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November 17, 2024

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FirstEnergy CEO Abruptly Retires, Without Severance

FirstEnergy (NYSE:FE) announced late Thursday night that President and CEO Steven Strah would be replaced the next day by John W. Somerhalder II, chairman of the board of the directors.

The company announced the move in a filing with the Securities and Exchange Commission and a news release issued about an hour after markets closed Thursday. Strah is retiring without a severance package, though he will be accorded pension benefits. Somerhalder will serve as interim president and CEO while the board conducts a search for a permanent replacement.

The press release also noted that the company had completed its review of its top management team, as required in a proposed settlement of shareholder lawsuits.

Neither the release nor the 8-K filing contained an explanation for Strah’s “decision to retire” just 18 months since his permanent appointment in March 2021. Strah had been named acting CEO in October 2020, replacing fired CEO Charles Jones.

Federal prosecutors had identified Jones as having been involved in a company-financed bribery of former Ohio House Speaker Larry Householder, who was indicted in a federal racketeering conspiracy in connection with the passage in 2019 of H.B. 6, legislation creating a $1.3 billion bailout of two nuclear power plants in the state then owned by FirstEnergy. Lawmakers later rescinded the subsidy in the wake of the federal charges.

Jones has not been charged in the ongoing federal probe, but FirstEnergy entered a deferred prosecution plea admitting its involvement and agreeing to pay a $230 million fine. Householder’s trial is scheduled for January.

During his brief tenure as CEO, Strah has served as the face of a corporate turnaround, leaving the bribery scandal behind, making his unexpected retirement more surprising. Some local media, and a national watchdog group immediately speculated that his departure is linked to emails that recently came to light between Strah and company lobbyists during the H.B. 6 campaign.

The board’s leading independent director, Lisa Winston Hicks, praised Strah in the company’s announcement: “I would like to thank Steve for his many contributions and years of service to FirstEnergy and wish him well in his next chapter.”

The release also contained an upbeat statement from Strah.

“It has been a great honor to be part of the FirstEnergy family for more than 38 years,” he said. “I want to express my gratitude to the extremely dedicated employees, as well as our incredibly talented management team. I believe the future holds great opportunity for this organization.”

Somerhalder has been chair of the board since May and joined the company as vice chair and executive director in May 2021. Prior to that he served as interim president and CEO of CenterPoint Energy from February to July 2020.

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FHWA Beats Sept. 30 Deadline for Approving States’ EV Charging Plans

One day after President Biden celebrated the passage of the Inflation Reduction Act ― including its incentives to help more Americans buy electric vehicles ― the administration on Wednesday also announced that 35 states have been approved to receive millions in federal funding to be used to build out a national network of EV chargers.

A key provision in the Infrastructure Investment and Jobs Act, the National Electric Vehicle Initiative (NEVI) program will be distributing $5 billion in funds for those chargers over the next five years. Biden’s goal is to have 500,000 chargers installed across 53,000 miles of U.S. highways. Funds are allocated to each state based on a formula.

Under rules issued in February, states had an Aug. 1 deadline for submitting initial plans to the Federal Highway Administration (FHWA) for how they will use the NEVI formula funds. The FHWA set itself a Sept. 30 deadline for approving the plans, received on time from all 50 states, D.C. and Puerto Rico. (See States to Get $615 Million for EV Charging from IIJA Funds.)

For the approved plans, FHWA will be releasing formula funds for both 2022 and 2023 — a total of more than $900 million for the 35 states — according to an agency spokesperson.

The formula used for the allocations is based on the formula used for federal highway programs. Those allocations ensure each state receives 95 cents on the dollar for the taxes on gasoline and diesel their residents pay into the federal Highway Trust Fund.

Transportation Secretary Pete Buttigieg called the early approvals “an important step to build a nationwide electric vehicle charging network where finding a charge is as easy as locating a gas station.”

“Making electric vehicle charging accessible to all Americans is critical to achieving a transportation sector that improves our environment and lessens our dependence on oil and gas,” Energy Secretary Jennifer Granholm said. The states with approved plans “now have the green light to build their pieces of the national charging network to ensure drivers can spend less on transportation costs while commuting confidently by charging along the way.”

For this initial round of funding, states were required to identify key “alternative fueling corridors” (AFCs) — major state and interstate highways — where EV charging stations could be located every 50 miles, within 1 mile of the designated AFCs.

For example, Maryland’s plan, which won early approval, identified 502 “optimal” locations where it might install charging stations over the next five years, using its NEVI funding, although not all the sites are within 1 mile of the state’s AFCs.

FHWA also released additional technical guidelines in June for the charging stations to be installed with NEVI funds. Each station must include four 150-kW DC fast-charging ports, so multiple vehicles can charge at the same time. The stations must also be operating 97% of the time and must be able to accept all debit and credit cards without requiring any special memberships. (See Biden Administration to Order EV Charging Standards.)

Acting FHWA Administrator Stephanie Pollack said the early approvals reflected “the commitment of state leaders who worked hard to develop EV charging networks that work for their residents.”

The remaining plans are being reviewed and will be approved by Sept. 30, if not before, Pollack said. Under the IIJA, additional rounds of NEVI funding will require states to regularly update their plans and submit them to FHWA.

Challenges Ahead 

Plan approvals also mean that states will be able to reimburse themselves for the expenses incurred for developing their plans, according to a statement from the Department of Energy. The NEVI funds can be used for a range of projects “directly related to the charging of a vehicle,” such as the upgrade of existing charging stations, the construction of new stations, and stations’ operations and maintenance, the department said.

Other covered activities include community engagement and workforce development, EV charging station signage, and data analysis and sharing.

However, many state plans raised concerns about challenges that NEVI funds may not be able to immediately solve. (See States File Plans on Deadline for Federal EV Charging Funds.)

Several states were uncertain whether their electric systems would be able to interconnect and integrate multiple charging stations, each with the four 150-kW DC fast charging ports called for in the NEVI guidelines.

“Upgrades needed to both the line and load side to meet this increased demand could be extremely costly, especially in areas where the infrastructure may be limited,” Maryland said in its plan. The state is assuming that installation costs to be covered with federal funds could include system upgrades as needed.

Maine’s proposed solution to the problem, laid out in its now approved plan, is a staged approach. The initial stage would see the state install charging stations with four 150-kW ports at high-traffic sites, mostly in the southern part of the state. Medium- and lower-traffic sites in the middle and northern regions will only get two 150-kW chargers, at least to start.

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MISO Board Week Briefs: Sept. 12-15, 2022

High employee turnover concerns leadership

MINNEAPOLIS — Employee churn has MISO tracking its highest-ever rate, with 130 staff exits expected by the end of the year.

“At the current pace, MISO’s year-end turnover will be between 12% [and] 13%, reflecting the highest level of regrettable turnover in MISO’s history,” MISO said in a Board Week presentation.

The grid operator said every departing employee “creates a compounding challenge based on the current labor market,” where it increases the offered salary to attract applicants and grants equity raises to existing staff to avoid triggering more exits.

Allegra Nottage, vice president of human resources, said Thursday she doesn’t expect turnover to slow in the energy industry anytime soon and said MISO’s current level of resignations is “unsustainable.”

“The unfortunate side of having a talented work force is that it becomes a recruiting pool” for other companies, Nottage said.

She said it’s difficult for MISO to compete with 30% pay increases offered by other employers and said market rates for jobs are changing on a “day-to-day basis.”

The RTO is about $6 million over budget this year due almost exclusively to higher salaries and benefits. It has spent nearly $170 million, higher than its budgeted $164 million in base expenses.

MISO director Barbara Krumsiek called the presentation unusual for an open meeting but “so necessary.”

“In many ways, we’re chasing a moving target,” she said.

2023 Budget Contains Salary Hikes

CFO Melissa Brown said MISO expects to spend $373 million in its 2023 budget, split among base operating expenses ($310 million), project investments ($37 million) and other operating expenses ($26 million).

Base operating expenses are up about 10% over 2022 due to retaining and recruiting staff and inflationary pressures on salaries, Brown said.

“MISO is a people-heavy group. That’s what drives us … Approximately 70% of our budgets is salaries,” Brown told the Advisory Committee Wednesday. She said the RTO doesn’t maintain an extraordinary amount of infrastructure but values staff’s brain power and creativity.

The grid operator plans to increase staff in 2023 to address its long-range transmission planning, processing its record generation interconnection queue, and preparing operations for a transformed generation fleet.

MISO is keeping its membership rate unchanged in 2023, maintaining the $0.45/MWh tariff revenue rate it has had in place since 2021.

“There have been some ups and downs in our budget this year, but we’re ultimately proposing a flat rate,” Brown said.

Board Will Remain Same in 2023

The board will likely look the same into 2023, with MISO advancing current board members Todd Raba, Barbara Krumsiek and H.B. “Trip” Doggett for reelection to three-year terms.

Staff counsel Andre Porter said electronic voting will soon be opened to its membership.

The monthlong board elections require a minimum 25% participation rate among the nearly 140 voting-eligible members to achieve quorum. Members can vote for, against or abstain from selecting any of the candidates. Candidates must earn a majority of supportive quorum votes to be installed.

The board also unanimously approved the membership applications of Dallas-based Leeward Renewable Energy; Steelhead Americas, a subsidiary of Danish wind turbine manufacturer Vestas; Crayhill Renewables, a Nashville-based renewables affiliate of Crayhill Capital Management; and Chicago-based solar developer Nexamp, Inc.

New Market Platform Has 2024 Finish

MISO’s market platform replacement is poised for a late 2024 finish and has not been meaningfully affected by some delays that have cropped up.

Chief Digital Officer Todd Ramey said during a Tuesday Technology Committee meeting of the board that MISO and its General Electric vendor hope to complete factory acceptance testing and delivery of the new day-ahead clearing engine by the end of the year. Staff then aims to get the clearing engine into production next year and discontinue its current mechanism by the third quarter of 2023.

The real-time market-clearing engine will not be replaced until 2025.

The grid operator began the process of swapping out its legacy market platform for the new, modular platform in 2017. The project has been affected this year by staff turnover and supply chain impediments, Ramey said.

That has forced MISO to extend parallel operations of the legacy and new modeling tools.  Ramey said that undertaking will be completed by the end of this year instead of the third quarter as originally planned.

However, staff will roll out a new energy management system (EMS) for parallel operations sometime before the end of the year, as scheduled. MISO operators use the EMS to monitor and analyze the bulk electric system and fulfill the RTO’s responsibilities to NERC as reliability coordinator and balancing authority.

MISO has allocated a little more than $20 million this year for the platform replacement. Next year, it anticipates spending roughly $15 million. The full market platform replacement is expected to cost about $141 million.

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New York PSC Raises Champlain Hudson Debt Ceiling to $6B

The New York Public Service Commission on Thursday authorized developers of the Champlain Hudson Power Express to take on up to $6 billion in debt to build the transmission line from Quebec to New York City.

The PSC had authorized up to $4.5 billion in debt for the project in February, but the developers asked for an increase just four months later, citing nationwide economic conditions that had changed substantially since they initially submitted their request in November 2020.

The commission also authorized the developers to exercise the rights they have negotiated with the municipalities that the line will cross in the overland portion of its 340-mile route.

CHPE is considered important to New York state’s climate goals, as it will bring as much as 1.25 GW of power generated by zero-emission Canadian hydroelectric plants to New York City, which now relies almost entirely on fossil-generated electricity.

The underground HVDC line was proposed in February 2010 and authorized by the PSC in April 2013.

The company behind the project — a partnership between Hydro-Quebec and Transmission Developers Inc. — says the regulatory review since then has taken longer than it expected. On Aug. 31, it announced it was pushing back the anticipated in-service date from fall 2025 to spring 2026 because of the length of the process, as well as supply-chain constraints for key components.

The developers said Thursday that construction will begin later this year.

The PSC vote was not unanimous. Commissioners Diane Burman and John Howard both voted against the financing petition. Commissioners David Valesky and John Maggiore voted in favor of the measure, but their support was not unqualified.

Burman was concerned about giving the developers the ability to change lenders and modify the amount and terms of the financing without prior approval by the PSC.

Howard said he is opposed not to the project but to the way it is being paid for. “There’s nothing inherently objectionable, and I find many things actually very positive about the concept of … construction of the CHPE line. What I have a problem with, again, consistently, is how we pay for it, making all ratepayers pay, and sort of abandoning the broad and long-held concept of beneficiaries pay.”

Valesky said he shared Burman’s and Howard’s concerns. “However, I did come to a different conclusion,” he said. “I did support that item in February, and I will be supporting this item today.”

Maggiore said his concern that the higher debt limit might impact ratepayers was satisfied and his other concerns with CHPE are ancillary to financing, so it was not appropriate for him to raise them at Thursday’s meeting.

The project has long been contentious. Some opponents worry about the potential for environmental damage caused by construction of the line, 60% of which will run beneath Lake Champlain and the Hudson River.

Others say the net environmental benefit of hydropower is overstated and, in the case of Hydro-Quebec’s vast hydropower infrastructure, harmful to indigenous people.

But project developers have also marshaled support from environmentalists and indigenous communities.

In a news release announcing the PSC’s decision Thursday, Chair Rory Christian said: “In addition to ensuring the safety and reliability of the transmission system, the Champlain Hudson project, and others being developed, will play a key role in our comprehensive plan to modernize our state’s transmission system so that it delivers clean energy to all New Yorkers, while advancing our climate goals and creating clean-energy jobs.”

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NYISO Proposes 10-kW Min. Capability Req for DERs in Aggregations

NYISO on Monday shared a proposal to set a 10-kW minimum capability requirement for individual distributed energy resources participating in aggregations, which it said would help support their integration in its markets.

The ISO is developing new software and internal procedures to comply with FERC Order 2222, which did not set any minimum requirements for DER deployment. But NYISO said the work generated more overhead costs to interconnect DERs.

NYISO said that its proposal, presented to the Installed Capacity Working Group, would help staff save time reviewing aggregations for interconnection: reviewing 100 1-kW DERs in an aggregation would take significantly more time than reviewing an aggregation of 10 10-kW DERs, though both would have the exact same capacity.

The ISO said the minimum requirement would enable aggregations to remain flexible and still deliver their services in a reliable and timely manner, but also allow staff to catch up on the compliance work.

It also said it would consider lowering the minimum after market deployment has been underway for some time and it has gained experience managing DER aggregations.

Stakeholders attending the meeting expressed concern about the proposal, saying it could disenfranchise entire residential market classes from being included in aggregations, and that it would not supply the experience NYISO is looking for because most initial aggregation participants will be on a larger scale (20 to 40 kW).

NYISO intends to file the proposal with FERC toward the end of 2022. Comments or questions should be sent to DER_Feedback@nyiso.com.

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University of California System Pursues Hydrogen Blending

California took tentative steps toward mixing hydrogen with natural gas this week with a large grant to the University of California, Los Angeles, to study the process and an announcement by San Diego Gas & Electric that it is seeking to establish a pilot project at the University of California, San Diego (NYSE:SRE), to blend the fuels in an existing gas system.

The California Energy Commission on Wednesday awarded UCLA nearly $5.7 million to “assess the feasibility and safety of targeted hydrogen blending in gas infrastructure to support decarbonization.” The project will study hydrogen’s effects on materials and components of the gas system under different blend levels and develop risk models.

“Blending pipeline gas with hydrogen is still in the early stages of development and use,” UC researchers wrote in their grant application. The UCLA research aims to “reduce the gap in critical knowledge to help [investor-owned gas utilities] introduce hydrogen in the current California gas pipeline network.”

The benefits could include production and storage of green hydrogen at solar arrays and wind farms, using renewable energy that might otherwise be curtailed, and decentralization of the state’s gas system, researchers said.

“The current California gas pipeline system is dependent on a few key pipelines, and a single point of failure can have catastrophic consequences” they said. “The decentralization of energy production will greatly improve the resiliency of the pipeline energy network infrastructure.”

The CEC approved the grant without discussion as part of its consent agenda.

On Monday, SDG&E said it had submitted a proposal to the California Public Utilities Commission for a demonstration project at UC San Diego to study the feasibility of injecting up to 20% hydrogen into plastic natural gas pipes.

“An isolated section of a gas line serving a UC San Diego apartment complex would use hydrogen-blended gas for common building equipment such as boilers and water heaters,” the utility said in a news release. “Hydrogen used in this study would be produced on site via a dedicated, grid-connected electrolyzer. The results of the study would help inform the development of a renewable hydrogen blending standard for California.”

SDG&E CEO Caroline Winn said in the news release that “achieving the state’s climate goals, including reaching carbon neutrality by 2045, will require a broad range of clean energy technologies. That’s why we are investing in the research, development and demonstration of emerging hydrogen innovations that have the potential to be a game changer.”

The utility said the project would fulfill a recommendation of the “Hydrogen Blending Impacts Study” commissioned by the CPUC and performed by researchers at the University of California, Riverside, that called for additional examination of hydrogen blending to ensure its safety, including demonstration projects under controlled, real-world circumstances.

The study found that hydrogen blends of up to 5% in the natural gas stream are relatively safe but that blending more hydrogen in gas pipelines can embrittle steel pipes and raise the risk of leaks. Hydrogen blends of more than 20% carry a higher risk of permeating plastic pipes, increasing the risk of ignition outside the pipeline, it said. (See Study Finds Adding More Hydrogen to Natural Gas Raises Risks.)

“The main concern with pipelines comprising of polyethylene is permeability to hydrogen, which may result in leakage of gaseous hydrogen,” it said. About 65% of distribution pipelines are made of plastics and 35% are steel, it noted.

SDG&E cited a similar demonstration project in England that found that injecting up to 20% hydrogen into a university’s natural gas network had not affected pipes or gas appliances.

UC San Diego would welcome the pilot project, Chancellor Pradeep Khosla said in the news release.

“Sustainability and public service have been a key part of the university since its founding,” Kholsa said. “That’s why we are helping to support California’s decarbonization efforts through this pilot project exploring the economical and safe use of blended hydrogen.”

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NERC RSTC Briefs: Sept. 13-14, 2022

Committee Meets for Second Time in over 2 Years

In its first in-person meeting since the start of the COVID-19 pandemic — and its second ever — NERC’s Reliability and Security Technical Committee (RSTC) gathered at the offices of the Midwest Reliability Organization in St. Paul, Minn., this week to advance action on a number of NERC’s projects.

Before Tuesday, the RSTC’s only face-to-face meeting was its first, held in Atlanta more than two and a half years ago, where the group primarily discussed its plans for taking over the business of the now defunct Operations, Planning and Critical Infrastructure Protection committees. (See RSTC Tackles Organization Issues in First Meeting.) On the first day of this week’s meeting, Chair Greg Ford, of Georgia System Operations, reflected that the committee “has come a long way” since it first came together in 2020.

“I think at that point, and over the next year or so, we were still the OC, PC and CIPC, just in a room together. And today based on the discussion it was clear to me that we have become an RSTC,” Ford said. “We’re really thinking across boundaries; we’re trying to bring a cyber connection to everything we do … [which] is what the board asked us to do. We may not be perfect, but we’re certainly getting there.”

The RSTC’s next meeting, which will be held virtually, is scheduled for Dec. 6-7. For next year’s meetings, two will be fully virtual, while the other two in March and September are planned to be in person. The locations for those meetings have not been determined yet; NERC’s Tina Buzzard said the possible cities include Phoenix, Dallas and San Diego.

SPIDER Documents Approved

Three reports from NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group came before the committee this week, with members approving all three.

First was the NERC Reliability Standards Review, which SPIDER Chair Shayan Rizvi described as a “foundation” for revising the organization’s reliability standards to account for the recent rapid growth of distributed energy resources on the bulk power system, which is expected to continue in the next few years. Work on the project began in 2020 and involved the review of 78 standards over nearly two years.

SPIDER ultimately determined that 54 standards are not likely to need action of any kind to ensure they remain relevant in light of the spread of DERs. The group recommended revising 11 standards across six families: Resource and Demand Balancing; Emergency Preparedness and Operations; Facilities Design, Connections and Maintenance; Modeling, Data and Analysis; Protection and Control; and Transmission Operations (TOP). Eleven standards were recommended for supplemental reliability guidelines — in the same categories except for TOP — and two are being considered for potential future revision, though no action is needed at this time.

The group also submitted a white paper to the committee concerning the impacts of DERs on undervoltage load shedding (UVLS) programs, which found that DERs “are not expected to significantly affect” such systems. Still, it recommended that utilities ensure resources are modeled appropriately in UVLS studies, as well as a technical report on simulating beyond positive sequence conditions using current industry tools.

The group’s representatives concluded by soliciting volunteers from the RSTC to review another white paper on the impact of battery energy storage systems on DER modeling.

LTRA Previewed

NERC staff working on the ERO’s Long-Term Reliability Assessment (LTRA) said they expect a draft version of the document to be ready for the RSTC’s review by Sept. 26, with a release scheduled by Dec. 15. The LTRA is released every year to assess North American resource adequacy in the next decade and to identify trends that could affect grid reliability and security.

Anna Lafoyiannis, chair of the Reliability Assessment Subcommittee, told attendees that the goal of this year’s assessment is “to be a little bit more concise” than in previous years and “focus on what are the most critical emerging risks … for policymakers and decision-making.” She said the report will focus on two main themes: resource adequacy and energy sufficiency, including capacity shortfalls in Ontario, MISO and California; and extreme weather risks involving insufficient flexible generation in Texas and the Northwest, along with issues with the natural gas infrastructure in New England and other areas.

In response to questions from committee members, Lafoyiannis confirmed that the LTRA will “include a list of recommendations” for policymakers and industry. She added that the RAS is hoping for feedback from the RSTC about whether “those recommendations [are] the right recommendations,” and whether they “are doable and the right priority.”

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Judge Approves Brazos Chapter 11 Exit Plan

A U.S. bankruptcy judge on Tuesday conditionally approved Brazos Electric Power Cooperative’s disclosure statement about its deal with ERCOT and its proposed exit plan from Chapter 11 bankruptcy.

The decision of Chief Judge David Jones, of the U.S. Bankruptcy Court for Southern Texas, allows Brazos — which declared bankruptcy in the wake of the February 2021 winter storm after being billed for $2.1 billion in wholesale prices — to begin soliciting votes from creditors and settle its dispute with ERCOT. The grid operator later revised the amount due to the market to $1.89 billion (21-30725).

Under the terms of the settlement, ERCOT will receive $1.4 billion. Brazos will pay $1.15 billion up front and then make annual payments to ERCOT of $13.8 million for 12 years. The cooperative will also contribute about $116 million from the sale of its generation assets to fund payments through ERCOT for market participants still short from market transactions during the week of the storm. (See ERCOT, Brazos Reach Agreement in Bankruptcy Case.)

Brazos agreed to sell its generation assets and transition to a transmission and distribution utility. It owns about 4 GW of natural gas-fired capacity.

Under the agreement, Cliff Karnei, Brazos’ general manager since 1997, and three other members of the cooperative’s senior management will leave their jobs by March 2023. In addition, Karnei and two others will be barred from working for any ERCOT market participant if they’re acting as a financial counterparty to the grid operator.

The votes and any objections are due Oct. 28. Another hearing has been scheduled for November to consider final approval of the settlement and the exit plan.

Brazos filed for bankruptcy in March 2021 after receiving the $2.1 billion invoice from ERCOT. The cooperative responded with a force majeure event letter and by disputing the charges. (See ERCOT’s Brazos Electric Declares Bankruptcy.)

The co-op then opened an adversary proceeding against ERCOT in August 2021, challenging the Texas Public Utility Commission’s emergency orders directing the grid operator to set prices at their $9,000/MWh limit to reflect the scarcity in the market. It sought to reduce the short-pay claim by at least $1.1 billion, the amount it attributed to ERCOT’s administrative adjustment.

The adversary proceeding trial began earlier this year but was suspended after several weeks to allow the parties to mediate the dispute. (See ERCOT, Brazos Agree to Mediation in Dispute.)

Gregory Power to Full-time Ops

Also on Tuesday, NRG Energy (NYSE:NRG) notified ERCOT that it plans to return its Gregory Power Partners gas-fired facility to fulltime operations, effective Oct. 1.

The company submitted a notification of change of generation resource designation for the three units and their 365 MW of capacity. The plant, located outside Corpus Christi, had been on seasonal operations from May through December. It went online in 2002.

The plant was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. NRG returned the facility to seasonal operations in 2019. (See ERCOT Approves Seasonal Plan for NRG Cogen Units.)

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Gordon van Welie Stares down Another Winter in Charge of ISO-NE

BURLINGTON, Vt. — Gordon van Welie is facing another winter full of worry as the head of ISO-NE, tasked with keeping the lights on amid the possibility that extreme weather will threaten a grid that’s straining to catch up to clean energy policy in the region.

In an interview with RTO Insider after a FERC meeting in Vermont that brought all sides of the New England energy sector into a room to talk about the region’s winter issues, van Welie shared his views on the clash between reliability and the clean energy transition. (See FERC Comes to Vermont and Leaves with a New England-sized Headache.)

“The problem is, we should absolutely build all the renewables as fast as we possibly can, hook them up to the system and then let the stuff go that we don’t want. But we’re doing it the other way around,” van Welie said. “We’re shutting stuff down before the new stuff’s built.”

The clean energy transition isn’t being conducted with “completely rational behavior” right now, he said. His call has been for a “deliberate, measured” and incremental move to get away from fossil fuels.

“That’s not the way things are playing out at the moment.”

In his more than 20 years as head of the grid operator, van Welie said he’s developed a keen understanding of the economic theories underpinning the region’s markets; the regulatory paradigms; and the politics that shape his job. It’s a far cry from his background as an engineer working on smart grid technology. And the problems he’s trying to solve now are bigger and thornier than ever.

“Sometimes I feel like we’re trying to thread a rope through a needle in this region. It’s very hard to find the solution that is going to satisfy everyone,” van Welie said.

Last winter, van Welie and his staff launched a public awareness campaign, using media interviews to warn about the thin margins on New England’s grid in the winter in the case of extended cold weather. ISO-NE is planning to do so again this year, despite accusations from some critics that the as-of-yet unfulfilled warnings of rolling outages are “fear-mongering.” (See ISO-NE: New England Could Face Load Shed in Cold Snaps.)

“What would you do in our shoes?” van Welie asked. “You know there’s a risk, and if it goes bad, it’s going to impact 15 million people. Do you hide it and say, ‘We’ll deal with it when it comes?’ Or do you talk about it and say, ‘There’s a problem here that we need society to be aware of?’”

The grid operator is planning a few changes to its strategy this year, including to emphasize that under most circumstances, it still won’t have to dip into the most extreme operating procedures involving load shed. ISO-NE is also doing a tabletop exercise with utilities to run through the scenario of an energy shortfall.

“It’s not just about CYA [covering your ass]. It’s so that people know and can take precautions,” van Welie said. “Part of what we’re saying is that we think we’re short. And so that’s a problem for society. And I’d rather have society know that in advance than for them to find out after the fact, and say, ‘Why didn’t you tell us? We could have done something.’”

No Plans to Step down

The tenuous state of the region’s grid means that van Welie, who joined the organization in 2000 and was named its president and CEO in 2001, isn’t ready to start thinking about retiring.

“The thing I would like to do is to try and leave behind something that’s in decent shape; set it up on a solid foundation,” he said. “I don’t feel like we’re on a solid foundation now.”

Last year, van Welie laid out a four “pillar” plan to support the clean energy transition: substantial amounts of clean energy, balancing resources, energy adequacy and robust transmission.

Using a traffic light indicator to gauge progress, he said transmission is green for now, renewables and balancing resources are yellow, and energy adequacy is red.

“I’d like to get things back to yellows and greens, as opposed to reds,” van Welie said. “It’s going to take time. We might, 10 years from now, be still having the same conversation.”

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Monitor Critiques MISO’s Commitment Usage During Summer

MINNEAPOLIS — MISO presided over reliable operations at higher prices this summer, although its Independent Market Monitor said it is concerned about the RTO’s reliance on out-of-market commitments to maintain reliability.

The difference of opinion arose in Tuesday’s session of the MISO Board of Directors’ Markets Committee during MISO’s quarterly Board Week.

The RTO only called a couple of maximum generation alerts this summer during June’s early heat. That same month, MISO registered the summer’s high systemwide peak at 121 GW on June 21, topping a projected 116-GW monthly peak. The system peaked at 119 GW in July and at 112 GW in August, below expectations of 124 and 122 GW, respectively.

The operations performance came with dramatically higher costs because of soaring natural gas prices, supply chain issues for coal and slightly higher load as the COVID-19 pandemic precautions ease.

The Monitor’s David Patton said all-in summer energy prices doubled year-over-year to about $75/MWh. He said that day-ahead and real-time congestion costs doubled over last summer to more than $750 million, primarily in the footprint’s northern region where abundant wind generation struggles to flow out of the region.

Are Units Being Overcommitted? 

Patton also said MISO operators continued to overcommit generation during the summer. The grid operator said it has had a commitment success rate of about 96% during the season, an indication that it regards most of its commitments as optimal or necessary.

“MISO grades itself as an A+, but at this point we think it’s more a C+. … There’s a disconnect,” Patton said.

Patton estimated that the RTO spent about $80 million in revenue sufficiency guarantee (RSG) payments to resources during the summer. He said only about 10% of the RSG payments are necessary to dilute risk.

MISO uses overly conservative criteria to justify making additional commitments, Patton said. He asked staff to support their commitments with a sharper risk analysis that could avoid excessive commitments. He said the RTO’s operators are “squelching” the markets’ ability to incent nimble generation.

“Ultimately, we want the markets to work,” he said. “We want prices to rise under tight conditions so that fast-start resources are rewarded for the reliability they provide.”

“It is our goal to never make an out-of-market commitment. The reality is we have to make out-of-market commitments,” MISO President Clair Moeller said, adding that exact load amounts materialize in real-time, not day ahead.

Renuka Chatterjee, the grid operator’s vice president of operations, called Patton’s criticism a “healthy tension” between MISO and its Monitor. Patton added that to its credit, the RTO’s leadership is open to discussing the problem further and collaborating on a solution.

MISO, which has begun to track its solar output peaks, said it recorded an all-time high of 2.2 GW on Aug. 31, accounting for 3% of load. Its all-time wind peak remains the 23.6 GW generated on Jan. 18.