Calling the rapid growth of inverter-based resources on the bulk power system “one of the most significant drivers of grid transformation and … a high risk to BPS [bulk power system] reliability,” NERC on Wednesday published a strategy document outlining current and future work needed to help the organization address potential pitfalls of the new generation fleet.
NERC considers inverter-based resources (IBRs) to be generation types such as solar photovoltaic and wind facilities that “are asynchronously connected to the grid and are either completely or partially interfaced with the BPS through power electronics,” according to the organization’s draft reliability guideline for IBRs. Concerns about these resources have grown in part because of events like the Blue Cut fire in 2016, when erroneous tripping of solar generation caused the loss of 1,200 MW of output in Southern California.
Speaking at this week’s meeting of NERC’s Reliability and Security Technical Committee (RSTC), Ryan Quint, NERC’s director of engineering and security integration, explained that the organization has been working to address the risks of IBRs through initiatives such as the Inverter-based Resources Performance Subcommittee (IRPS). However, because there are “a lot of moving parts” to the issue, NERC felt it necessary to formalize an overall approach.
“We recognized [that] we needed to have a solidified, codified strategy to help bring things together, and we’ve heard that comment a couple of times here. So … this is that strategy,” Quint said. He added that a similar strategy for distributed energy resources — generation types that produce electricity but are not included in the bulk power system, such as rooftop solar panels and behind-the-meter batteries — “is in the works and will hopefully be coming at the December RSTC meeting.”
Report Outlines Risk Mitigation Approach
The Inverter-Based Resource Strategy document outlines a risk mitigation framework with four key tenets: risk analysis, interconnection process improvements, best practices and education, and regulatory enhancements.
NERC’s IBR risk mitigation strategy | NERC
Risk analysis includes NERC’s monitoring and awareness tools such as the event analysis process, disturbance reports, alerts and lessons learned reports. Interconnection process improvements include enhanced interconnection requirements, updated generator interconnection procedures and agreements, and the Institute of Electrical and Electronics Engineers’ 2800-2022 standard, which sets “uniform technical minimum requirements for the interconnection, capability and lifetime performance” of grid-connected IBRs.
The last two sections involve NERC’s reliability standard and reliability guideline development processes, along with industry outreach and engagement. NERC observed in the report that “reliability guidelines related to IBRs are the most commonly downloaded documents on [its] website” and that webinars on inverter-related topics “often have over 1,000 participants dialing in.”
NERC has planned several activities to support the strategy, such as issuing a Level 3 alert that “would enable industry action while reliability standards are being developed.” The organization is also considering updating its definition of the bulk electric system, which was last revised in 2014, to better account for IBRs.
Finally, the IBR document includes a series of IBR-related milestones to be presented to the RSTC at future meetings. These include standard authorization requests to begin projects aimed at revising NERC’s current standards — three of which are planned to go before the committee by the first quarter of 2023 — a set of reliability guidelines to be completed by the end of 2022, and white papers on IBR reliability issues and commissioning best practices to be submitted by the middle of next year.
MINNEAPOLIS — MISO’s mid-September Board Week centered on the tectonic industry shift underway as the RTO plans to string more transmission lines across the footprint to bring record amounts of new capacity online and avert reliability crises.
Since the MISO Board of Directors’ last public meeting in June, the grid operator has opened its wholesale markets to full energy storage participation, approved more than $10 billion in long-range transmission lines, obtained FERC permission to conduct a seasonal capacity auction, and is preparing to study enough proposed capacity entering its generator interconnection queue to cover its current summer peak.
Transition a ‘Double Whammy’ Risk
MISO’s vice president of operations, Renuka Chatterjee, told directors during a Tuesday session that the footprint’s fleet evolution is having a “double whammy impact” on the RTO’s risk profile. She said increased renewable energy makes the grid more dependent on forecasting while baseload generation retirements hinder its ability to absorb their intermittency.
Chatterjee said staff are working toward creating automated daily risk assessments that combine the interplay between solar and wind forecasts, load expectations, fossil fuel availability, net scheduled interchanges and transmission congestion. She said MISO will eventually introduce tailored daily reserve margin requirements.
The grid operator has committed to reviewing operating days that fall outside of historical norms to see if it needs to change its reliability preparations or new market products, Chatterjee said.
Jessica Lucas, executive director of system operations, said about 70% of MISO’s daily energy supply remains sourced from thermal generation, a concern before the national rail strike was apparently averted.
During the Thursday board meeting, CEO John Bear said the organization paid attention to CAISO operations during its early September heatwave. He said MISO trails California in the energy transition and noted that CAISO struggled with a lack of “controllable, long-duration resources” to weather the heat.
“We’ve got a good sense of where we need to go and how we need to get there,” Bear said.
More Tx to Yield Interconnections
Vice President of System Planning Aubrey Johnson said MISO expected more than 1,000 new generator interconnection requests, representing about 120 GW, for the 2022 cycle when the application window closed Thursday. He said it will be the third straight year staff have processed a record number of applications, each bigger than the previous.
Since 2014, MISO has received 329 GW of interconnection requests; 52 GW have progressed through to the generation interconnection agreement (GIA) stage that allows grid access. The grid operator currently has about 124 GW in the queue but has seen interconnection customers withdraw 153 GW over the past eight years. It hopes its recent transmission planning activity will drive up interconnection numbers and limit withdrawals.
“The last few years were relatively flat in terms generation additions and subtractions,” Johnson told board members during a Tuesday System Planning Committee meeting. “… What we’re seeing is an accelerated change in the resource mix, and it’s calling on us to do things differently.”
Transmission upgrade costs and dropouts for interconnections by region for the 2016-2020 queue cycles | MISO
MISO projects it will have 346 GW of nameplate capacity by 2042, but just under 200 GW in accredited capacity. The RTO currently has 201 GW in nameplate capacity and 173 GW in accredited capacity.
The grid operator is keenly aware that soaring network upgrade costs in parts of its footprint are hindering more generation additions. Interconnection projects tend to complete the queue when their associated transmission investments for interconnections are at or below $125/kW, Johnson said. However, upgrade costs have neared $1,000/kW or beyond in MISO’s West and South planning regions, eight times what investors are comfortable putting forward, he said.
“If you’re looking to interconnect in the Central region, come on in. The water’s warm,” Johnson said. “But if you’re looking to interconnect in the West or even the South, that’s a different matter.”
Johnson said transmission projects stemming from MISO’s Joint Targeted Interconnection Queue study with SPP should help yield more GIAs.
He said MISO is also immersed in identifying a second set of Midwestern transmission projects under its four-part long-range transmission plan (LRTP). The RTO obtained board approval in late July on the first, $10.4 billion set of LRTP projects in MISO Midwest.
“July 25 was a great day, but we’re going to continue to press on and define and develop what the next stage of projects is going to be … Much like football, we thought about the win for 24 hours, and then we moved on,” Johnson said.
The grid operator released the first competitive request for proposals stemming from the LRTP, a 345-kV line from an Indiana substation to the Michigan border. Proposals are due Jan. 11. The grid operator plans to release a new RFP for a different LRTP project about every three months and administer simultaneous bid evaluations.
The grid operator characterized wholesale storage activity as nominal so far. But its interconnection queue currently has more than 13 GW of standalone battery storage as part of more than 150 projects in varying stages of development. That doesn’t include the queue’s hybrid generation projects, which usually pair renewable energy with a storage resource.
Unease over MISO Support for Gas Plant
Clean Grid Alliance’s Beth Soholt told board members that MISO has recently and unacceptably favored natural gas generation’s development over other resource types in bring new generation online. She said staff presentations following capacity shortages during the 2022-23 planning year advocated new gas-fired capacity, despite its fuel-neutral posture.
Soholt pointed to the RTO’s July letter to the Rural Utilities Service (RUS) in support of a loan for the proposed, $700 million gas-fired Nemadji Trail Energy Center in Superior, Wis., which would be jointly owned by Dairyland Power Cooperative and two Minnesota utilities.
In the letter, MISO said it was concerned about looming generation shortfalls and asked RUS to “consider grid reliability” and Nemadji Trail Energy Center’s role in the footprint’s resource adequacy.
“While MISO is both fuel- and technology-neutral, MISO needs to help ensure the best options to provide needed resource capabilities and attributes are available to bridge the gap between electrical baseload retirements and replacement capabilities and attributes,” Deputy General Counsel Kristina Tridico wrote.
Tridico said “the retirement of generation plants is occurring far faster than new energy sources with equivalent attributes, whatever the fuel source, can be developed, constructed and brought online.”
“While the letter was very careful to color within the lines of grid reliability, I’ve never seen MISO send a letter in a specific docket advocating for a specific new resource. This is not appropriate,” Soholt said during a public comment period Tuesday. “MISO has always said it is fuel and technology neutral, but a different message is coming through in the last several months of MISO messaging and presentations.”
Soholt said, “at the end of the day, there are many solutions to MISO’s resource adequacy challenges, and the work is not done yet.”
She urged MISO to not encourage members to rush headlong into natural gas solutions before it assesses battery storage’s flexible attributes in its market portfolio.
MISO executives didn’t respond to Soholt’s criticisms in real time during Board Week. In a later statement to RTO Insider, the grid operator said it believes the letter speaks for itself.
NV Energy has filed a $348 million transportation electrification plan, which includes funding for electric vehicle purchase incentives, new charger installations and a managed charging program.
The company filed the plan with the Public Utilities Commission of Nevada (PUCN) on Sept. 1 as part of a proposed amendment to its 2021 integrated resource plan. The commission has 165 days to issue an order on whether to accept, modify or reject the plan.
NV Energy’s proposed transportation electrification plan is a follow-up to the company’s Economic Recovery Transportation Electrification Plan (ERTEP), filed in September 2021. The $100 million plan included a network of EV charging sites throughout the state. (See NV Energy Gets Green Light for $100M EV Charger Plan.)
Both plans are required by Senate Bill 448 from the state’s 2021 legislative session.
The proposed transportation electrification plan covers 2023 and 2024. It allocates $348 million, with 45% going to personal vehicle programs and 42% going to commercial vehicle programs. The remainder will go toward education, grid integration, program management and contingency.
NV Energy acknowledged in its filing that $348 million is a “significant” amount. The money will potentially be available as a match in federal funding opportunities.
“This plan represents an intentionally significant investment to set the foundation and maximize Inflation Reduction Act funding,” the filing said. “Future plans will match future needs.”
And in written testimony accompanying the plan, Marie Steele, NV Energy’s vice president of electrification and energy services, addressed the question of whether the proposed EV infrastructure would put additional stress on the utility’s systems.
“The new load from electric vehicles is coming, whether the companies and the commission plan for it or not, and studies show unmanaged charging can occur coincident to peak.”
Personal, Commercial Programs
The plan has more than a dozen programs for personal and commercial EVs.
On the personal vehicle side, the plan proposes a $5,000 rebate to low-income residents who buy an EV with a manufacturer’s suggested retail price of up to $40,000. NV Energy has allocated $500,000 to the rebate program.
Another $4.7 million would go toward incentives for about 200 home charger installations. The incentives would cover 75% of the project cost, or 100% for low-income applicants.
In the proposed residential turnkey charging program, NV Energy would install and maintain home EV chargers. The program includes options for one single-port charger; two single-port chargers with battery storage; one single-port charger integrated with battery storage and rooftop solar; or a single-port charger that is vehicle-to-grid capable. The company allocated $14.8 million to the program — enough for about 240 homes.
The plan also offers a technical advisory program for residents, with services such as an EV savings calculator, dealer finder and a transportation electrification call center.
Some programs, such as the interstate corridor charging depot program and urban charging depot program, are carried over from ERTEP and expanded. There are also EV charging infrastructure programs for multifamily housing and workplaces.
A new addition to the transportation plan is a telematics program, in which equipment would be installed in residents’ gas-powered cars to analyze their driving patterns and the savings they’d realize by switching to an EV. NV Energy might focus the program on drivers for ride-hailing companies or food delivery services, or people with long commutes.
NV Energy has also proposed a telematics program for light-duty vehicles in government fleets.
Among other programs in the plan, a transit electrification grant and an electric school bus vehicle-to-grid trial that were included in ERTEP would be continued and expanded.
Managed Charging
Another piece of NV Energy’s transportation electrification plan is managed charging. Customers who participate in the plan’s EV charger programs would automatically be enrolled in managed charging, in which the utility can adjust the amount of power going to EV chargers based on the needs of the grid. Customers would be able to opt out of managed charging events.
Customers who already have EV chargers installed and meet certain criteria may receive an incentive for opting in to managed charging.
NV Energy will gather feedback from participating customers on managed charging and track load impacts. About $13 million of the plan’s funding is earmarked for managed charging.
NV Energy ran a demonstration project on managed charging in 2020 and 2021, according to the company’s filing. The project showed the technical feasibility of managing EV chargers at a workplace.
The managed charging program proposed in the plan “will expand on this foundation and provide more EV operational data for a broader spectrum of site profiles and use cases,” the company said.
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.
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,” EnergySecretary 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.
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.
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.
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.”
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 FERCOrder 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.
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.”
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.”
NERC’s IBR risk mitigation strategy | NERC