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December 22, 2025

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PJM MRC/MC Preview: Jan. 27, 2021

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Wednesday. 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)

B. The MRC will be asked to endorse proposed revisions to Manual 6: Financial Transmission Rights addressing the enforcement of FTR bid limits at the corporate entity level. Revisions include adding a bullet to Section 6.6 regarding “FTR Auction Business Rules” denoting the rule for FTR auction bid limits at the corporate entity level. (See “FTR Bid Limits Changes,” PJM MIC Briefs: Dec. 2, 2020.)

C. Members will be asked to endorse proposed revisions to Manual 12: Balancing Operations resulting from the periodic review. The changes include updating the out-of-date two settlement terminology to day-ahead market terminology in the markets database application and adding references to the Dispatch Interactive Map Application and reliability assessment and commitment tool.

D. The committee will be asked to endorse proposed revisions to Manual 13: Emergency Operations resulting from the periodic review. Changes include an updated note in Section 2.2: Reserve Requirements increasing the proportion of contingency reserves that can consist of interruptible load from 25% to 33%.

E. The MRC will be asked to endorse proposed revisions to Manual 18: PJM Capacity Market conforming to the PJM MIC Briefs: Jan. 12, 2021.)

F. Stakeholders will be asked to endorse proposed revisions to Manual 38: Operations Planning resulting from the periodic review. The revisions were unanimously endorsed at the Operating Committee meeting Jan. 13. (See “Manual Endorsements,” PJM Operating Committee Briefs: Jan. 13, 2021.)

Endorsements/Approvals (9:10-11:30)

1. Manual 14C Revisions (9:10-9:30)

The MRC will be asked to endorse proposed revisions to Manual 14C: Generation and Transmission Interconnection Facility Construction as part of the biennial cover-to-cover review. Stakeholders voted to delay the revisions at the MRC meeting Dec. 17 after concerns arose over some of the proposed manual language. (See “Manual 14C Delayed,” PJM MRC/MC Briefs: Dec. 17, 2020.)

2. Real-time Values Market Rules (9:30-9:50)

Members will be asked to endorse a solution package addressing real-time values (RTV) market rules and corresponding revisions to Manual 11: Energy & Ancillary Services Market Operations and the tariff and Operating Agreement. Stakeholders endorsed PJM’s package of updates to RTV that call for additional penalties for generation operators that abuse the rules. (See “Real-Time Values Market Rules,” PJM MRC/MC Briefs: Dec. 17, 2020.)

3. PRD Credits Disposition (9:50-10:10)

The MRC will be asked to endorse a proposed solution package addressing the disposition of price-responsive demand (PRD) credits and corresponding revisions to Manual 11: Energy & Ancillary Services Market Operations, Manual 18: PJM Capacity Market, OA, tariff, and Reliability Assurance Agreement. PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity for an area and do not address the roles of electric distribution companies (EDCs) or curtailment service providers (CSPs), meaning some LSEs are paid for PRD service supplied by EDCs and CSPs. (See “PRD Credits Disposition,” PJM MRC/MC Briefs: Dec. 17, 2020.)

4. Stability Limits in Markets and Operations (10:10-10:50)

Members will be asked to endorse a proposed capacity constraint solution package and corresponding OA and tariff revisions regarding stability limits capacity constraints. The proposal addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. (See “Stability Limits Review,” PJM MIC Briefs: Dec. 2, 2020.)

5. Black Start Unit Testing, CRF, Involuntary Termination, MTSL and Substitution Rules (10:50-11:30)

Stakeholders will be asked to endorse proposed solution packages addressing black start unit testing, involuntary termination, substitution rules, capital recovery factor (CRF) and minimum tank suction level (MTSL), and corresponding revisions to the tariff, Manual 12: Balancing Operations, Manual 14D: Generator Operational Requirements and Manual 15: Cost Development Guidelines. The black start issue has been lingering for months, leading to heated discussions. (See Gen Owners Balk at Change to PJM Black Start Rates.)

Members Committee

Consent Agenda (1:20-1:25)

B. Members will be asked to approve proposed revisions to Manual 34: PJM Stakeholder Process addressing the preference for status quo. The change provides clarifying language to affirm that the preference over the status quo 50% requirement is binding. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: Nov. 19, 2020.)

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ISO-NE Provides Initial Feedback on ‘Future Grid’ Study

ISO-NE said last week that stakeholders’ proposed schedule for the Phase 1 reliability and market analyses in the Future Grid Initiative is “aggressive but achievable” if there are no delays or changes in assumptions or scenarios.

NEPOOL asked ISO-NE in late December to provide feedback on the stakeholder-developed framework document that outlines the modeling for the project, which is intended to predict the impact of states’ policies to reduce carbon emissions and electrify transportation and buildings.

Carissa Sedlacek, ISO-NE’s director of planning services, told a joint meeting of the NEPOOL Markets and Reliability committees Jan. 19 that the RTO has the software to perform all four of the Phase 1 studies in the framework document first brought before the committees in December: simulations of production costs and ancillary services, a resource adequacy screen and a probabilistic resource availability analysis. The RTO said, however, that it lacks the tools to conduct the three Phase 2 analyses — revenue sufficiency in the capacity market and transmission thermal and voltage impacts — recommending NEPOOL hire a consultant. (See New England ‘ Future Grid’ Study Takes Shape.)

Sedlacek said the RTO’s ability to produce a Phase 1 report by May 2022 as requested depends on the “final clarity” of the assumptions and the ability to supply necessary model input data in a “timely manner.”

ISO-NE plans to use staff from past annual economic studies for most of Phase 1 but said the work could delay completion of any additional economic studies requested this year. If ISO-NE is asked to conduct another economic study, the RTO said it would be performed after completing the 2020 economic study for National Grid, which has an expected finish date of June 1.

It said that the Future Grid’s study’s reference to “current state energy and environmental laws” should also mention current market rules and assume the laws and tariff rules in effect as of Dec. 31, 2020.

To aid in comparing study results, the RTO added that it “strongly” recommends using a single target year in studies rather than 2035 for some scenarios and 2040 for others.

ISO-NE said it expects to conduct the Phase 1 work concurrently with its evaluation of the potential pathways part of the Future Grid Initiative which will start next month. The pathways being considered are a Forward Clean Energy Market or Integrated Clean Capacity Market, an Energy Only Market, carbon pricing and alternative resource adequacy constructs. (See Report Outlines NEPOOL ‘Pathways’ to a Future Grid.)

Sedlacek said the RTO would continue to review Phase 1 of the framework to identify any needed clarifications, and it may take up to three months to fully develop and define all study inputs. For the February MC/RC meeting, the RTO will develop a detailed plan for conveying updates on the status of the Phase 1 analyses. It plans to report its progress on the work monthly at the Reliability Committee. Detailed presentations of both interim and final results could be held via additionally scheduled MC/RC meetings.

Schedule

Study assumptions for the first phase of the report are expected to be completed by March 1. The final production cost simulation is scheduled for September 2021 to March 2022, and the ancillary services simulation from September 2021 to January 2022. MARS analyses will occur between October 2021 and January 2022. Drafting of a final report is expected to begin in February 2022.

Dates have not been set for the revenue sufficiency analysis and system security analyses in Phase 2, but they will not start before September 2021.

ISO-NE said there is no model for studying the detailed, operational dispatch needs of the future system — with significant inverter-based resources, interaction between transmission and distribution systems, and evolving load profiles. The RTO is developing a model internally but says it will be a “time-intensive … multiyear effort.”

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Western EIM Questions Performance in Shortfalls

The Western Energy Imbalance Market Governing Body waded into the discussion over CAISO’s summer energy shortfalls on Wednesday, asking questions of CAISO management and pondering how the EIM could better serve participants in times of system stress.

Governing Body Vice Chair Anita Decker asked whether the EIM, an interstate trading market run by CAISO, had provided a level playing field for its participants during the capacity shortfalls in mid-August and over Labor Day weekend — or whether it had favored the ISO.

In addition, she said, the root-cause analysis of the rolling blackouts Aug. 14-15 — prepared by CAISO, the California Public Utilities Commission and the state Energy Commission — had paid little attention to the role of the EIM. (See CAISO Issues Final Report on August Blackouts.)

“The EIM is mentioned, but it’s almost like we’re mentioned in passing,” Decker said. “That left me a little not sure that the EIM benefits were really demonstrated in the [root-cause analysis]. I’m sure they’re there, but I thought it was a little light.”

Member Carl Linvill questioned why demand response resources had not contributed more to heading off the shortfalls. And member Robert Kondziolka, a former management consultant for the Salt River Project, requested further analysis of the EIM’s behavior in the severe heat waves that hammered the West in August and September.

“We should be asking ourselves did the EIM perform as designed and expected? Did it meet requirements? And maybe, importantly, were there any anomalies identified?” Kondziolka said. “Did the EIM help reliability for the system during the summer’s heat waves, and was the EIM effective in helping acquire resources within the operating market timeframe? And then lastly, could the EIM have done more during the times of highest stress on the system?”

CAISO COO Mark Rothleder addressed the concerns one by one.

In response to Decker’s comments, Rothleder said he believes the EIM does provide a level playing field for its 11 members across the West. The root-cause analysis, he said, “didn’t dive deeply into [EIM performance] because, first and foremost, the EIM was not identified as any root cause to the events leading to the need to shed load in the California ISO on Aug. 14 and 15.”

“Our initial review indicated the Energy Imbalance Market generally identified where there was resource sufficiency issues, and more specifically flexibility issues, in the ISO, and it took the designed actions to freeze or limit the amount of transfers the ISO would be getting from other balancing areas that were participating in the EIM at that point,” Rothleder said. “And in fact, we saw transfers coming into the ISO, helping alleviate some of the supply issues that we were encountering on Aug.14 and 15. So that’s what was addressed in the root-cause analysis.”

CAISO has been taking a broader look at how the EIM performed and identified several issues, he said. A capacity test routinely performed on EIM entities had failed to identify capacity insufficiencies in CAISO, but a subsequent flexibility test did identify the shortfalls. The ISO intends to fix the capacity test, he said.

Another issue arose on Sept. 6 when the Pacific DC Intertie linking the Pacific Northwest to Southern California experienced problems, compounded by congestion on the Pacific AC Intertie into Northern California. Rothleder said the ISO is examining whether better interchange coordination or even automation is needed between the EIM’s balancing authority areas during times of system stress.

A major goal of the EIM — and one it is trying to refine in the wake of the summer events — is to promote transfers between members during shortages while preventing participants from leaning on the market and dragging other balancing authority areas into crisis.

CAISO is looking at whether current mechanisms need improvement as part of its 2021 summer readiness market enhancements stakeholder initiative. The EIM governing body will take up the proposed initiative, which has been fast-tracked, in its March meeting, followed by the ISO’s Board of Governors.

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New York PSC OKs Utility Storage Deployment, Cost Recovery

The New York Public Service Commission on Thursday approved tariff modifications for energy storage cost and benefit recovery by the state’s six major investor-owned electric utilities, authorizing revenue sharing of 30% to utility shareholders and 70% to ratepayers when net wholesale market revenues derived from the storage assets exceed contract costs on an annual basis.

The PSC approved one filing by the largest utility in the state, Consolidated Edison Company of New York (CECONY) (Case No. 20-E-0444), effective Feb. 1, and a separate filing by all the other utilities, including fellow Consolidated Edison subsidiary Orange and Rockland Utilities (O&R), effective immediately (Case No. 18-E-0130).

The other IOUs included Avangrid subsidiaries New York State Electric and Gas (NYSEG) and Rochester Gas & Electric; Central Hudson Electric and Gas; and National Grid subsidiary Niagara Mohawk Power. Their joint filing with O&R was only slightly different from CECONY’s.

The commission in December 2018 set a goal of deploying 1,500 MW of storage by 2025. It required CECONY to procure and have operational by Dec. 31, 2022, at least 300 MW of energy storage scheduling and dispatch rights, and 10 MW for each of the other IOUs, provided that the bids do not exceed a utility-specific defined ceiling.

“The order achieves a good balance of consistency, transparency and practicality,” PSC Chair John B. Rhodes said. “It is good practice to order these tariff aspects, and it’s also important to open up opportunities consistent with our storage order of 2018 in order to support our clean energy goals for the state, our reliability goals for the state and system savings to the benefit of all New York customers.”

The utilities last year worked with government officials and project developers to fine-tune the processes and contract terms of state-mandated energy storage solicitations. (See NY Utilities, Developers Tweak Storage Procurement Terms.)

“We are at the actual beginning of our baby steps of our enormous goals on storage, and I’m confident that storage will come back to us time and time again as we move forward in compliance with the climate act,” said Commissioner John Howard, referring to the state’s Climate Leadership and Community Protection Act.

Yes to Marcy-New Scotland

The commission also unanimously granted a certificate of environmental compatibility and public need to the Marcy-New Scotland upgrade project being jointly developed by LS Power Grid New York and the New York Power Authority. It also approved lightened regulation and flexible financing for LS Power, up to a maximum amount of $478 million (Case No. 20-E-0361).

Lightened regulation under the Public Service Law is intended for companies that operate only at the wholesale electric market level and have no direct impact on the retail customers regulated by the PSC. NYISO Board Selects 2 AC Public Policy Tx Projects.)

The Marcy-New Scotland project involves building 93 miles of a new 345-kV line from Edic to New Scotland on an existing right of way; erecting two new 345-kV lines from Princetown to Rotterdam; decommissioning two 230-kV lines from Edic to Rotterdam; and doing related switching or substation work at Edic, Princetown, Rotterdam and New Scotland.

“This line has been part of my life for most of my life, and in fact, I’ve lived for over 40 years within a mile or two of the current line,” Howard said. “The issue of the need for this line goes way back before this particular proposal. The need for more cross-state interconnection and at the time, the need was to help reduce pricing into downstate regions, which wanted to take advantage of lower-priced assets upstate.”

The more environmentally sensitive planning process these days will allow bringing many megawatts of renewable energy into the load areas in downstate New York, he said.

“I don’t think the commission really sees projects of this magnitude with this much consensus behind them,” Howard said.

NYSEG Dinged for Isaias; Other IOU Cases Pending

The commission reached a $1.5 million settlement with NYSEG for its alleged violations regarding its preparation and restoration efforts related to Tropical Storm Isaias, which struck the state Aug. 4 last year (Case No. 20-E-0586).

Isaias caused approximately 1 million customer outages in the state, affecting roughly 1.5 million New Yorkers. Gov. Andrew Cuomo on Aug. 5 directed the Department of Public Service to investigate the electric service providers’ performance in response to the storm.

The department evaluated NYSEG’s response against the utility’s emergency response plan and found that, “while NYSEG’s performance was better than its response to past storms, it nevertheless violated its own plans three times,” Rhodes said. “As part of the settlement, NYSEG admitted to the three violations and agreed to provide customers with $1.5 million in benefits, the maximum amount allowed under the statute.”

Of those million outages, 183,000 were located in NYSEG service territory, mostly in its Brewster Division that serves customers in Dutchess, Putnam and Westchester counties.

As part of its consent agenda, the commission approved further investigation into the Isaias preparation and response by Central Hudson, CECONY, O&R and PSEG Long Island. It also announced it was moving to the next phase of the proceeding.

PSEG is not under PSC jurisdiction, so the commission provided recommended enforcement actions to the Long Island Power Authority. The three utilities under its jurisdiction “now face maximum potential penalties of up to $137.3 million, with Con Edison and O&R also facing potential license revocation depending upon a finding of repeat violations,” the commission said.

The order to move to the next phase of investigation “misses the mark,” Commissioner Diane Burman said, recommending that the PSC rethink its approach to utility performance in responding to storms.

“We’re seeking to cure some possible procedural infirmities … however, we can’t really do that if we’re not fully examining the substantive information that we’ve received since the November 2020 orders to show cause,” Burman said. “We have the emergency response plan filings. … We are continually knowing that we have to assess and be ready to prepare for the next storm. We have an obligation to carefully look at the responses that came in as a requirement of the orders to show cause.”

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Biden Names Glick as FERC Chair

President Biden early Thursday named Commissioner Richard Glick as Bay Resigns after Trump Taps LaFleur as Acting FERC Chair.)

Glick would join later that year in November after serving as general counsel for the Democrats on the Senate Energy and Natural Resources Committee. He served as the lone Democrat on the commission for more than a year after the departure of Commissioner Cheryl LaFleur in August 2019 until the arrival of Allison Clements last month.

Prior to his job in the Senate, Glick was vice president of government affairs for Iberdrola’s renewable energy, electric and gas utility, and natural gas storage businesses in the U.S.

“I am honored that President Biden has shown the confidence in me to lead the agency at this critical moment in time,” Glick said in a statement. “I look forward to continuing working with my fellow commissioners and the exemplary FERC staff to pursue the commission’s important statutory missions.”

Glick has frequently delivered strongly worded dissents over orders by his Republican colleagues approving natural gas infrastructure without considering their downstream greenhouse gas emissions and what he argues as interfering with state resource mixes through RTO/ISO capacity market rules — positions he also explained at FERC’s open meetings.

Despite these strong disagreements, Glick has often said at public events that he gets along with his fellow commissioners and former Chair Neil Chatterjee. While Chatterjee tended not to respond to his comments at meetings, Glick found sparring partners in Danly and Commissioner Bernard McNamee.

Trump named Danly chair two days after the presidential election, demoting Chatterjee after the latter joined with Glick on Oct. 15 in supporting a proposed policy statement inviting states to introduce carbon pricing in wholesale electricity markets to address climate change. (See Trump Names Danly FERC Chair.)

Barring any resignations in the interim, Glick and Clements will remain in the minority until at least the end of June, when Chatterjee’s term ends, though it could last longer if Biden and the Senate do not immediately appoint a replacement. At the commission’s open meeting Tuesday, Danly’s last as chair, Glick praised both Chatterjee and Danly for their leadership. (See related story, FERC Ends Trump Era with a Busy Agenda.)

“As everyone who follows this commission knows, I’ve been a little critical at times over the last couple years for what I believe, at times, was a departure from the commission’s normal practice,” Glick said in closing remarks. “Instead of back-and-forth discussions and negotiations … the minority was presented with a take-it-or-leave-it offer on a number of orders. …

“But I want to say, first under the leadership of Chairman Chatterjee beginning this past summer, and then under Chairman Danly, there has been a noticeable shift in the approach, and I’m very appreciative for that. In my opinion, there has been far more opportunity discussion, negotiation and compromise.” He cited FERC Order 2222, which in September directed RTOs and ISOs to open their markets to distributed energy resource aggregations, as an example.

“I’m confident … this five-member commission will work well together to accomplish this commission’s important missions, and I look forward to continuing to work with my colleagues,” he concluded.

Numerous energy trade associations, politicians and energy lawyers congratulated Glick on his promotion — and expressed their hope he would address their priorities.

“I have worked with Rich for many years, and I know he will lead FERC and serve the nation well as chairman,” said EEI Executive Vice President and former FERC Commissioner Phil Moeller. “We congratulate him and encourage the commission to address the many key issues impacting EEI member companies and our customers, including making necessary reforms in wholesale electricity markets; enabling the development of the transmission infrastructure needed to deliver more clean energy to customers; and continuing to focus on reliability and energy grid security.”

American Council on Renewable Energy CEO Gregory Wetstone said ACORE is “particularly hopeful that Chairman Glick will turn his strong condemnation of the minimum offer price rule in the PJM capacity market and the buyer-side mitigation measures currently imposed in NYISO into immediate action.”

“ACORE also looks forward to the commission beginning the process of replacing Order No. 1000 on transmission planning,” Wetstone added. “We also encourage the Commission to swiftly finalize its proposed policy statement on carbon pricing and expand and standardize hybrid resource integration across RTO/ISO markets.” (See Wide Support for FERC Carbon Pricing Statement.)

Glick “understands the need to retool and expand competitive wholesale power markets to align them with state and federal clean energy and climate policies, ensuring that they serve as a platform for a zero-carbon advanced energy future,” said Jeff Dennis, managing director and general counsel for Advanced Energy Economy. “We also look forward to Chairman Glick’s leadership in optimizing the transmission grid to deliver the cost-effective advanced energy resources that customers are demanding.”

Biden’s DOE Roster Fills out

Also on Thursday, the Department of Energy announced a slate of appointees to senior leadership positions.

Among them is Kelly Speakes-Backman as principal deputy assistant secretary for energy efficiency and renewable energy. Speakes-Backman was the first CEO of the Energy Storage Association, whose board of directors immediately appointed Vice President of Policy Jason Burwen as interim CEO. Prior to ESA, Speakes-Backman served on the Maryland Public Service Commission.

Jennifer Wilcox will serve as principal deputy assistant secretary for fossil energy. Wilcox is the presidential distinguished professor of chemical engineering and energy policy at the University of Pennsylvania, where her research at the Kleinman Center for Energy Policy focused on carbon management, capture and sequestration.

Avi Zevin, formerly a senior attorney and affiliated scholar at the New York University School of Law’s Institute for Policy Integrity, was appointed deputy general counsel for energy policy.

Biden, who is moving quickly to put his cabinet in place, has nominated former Michigan Gov. Jennifer Granholm as secretary of energy. The Senate ENR Committee on Thursday announced it will hold her confirmation hearing on Wednesday, Jan. 27.

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Advisory Committee Charts Course on MISO Sector Rules

MISO’s Advisory Committee has put the finishing touches on a revamp of the RTO’s stakeholder sector setup.

The AC said Wednesday that it will defer to MISO as the final arbiter over whether a new company or organization is entitled to join a certain sector. Members agreed that will prevent a sector from being able to veto an entity’s request to join.

The committee also laid out a challenging process for creating a new sector beyond the existing 11 sectors.

Members said creation of a new sector should be a “last resort,” requiring a written purpose and more than 10 prospective members with documented evidence of active participation in stakeholder meetings. The AC must then recommend the new sector that the Board of Directors would vote on before MISO files tariff changes with FERC.

MISO Sectors
A MISO Advisory Committee gathering in March 2018 | © RTO Insider

When some members said the requirements for forming a new sector might not be specific enough, AC Chair Audrey Penner said the vagueness was deliberate so requests for new sectors can be decided on a case-by-case basis.

“I thought of this more as a guideline than something that is hard-coded … enough so that separate circumstances can be considered,” Penner said.

MISO has also posted a new guide that prospective members can review to get a clearer idea of requirements before joining.

“Obviously someone new would not understand totally what the sectors are … so we hope they will reach out to MISO,” AC liaison Bob Kuzman said.

Affiliate Sector not Pleased with Voting Rights

The AC also decided the 11th and newest sector — the Affiliate Sector — should have one vote apiece on the Advisory and Planning Advisory committees. (See MISO Members Back Voting Rights for New Sector.) The AC will direct MISO’s legal team to incorporate the changes into the tariff with Board approval.

The Affiliate Sector currently can’t cast votes, though it can offer opinions during discussions with the Board at the AC’s quarterly meetings.

FERC last year ruled that MISO could rely on the Affiliate Sector as a catch-all for difficult-to-define members only on a temporary basis because it had not developed a meaningful way for the new sector to participate in RTO matters. (See New MISO Sector Gets FERC OK — with a Catch.)

The non-member Affiliate Sector contains North Dakota coal lobbying group Lignite Energy Council, coal trade organization America’s Power, chambers of commerce and several mining organizations. It also contains conservative lobbying group Center of the American Experiment and sustainability and conservation trade association Minnesota Forest Industries.

Lignite Energy Council’s Jonathan Fortner, also Affiliate Sector chair, said it was unfair that the four other stakeholder sectors that aren’t subject to MISO membership dues — the State Regulatory Authorities, Public Consumer Advocates, Environmental and Affiliate sectors — are imbalanced in their voting rights. The Regulatory sector is represented by four seats on the AC with a 16% weight in voting matters — the most of any sector — while the Public Consumer Advocates and Environmental sectors each hold two seats apiece at an 8% weight.

Fortner has called for a “level playing field between similarly situated stakeholder sectors” and an “equal number of votes and voices at the table in order to advocate for [sector] interests because there will be challenging votes on the AC board in the near future.” He said the AC’s recommended voting approach could have potential legal concerns and could be “inconsistent with the Federal Power Act.”

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Members Send MISO Back to Drawing Board

Stakeholders told MISO on Wednesday to rework a proposal that allows the RTO to remove stakeholders and committee leadership in certain situations.

MISO is seeking to codify in the stakeholder governance guide its ability to remove a stakeholder committee chair and to unilaterally ban disorderly stakeholders from meetings in response to an incident involving a stakeholder in 2019.

However, the Advisory Committee put the proposal on ice during the meeting Jan. 20, with members saying vague language needs wordsmithing.

The grid operator said it should be able to bar stakeholders when they cause a disruption or damage while on MISO property, become physically or verbally abusive, or threaten physical harm to other staff and stakeholders. These threats can be written or spoken, General Counsel Timothy Caister said.

The RTO said it should also be able to remove stakeholders if it is made aware of “information that would justify or otherwise provide a reasonable basis for such an action.”

Caister said MISO needs to be able to prevent building damage and physical harm. He said the proposal’s language is intentional “because of past experience.”

“We do believe it’s appropriate to add this in light of findings and lessons learned,” Caister said.

In August 2019, MISO removed a stakeholder from its facilities after the individual sent threatening emails to multiple MISO executives. The incident resulted in two MISO executives filing orders of personal protection against the stakeholder.

MISO also wants to list grounds for removing a stakeholder chair from their committee. It recommended that staff or stakeholders initiate removal when a chair is repeatedly not available for committee meetings, is not fulfilling their leadership role, not observing stakeholder governance rules, or “demonstrating, condoning or otherwise not managing unprofessional behavior during meetings.”

Madison Gas and Electric’s Megan Wisersky said she worried the proposed language is too vague and permits MISO “way too much latitude for what could be very subjective reasons.”

“I’m not saying it’s going to be, but it could be potentially abused,” she said, adding that stakeholders can always vote to remove committee leadership.

“MISO already has the ability to oust anyone who’s abusive or is doing damage to property,” Wisersky added.

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NY Grid Study Pushes Meshed OSW Transmission, Coordination

New York state energy agencies on Tuesday released a three-part study that urges faster permitting, planning and approval processes to build the transmission necessary to accommodate the nearly 40 GW of new renewable energy plugging into the grid over the next two decades.

The Initial NY Power Grid Study Report recommends that transmission planners increase their reliance on NYISO’s stakeholder processes, particularly for developing public policy projects. It says the most urgent needs are to link Long Island’s expected 3 GW of offshore wind energy with the mainland and to beef up the infrastructure needed to import 6 GW of OSW into New York City.

The state’s Department of Public Service and the New York State Energy Research and Development Authority (NYSERDA) prepared the study, supported by The Brattle Group and Pterra Consulting, among others.

“‘Initial’ means it’s the 2021 installment, and ‘full’ means it is complete at about 750 pages of work,” Public Service Commission Chair John Rhodes, said in announcing release of the report at a meeting of the state’s Climate Action Council.

The PSC ordered the report last May, as directed by the Accelerated Renewable Energy Growth and Community Benefit Act (Case No. 20-E-0197). (See NYPSC Launches Grid Study.)

The study comprises three components, examining transmission needs for OSW and bulk system needs for land-based renewables out to 2040, as well as needs on the sub-bulk level.

“We think it’s very well done. We know it’s informative, has many interesting findings and is a major milestone in terms of creating the information foundation for us to craft the right kind of transmission future for the state,” Rhodes said.

Procuring 9 GW of OSW by 2035 is vital to meeting the goals established by the Climate Leadership and Community Protection Act, which mandates that 70% of electric power in New York come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040.

Local transmission and distribution (Phase 1) projects already under development appear sufficient to integrate land-based renewables, although some might be accelerated, the report said.  Other more preliminary (Phase 2) projects might be pushed forward in order to attract investment in solar and wind development Upstate.

“In particular, [New York’s] Zero Emissions Study results suggest that additional bulk transmission from Upstate into the New York City area (from Zone H to Zones I, J and K) will likely become cost effective as the state approaches 2040 and congestion costs increase,” the report said.

OSW Scenarios

In calling for the start of development of a tie-line between Long Island and Zone I or J, the study said that “all studies indicate that additional tie-line capacity would be needed by 2035–2040 as renewable requirements grow and emissions limits tighten. Advancing such a project would provide additional value earlier if constraints into New York City force more than 3,000 MW of OSW into Long Island and mitigate curtailments associated with real-world operating conditions not captured in the studies’ simulations.”

The report also urged a multidisciplinary planning and coordination effort for routing up to 6 GW of OSW generation into New York City and interconnecting it with the city’s substations.

“However, overcoming cable routing limitations in New York Harbor, space constraints in substations in Manhattan, and permitting complexities in both the Harbor and along the Long Island coastline (including approaches to New York City through the Long Island Sound) will require careful planning of OSW transmission cable routes and points of interconnection,” the study said. “Creating the option for a meshed offshore network by linking the offshore substations of several individual OSW plants near each other is valuable because a meshed configuration can achieve a more reliable and resilient delivery of OSW generation.”

The study concluded that a decision to implement a meshed system can — and possibly should — be delayed pending federal approval of new wind energy areas, as long as New York officials ensure that any projects with radial connections are built with an option to integrate into a meshed system later.

In its comments related to the study, NYISO said transmission congestion and curtailment patterns drive bulk transmission expansion, which the study contends will be necessary to integrate all the new renewable energy resources being developed under state clean energy policies.

To inject OSW energy, smaller megawatt amounts at more points of interconnection could potentially require less transmission expansion, NYISO said.

However, “based on the cable routing study conducted by the DPS’s technical consultant, there appear to be limited available cable routings through New York Harbor. If each project has independent radial connections, opportunities for necessary cabling to achieve the full offshore wind goal of 9,000 MW will be limited,” The ISO said.

“The study makes clear that to overcome interconnection challenges and achieve this [9 GW] goal, New York needs carefully planned offshore wind cable routes and points of interconnection that will ensure reliable, resilient delivery of offshore wind energy to power New York homes and businesses,” Janice Fuller, Anbaric’s Mid-Atlantic president, told RTO Insider. “Governor Cuomo has called on the market for creative proposals to meet this critical challenge.”

Local T&D Cost Allocation

The report found that Phase 1 local transmission projects would unbottle delivery of an estimated 6.6 GW of renewable generation, while proposed Phase 1 distribution projects could tap another 2 GW. The study estimates that the more preliminary Phase 2 project proposals for local transmission could provide 12.7 GW of renewable integration benefits, based on the headroom calculations, while Phase 2 distribution proposals could support an estimated 2.8-4.3 GW.

Both utility and NYISO transmission planning processes should be improved to recognize the unique advantages that advanced technologies such as dynamic line ratings can provide, the study said. For example, commercial-scale applications for dynamic line ratings “have demonstrated a 20-30% increase of average annual transmission capacity above static ratings (e.g., with a 10% increase during 90% of the year, 25% during 75% of the year, and 50% during 15% of the year), while maintaining or enhancing system reliability.”

The power grid study also recommends allocating the costs of these projects state-wide on a load ratio share basis, as recommended by the state’s investor-owned utilities, which in November jointly filed a report on transmission and distribution investment. Representatives from each company joined a technical conference to outline their policy recommendations and propose projects to state officials. (See Meshed OSW Tx Grid May Work Best, NY Officials Hear.)

The IOUs include Avangrid subsidiaries New York State Electric and Gas and Rochester Gas and Electric; Central Hudson Electric and Gas; Con Edison and its subsidiary Orange and Rockland; and National Grid subsidiary Niagara Mohawk Power. Collectively the utilities propose to spend $7 billion on transmission and distribution upgrades by 2025 and an additional $10 billion over the following five years.

The IOUs’ comments on the new grid study reiterated points from their earlier report and incorporated learnings from the technical conference Nov. 23, noting “the fundamental need” for local transmission and distribution investment to support the integration of clean energy resources. “In other words, the zero emissions grid presentation recognized that there is a clear interdependence between the local and bulk transmission system upgrades; without resolving the congestion and curtailments on the LT&D system, the value to customers of new bulk transmission investments and renewable generation will be limited,” they said.

Con Edison identified three immediately actionable projects around New York City, estimated at $860 million. The utility on Dec. 30 filed a petition with the PSC seeking approval to recover project costs through its rate plan capital budget, and also for up to $4 billion for the second phase of six projects to create points of interconnection, including two new “NYC Clean Energy Hubs,” several new feeders and the rebuilding of two area stations.

Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, submitted comments on the new grid study emphasizing that “customer funds are not unlimited, particularly in the aftermath of the economic recession caused by the COVID-19 pandemic.” The group urged the commission “to ensure that customers — and especially energy-intensive/trade-exposed businesses that are price-sensitive — are not burdened with excessive or unnecessary costs.”

New York City said the PSC should deny Con Edison’s requests for pre-approval as the report does “not provide sufficient information to provide a rational basis for such a decision,” and should also consider mechanisms for cost containment to help control the costs of the additional infrastructure that will be needed.”

The New York Power Authority (NYPA) said that a cost allocation approach in which NYSERDA would use System Benefits Charge funds to pay for transmission improvements supporting state policy goals would be “extremely difficult to exercise with NYPA” because its customers do not pay the charge, nor does NYSERDA have legal authority to charge NYPA’s municipal customers.

NYPA supports a proposal for the PSC to authorize a retail charge that would be distributed as appropriate among utilities pursuant to a commission-approved adjustment mechanism, which “means cost recovery would be set within retail rates and would not require a proceeding at FERC or any additional approval.”

NYISO Views

The state will likely need new transmission system facilities if more renewable resources are assumed to locate in Western New York, Northern New York and the Southern Tier as development trends suggest, the ISO said.

The grid operator said that NYSERDA awards of renewable energy credits to date support the conclusion that renewable investments will concentrate in certain geographic areas, and that its 2019 Congestion Assessment and Resource Integration Study (CARIS), released last July, provides insights into the potential value of additional transmission capability across the state.

“In the 70×30 Scenario simulations, approximately 11% of the annual total potential renewable energy production would be curtailed across the New York system,” NYISO said.

The power grid study said that more work will be necessary to quantify existing headroom in various transmission-constrained areas on the local and bulk transmission systems and “to identify high-priority, high-value locations that should be targeted with transmission upgrades. These studies should be based on both a power-flow model that better measures headroom capacity and a production simulation model — ideally aligned with the NYISO’s economic planning process assumptions and modeling tools — that can estimate annual curtailments and the extent to which proposed upgrades can reduce these curtailments.”

Based on its interconnection queue, over 90% of the land-based renewable capacity proposed outside New York City and Long Island is in NYISO Zones A through E, leaving less than 10% in Zones F and G, NYISO said.

The ISO referred to its own climate change impact and resilience study and to a decarbonization pathways study by NYSERDA, saying that both 2020 reports support the need for firm capacity to meet multi-day periods of low wind and solar output, a need most pronounced during winter periods of high demand for electrified heating and transportation.

Regarding bulk system storage resources, NYISO said a model should reflect their operational charging and discharging cycles as well as the probability of their availability.

NYISO also supports the use of its public policy process to solicit competitive solutions, a process it says should now take approximately 18 months following the PSC’s identification of such a transmission need.

The ISO’s Market Monitoring Unit, Potomac Economics, questioned NYISO’s benefit/cost analysis methodology for local transmission planning, saying that if “it relies on biased assumptions, there is a risk that viable alternative solutions that are more cost-effective or do not rely on ratepayer guarantees will be crowded out.”

In particular, the Monitor said that the CARIS 70×30 case was never designed to be an accurate forecast of the power system in 2030 and hence does not provide a reasonable basis for evaluating the benefits of individual transmission proposals.

“First, we recommend developing economic criteria for future resource inclusion in the forecast model and using multiple realistic scenarios when assessing projected curtailment. Second, we recommend changes to the LBMP, capacity value, cost of capital and period of analysis assumptions that will more accurately quantify projects’ benefits and risks,” the Monitor said.

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NERC Standard Drafting Teams Mulling Merger

The standard authorization request (SAR) drafting team for Project 2020-06 (Verifications of models and data for generators) is considering how to merge its work with Project 2020-02 (Transmission-connected dynamic reactive resources) after most industry respondents expressed support for the idea in a recent informal comment period.

Project 2020-06 was launched last year by NERC’s Standards Committee upon recommendation by the Inverter-based Resource Performance Task Force (now the Inverter-based Resource Performance Working Group) and endorsement by the Reliability and Security Technical Committee. (See “IRPTF SARs Accepted,” NERC Standards Committee Briefs: Sept. 24, 2020.)

The project targets reliability standards MOD-026-1 (Verification of models and data for generator excitation control system or plant volt/VAR control functions) and MOD-027-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions). Both standards “contain language that is specific to synchronous generators [and] not applicable to IBRs [inverter-based resources].” The project aims to clarify which requirements apply to which type of resource.

Both are also in the scope of Project 2020-02, which was approved by the Standards Committee in March 2020 with the goal of modifying them and other standards to apply to nonsynchronous energy sources. (See “Approvals,” NERC Standards Committee Briefs: March 18, 2020.) However, that project is now “on hold indefinitely,” according to NERC, with its scope to be “parsed out” to other development teams working on the applicable standards.

NERC did not give its reason for suspending 2020-02, but the last informal comment period on the SAR, which closed in May 2020, revealed widespread dissatisfaction among participants. Many complained that the project’s scope was too broad: Daniela Atanasovski of Arizona Public Service (APS) called for a separate SAR for HVDC devices, while Marty Hostler of Northern California Power Agency said the SAR “needs to clearly state” that generator owners and operators will not be affected by any changes to the relevant standards.

“From our experience with FERC, NERC and WECC, unless the SAR or the standard specifically states it is not applicable to GO/GOPs, we are going to have to annually provide documentation/evidence proving that we don’t own/operate transmission-connected resources and compile evidence, or null evidence letters, annually proving compliance or non-applicability of the standard,” Hostler said.

Concerns Remain over Scope

The suggestion to move all modification efforts for MOD-026-1 and MOD-027-1 under Project 2020-06 was backed by many critics of 2020-02, such as Richard Jackson of the U.S. Bureau of Reclamation, who repeated an earlier recommendation that the drafting team “coordinate changes with other existing drafting teams for related standards.” Kelsi Rigby of APS voiced approval as well, through she requested clarity that the drafting team for 2020-02 would continue to work only on other applicable standards.

Many who had supported 2020-02 also approved of the change. Mark Gray of Edison Electric Institute said last year that the project “identifies a gap in the existing body of reliability standards,” but now he “supports the concept” of merging the efforts. He noted that the change would be a “significant expansion” of 2020-06 and urged that the revised SAR be resubmitted for comment.

However, not all commenters viewed the move positively. Thomas Foltz of American Electric Power called the scope of 2020-02 “far too open-ended” but urged that the projects remain separate, even though combining them “[appears] to make logical sense from a topical standpoint.”

“There is technical merit in keeping the two projects and resulting standards separate because even though IBRs and dynamic reactive devices are both electronic-based, they are different enough in function and configuration to justify their own distinct efforts and resulting standards,” Foltz said. He added that the implementation plans for MOD-026 and MOD-027 are already “well underway” and that modifying them at this point would create confusion.

Bobbi Welch of MISO said the organization is “supportive of the same [standard drafting team] working on both projects” but called for them to be “approved and tracked separately.” Welch warned that tying the two projects together would require “adding transmission owners and a host of … equipment” that are currently not covered by MOD-026 and MOD-027 to their scope, potentially delaying the production of specifications needed for generator testing.

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MISO Reports Unremarkable December Ops

Peak demand was lower in December than in years past, MISO executives said during an informational forum Tuesday.

Rob Benbow, executive director of real-time operations, said peak demand topped out at 91 GW on Dec. 15, despite blizzard-like conditions in MISO North just before Christmas that resulted in the month’s coldest temperatures.

The peak was the lowest for December in five years, when it exceeded 100 GW. The year before, December’s peak was 96 GW.

Benbow said had the wintry weather shown up outside of the holidays, it probably would have created a larger peak. He said the subdued holiday load patterns lessened demand.

In the fall, MISO projected a 104-GW winter peak would occur in January. Its all-time winter peak came in January 2014 at 109.3 GW during a polar vortex. (See MISO: Winter Could Get Tricky Despite Forecast.)

MISO peak demand
| Madison Gas and Electric

Higher natural gas prices nudged up real-time energy prices in a year-over-year comparison, from about $21/MWh in 2019 to $24/MWh.

Staff said strong winds on Dec. 23 caused MISO to register a new all-time wind peak of more than 20 GW, accounting for about 27% of the load at the time. Just five years ago, MISO was setting wind peaks of around 11 GW.

“I’m giving old news when I report on wind peaks. Because by the time I do, invariably another wind peak occurs,” MISO Independent Market Monitor David Patton said during the January Market Subcommittee meeting.

MISO operations continue to be unaffected by the COVID-19 pandemic, Senior Vice President Todd Hillman said.

He said MISO is currently working with state and local officials on employee coronavirus vaccinations and that the RTO supports early vaccine priority for its control-room operators and IT personnel.

In the meantime, Hillman said MISO will keep stakeholders updated on when meetings can transition back to an in-person format.

“We all look forward to the time to get back together,” he said.