.

Such an approach could show “how the projects fit together and how the hydrogen project enables an ammonia project, and the ammonia project enables decarbonization of the port with shipping activities or decarbonization of fertilizer,” he said.

Looking toward 2030, Rogers said, the next milestone in U.S. and global climate commitments will be “how many projects that we actually get done. The measure of merit is no longer … about commitment; it’s about real projects, real speed on the ground.”

October 24, 2022June 14, 2023

ERCOT Board of Directors Briefs: Oct. 18, 2022

Directors Approve Aggregated DER Pilot Project

AUSTIN, Texas — ERCOT’s Board of Directors last week approved a pilot project in which Texas energy providers can aggregate their customers’ small distributed energy resources and sell their extra energy back to the grid.

The directors voted unanimously Oct. 18 to approve the Aggregated Distributed Energy Resource Pilot Project. The project is intended to evaluate how aggregated DERs can support reliability, participate in the wholesale market and play a role in emergency situations.

“This is a great big historic moment for Texas,” tweeted Arushi Sharma Frank, Tesla’s (NASDAQ:TSLA) lead for U.S. energy markets policy. The pilot “will drive demand for DERs [and] retail competition, and prove out the technology solutions needed for a resilient grid.”

Frank and Tesla have played a key role in the project’s formation. Tesla conducted a virtual power plant demonstration with its Powerwall energy storage product in North Texas earlier this year, while Frank was involved in a Public Utility Commission task force on DERs and testified before the PUC.

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The commission in July directed ERCOT to develop the pilot. Focused on aggregations of individual sites that can inject or withdraw power from the grid in response to ERCOT instructions, the project will give the grid operator’s staff time to develop a full framework for aggregated DER participation (51603).

The pilot will be conducted in phases so that it can begin as quickly as possible while minimizing changes to ERCOT and distribution service provider systems. Future phases could introduce additional design elements “to help expand participation opportunities while still maintaining distribution and transmission grid reliability.”

“We wanted to find a way to allow these resources to participate in the markets without a significant expense to our system upfront,” said David Maggio, ERCOT’s director of market design and analytics.

The initial participation will be limited to 80 MW of registered capacity and 40 MW of non-spinning reserve service to establish limits by load zone and by qualified scheduling entities (QSEs), allowing for diverse geographical and technology participation. ERCOT staff can increase those limits.

The DERs will be dispatched in real time by ERCOT’s security-constrained economic dispatch on a zonal basis and settled using a zonal price. They will only be eligible to qualify for the non-spin ancillary service and offered into and awarded in the day-ahead and real-time markets, similar to the grid operator’s current process for aggregated load resources.

“From our point of view, we’ll see a single resource, a single bid into the market and single telemetry,” Maggio said. “It will look like every other resource we might see.”

The pilot will get underway in January when staff begin DER qualification testing. ERCOT expects the pilot to last at least three years.

PUC Chair Peter Lake said a key answer he is looking for is transmission costs.

“That’s a big question we’ll need to be answered before we put it on monthly bills for our ratepayers,” he said.

Vegas Lays out Priorities

Board Chair Paul Foster welcomed new ERCOT CEO Pablo Vegas to his first board meeting, saying that, “in a very short period of time … he is already beginning to put his mark on the organization.”

Vegas, who only stepped into his position on Oct. 1, said he has been working with the executive team on one of the key elements of his first 100 days, developing a “clear remote work policy.”

One of interim CEO Brad Jones’ first actions last year was to allow most non-operations staff to work from anywhere in Texas, in part to address retention issues it faced after the February 2021 winter storm that drew negative attention to the grid operator.

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“The next evolution of our remote work policy … will continue to focus on balancing, first and foremost, meeting all operational requirements of ERCOT without exception, preserving flexibility for employees whose job roles enable them to work remotely and focus on the continued strengthening of our corporate culture,” Vegas said.

His other 100-day priorities include meeting with key market, regulatory and legislative stakeholders and ensuring the grid is ready for this winter by deploying and executing on new and existing efforts. ERCOT has scheduled winter weatherization workshops Tuesday for transmission service providers and generation owners to review requirements in place following the 2021 winter storm.

Vegas echoed comments he has made in several settings since becoming CEO, saying the key to rebuilding trust in ERCOT is simply “the core of what our operational strategy is.”

“Only through consistent and successful execution under a variety of conditions and scenarios can we return the trust of all Texans that their grid is sound and reliable,” he said, pointing to the grid’s dozens of energy-usage operations during the summer.

“The grid has withstood those tests and passed, but this doesn’t mean that our work is done. It’s really just beginning,” Vegas added. “We’re going to continue executing our mission with the recent successes we’ve had. And we’ll continue to build on that as we move forward.”

Records Fall in Summer Heat

Staff said this past summer was a record-breaking one for both Texas and its grid operator.

Average temperatures from June through August (84.8 degrees Fahrenheit) were the second highest in the state dating back to 1895, exceeded only by 2011 (86.8 F). The heat, and the state’s continued growth, led to 33 demand records, highlighted by an all-time peak of 80.01 GW in July.

“It seemed like we were setting new peaks every day,” Dan Woodfin, vice president of system operations, told the board.

He noted ERCOT set monthly demand records in April and the next four months, using the fingers on one hand as he listed the months. ERCOT added its sixth monthly demand record of the year on Oct. 12 at 66.1 GW.

Staff had about 8 GW of additional installed wind and solar capacity to work with, resulting in higher hourly renewable generation than the year before. Thermal forced outages were also higher this summer than the previous, but only by an average of an extra generating unit from 2021.

Kenan Ögelman, vice president of commercial operations, told directors that while ERCOT did not have to issue any energy emergency alerts during the extreme heat, it did experience several scarcity intervals that led to operator actions. Ancillary services were almost doubled that of two years ago at some points, and the 2,573 total reliability unit commitment (RUC) hours was 10 times that of 2020’s summer.

“We’re using RUCs more than we do traditionally,” Ögelman said.

Asked whether staff were trying to minimize the use of RUCs, Ögelman said, “We’re trying to minimize, but not at the expense of reliability.”

Natural gas prices that reached $9/MMBtu and increased demand for energy led to increased prices. Load-weighted average prices were up over the previous two summers, exceeding $160/MWh in July.

TAC Shares Changes with R&M

Technical Advisory Committee members and ERCOT staff will continue to tweak its process for handling priority revision requests after meeting with the board’s Reliability and Markets Committee on Oct. 17.

TAC Vice Chair Bob Helton, of ENGIE, shared with the R&M his committee’s proposals to accelerate protocol changes that are stuck in the stakeholder process, qualifications for its members and changes to the credit working groups’ structure. (See ERCOT TAC Considers Membership Requirements, Process Changes.)

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The Credit Work Group (CWG) has reported to the board’s Finance and Audit Committee since 2004, but the R&M asked earlier this year that it hear market credit issues from ERCOT staff. The F&A has agreed to give up its market credit oversight responsibilities, with TAC agreeing to take on the role and proposing to consolidate it with its Market Credit Working Group, which reports to the Wholesale Market Subcommittee.

The R&M asked Helton to work with staff in formalizing the Independent Market Monitor’s role in the stakeholder process. The IMM is currently free to comment on revisions requests and participate in the discussions.

The board will vote on the TAC proposals during its December meeting.

Directors Approve Nine Rule Changes

The board passed six nodal protocol revision requests (NPRRs), a modification to the Nodal Operating Guide and two system change requests (SCRs) during the meeting:

NPRR1058: requires quicker updates by QSEs to the telemetered resource status, high sustained limit (HSL) and other relevant information, improving the physical responsive capability calculation’s validity and dispatch.
NPRR1084: allows ERCOT to publicly provide information about resources’ forced outages, forced derates and start-up loading failures in a more complete and timely manner.
NPRR1118: clarifies the outage schedule adjustment (OSA) process to improve the terminology and clarifies the process for issuing advanced action notices and OSAs, as well as offer submission and RUC procedures after an OSA is issued.
NPRR1127: clarifies which entities are required to have hotline and 24/7 communications with ERCOT, and requires those entities answer each hotline call to proactively ensure situational awareness during emergency situations.
NPRR1139: replaces the usage of the wind-powered generation resource and photovoltaic generation resource productions with the HSL of an intermittent renewable resource as reflected in the current operating plan.
NPRR1140: permits generation resources to recover their fuel costs when instructed to start because of an RUC and operate above the resource’s low sustained limit.
NOGRR241: clarifies which entities are required to have hotline and 24/7 communications with ERCOT, and requires those entities answer each hotline call to proactively ensure situational awareness during emergency situations.
SCR820: builds on the hotline communication process by developing a web-based platform supporting real-time, bidirectional, “send-review” messaging between ERCOT operators and transmission operators during emergency event coordination.
SCR823: requests that ERCOT upload a flat file received from each affected transmission/distribution service provider (TDSP) that contains all their electric service identifiers (ESI), besides those that have been retired. This flat file would allow all retail electric providers to have county names associated to all ESIs on the very first day following the go-live of Texas SET V5.0 production.

October 23, 2022March 13, 2024

Renewable Devs Criticize PJM Response to FERC on Queue Proposal

INDIANAPOLIS — Several renewable energy developers and investors filed comments with FERC on Thursday arguing that PJM’s response to the commission’s deficiency letter on its interconnection queue restructuring proposal is insufficient (ER22-2110).

Jointly filing as the Affected Interconnection Customers, the companies argued that PJM has not explained whether the threshold of $5 million of network upgrades under which a project would be eligible to be placed into a fast-track interconnection study queue includes the costs of upgrades that have already been in construction or whose construction could have been fully securitized already through a signed interconnection service agreement (ISA).

Such projects should be permitted to be entered into the fast-tracked expedited process, the companies argued, even if the necessary upgrades would exceed $5 million.

“Network upgrades that have already been constructed or fully securitized prior to the transition date cannot adversely affect subsequently queued projects because they have already been fully committed to financially,” they said. “Transition Cycle projects in queue windows AE1 through AG1 with allocations towards network upgrades that have been fully constructed or securitized (‘fully funded [network upgrades]’) prior to the transition date through a signed ISA should be eligible for the Expedited Process category, regardless of whether those network upgrade allocations are greater than $5 million.”

Without that being the case, the ad hoc group argued that there could be impacts for companies both within the transition queues and those in the pre-transition cycles, which could see their network upgrade burden increase.

“In some instances, it could inadvertently cause such pre-Transition Cycle projects from signing an ISA even though they have remained in queue for up to six years, having planned for network upgrade socialization that PJM is now removing. Such an outcome would be illogical and would not be just and reasonable.”

The group also argued that PJM has not satisfied FERC’s request for justification for the proposed removal of two tariff sections related to reporting and penalties for completing a percentage of the transmission service request studies within a certain time frame. Without further information from PJM, it encouraged FERC to require that the language remain in the tariff until another approach can be found.

“PJM claims to be concerned about inconsistent requirements in its tariff, but PJM does not explain why it cannot consolidate the inconsistent provisions in one place or revise them to fit them into the new regime,” the group said. “PJM also does not try to explain why penalties are no longer needed to enable it to process study requests in a timely fashion, which is very important given the huge backlog of its interconnection queue.”

The group of companies includes Acciona Energy USA, ConnectGen, Copenhagen Infrastructure, Hecate Energy, Leeward Renewable Energy Development, Scout Clean Energy and Tri Global Energy.

Queue Backlog Discussed During OPSI Annual Meeting

During a panel during the Organization of PJM States Inc.’s Annual Meeting discussing the interconnection queue backlog on Oct. 18, American Municipal Power General Counsel Lisa McAlister said she believes that imposing penalties for failing to complete a percentage of the studies could be unfair to both transmission owners and RTO stakeholders.

“While that makes sense and it could be a compliment to the stricter requirements of commercial readiness on the generator’s part, the transmission owners do a lot of the interconnection studies from what I’ve seen, and if they have incomplete information or the information … it doesn’t seem really fair to impose penalties on the transmission owners and then … penalties on the RTO itself,” McAlister said. “The RTO is a nonprofit organization that doesn’t really have independent funds, so those are going to get passed through to PJM members who don’t have any skin in the game and certainly aren’t responsible for not having done the studies.”

Fellow panelist Benjamin Greene, RTO policy manager for American Electric Power, said the penalties could erode the relationship between PJM and its TOs, as well as potentially put the transmission providers in an awkward position of trying to determine which of the two is at fault for studies not being complete.

PJM Vice President of Planning Kenneth Seiler told the panel the RTO is hoping that if FERC approves its proposal soon, it could get through the transition queues within two to three years. Smaller projects that have minimal impact on the grid could be done within six months, with much of the work PJM staff have to commit to studies laying in those projects that would require hundreds of million in transmission upgrades.

Seiler also said he’s hopeful that FERC will revise its interconnection queue Notice of Proposed Rulemaking (RM22-14), issued in June, to remove a proposal to allow developers to ask RTOs and transmission providers to determine the costs of different combinations of projects. Such a rule would increase complexity and slow down PJM’s ability to complete studies, he said. (See FERC Proposes Interconnection Process Overhaul.)

“If we’re going to continue to have optional studies, we’re almost going to go back to where we were or where we are now, which is going to be pretty time consuming. We’re going to have to spin off another group to do optional studies, which everyone else is then taking their studies and deciding if they want to move forward, because all these projects intersect with each other. So the more flexibility we introduce for the developers, the more time it’s going to take for us to process the queues,” Seiler said.

October 23, 2022

PJM MRC Preview: Oct 24, 2022

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting Monday, part of the RTO’s Annual Meeting of Members. 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 have a full report for the Nov. 1 newsletter, along with coverage of the subsequent Members Committee being held this Wednesday.

Markets and Reliability Committee

Opening Remarks (1:05-1:40)

PJM CEO Manu Asthana will deliver opening remarks to the MRC, followed by a presentation on diversity, equity and inclusion (DEI) by Michael Coyle, the RTO’s chief DEI officer.

Consent Agenda (1:40-1:45)

B. The MRC will consider endorsement of the 2022 Reserve Requirement Study’s recommended values for the forecast pool requirement (FPR) and installed reserve margin (IRM) for the next capacity year and set projections for the following three. Should the vote pass, the RRS is scheduled to go before the Board of Managers in December. (See “Stakeholders Endorse 2022 Reserve Requirement Study Results,” PJM PC/TEAC Briefs: Oct. 4, 2022.)

C. The committee will consider proposed revisions to Manual 28: Operating Agreement Accounting to eliminate an exception that has allowed combustion turbine units to recover the costs of their full generation even when they’re operating above their load signal. The changes would bring them in line with the practices and penalties other generator types currently follow. (See “Elimination of ‘CT Rule’ Receives Endorsement,” PJM Market Implementation Committee Briefs: Oct. 6.)

Issue Tracking: Operating Reserve Clarification for Resources Operating as Requested by PJM

D. The committee will also consider proposed revisions to Manual 39: Nuclear Plant Interface Coordination as a part of a periodic review. (See “Manual 39: Nuclear Plant Interface Coordination,” PJM Operating Committee Briefs: Aug. 11, 2022.)

E. The MRC will consider revisions to PJM’s tariff addressing the internal network integration transmission service process that aim to reduce administrative burdens for approving new agreements for transmission within PJM’s network. (See “Streamlining Internal NITS Process Under Consideration,” PJM MRC/MC Briefs: Sept. 21, 2022.)

Issue Tracking: Internal Network Integration Transmission Service Process

Endorsements (1:45-2:20)

1. Fuel Requirements for Black Start Resources (1:45-2:10)

PJM staff will review a proposed package of changes meant to ensure that resources providing black start capabilities are available should they be needed. The language would create a new, higher tier of black start service — “fuel assured” — for generators with added fuel availability, such as through on-site storage or connections to multiple gas pipelines. (See PJM, Monitor Debate Black Start Fuel Requirements Proposals.) The committee will be asked to endorse the proposed manual revisions.

Issue Tracking: Fuel Requirements for Black Start Resources

2. Residential Customer Measurement and Verification for Demand Response (2:10-2:20)

Ken Schisler of CPower will review a proposed problem statement and issue charge to address residential customer measurement and verification for demand response. The work would evaluate the use of statistical sampling for interval-metered residential customers as a solution to data access remaining a barrier to such customers participating in wholesale markets through curtailment service providers. (See “DR Proposal Brought Before MRC After MIC Rejection,” PJM MRC/MC Briefs: Sept. 21, 2022.) The committee will be asked to approve the issue charge.