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November 19, 2024

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ERCOT Issues Low-level Alert as Heat Builds

ERCOT on Wednesday issued its third operating condition notice (OCN) since April, warning of extreme heat in several of its weather zones this weekend.

The Texas gird operator distributed the OCN, its lowest-level communication of a possible emergency condition, because it expects forecasted temperatures to exceed 103 degrees Fahrenheit in its North Central and South Central weather zones from Friday through Monday. Emergency conditions are issued when staff determine the system’s safety or reliability is compromised or threatened.

The first OCN was issued on May 3 and extended several times through May 20. A second OCN was issued for May 28-30.

AccuWeather said Wednesday Texans can expect the sweltering heat that has hung over the state since early June will stick around into next week. The weather pattern has been stuck in place for more than a week, the weather service said, allowing heat to build across the south-central U.S.

Daily temperatures have been 5-15 degrees above normal in many cities, with San Antonio setting records with consecutive 104-degree days Monday and Tuesday. Temperatures in the Dallas area are expected to reach triple digits Friday for the first time this year; the average date for Dallas’ first 100-degree day is July 1, according to an AccuWeather meteorologist.

ERCOT this week expected to break its all-time peak demand record of 74.8 GW, set in August 2019. (See ERCOT Expecting Record Demand this Week.) Demand fell short of that mark but did set June highs of 72.4 GW and 72.8 GW Monday and Tuesday, respectively. Demand Tuesday stayed above 72 GW for the three intervals ending 4-6 p.m.

The day-ahead forecast for Thursday projects a demand peak of 75.6 GW.

The ISO’s conservative operations posture had as much as 84 GW of committed capacity available Wednesday, when demand was expected to barely reach 70 GW. ERCOT apparently reduced demand by 649 MW after an explosion shut down an LNG plant near Houston.

In a blast email response to a Dallas television station that was sent to ERCOT’s media distribution list Wednesday, the grid operator said it “projects sufficient generation to meet forecasted demand.”

ERCOT expects peak demand to hit a record 77.3 GW this summer, it said in its seasonal assessment of resource adequacy released last month.

TAC Briefed on Recent Frequency Event

Staff gave ERCOT’s Technical Advisory Committee an early update on a frequency event last weekend in West Texas that momentarily knocked 2.5 GW of capacity offline.

Woody Rickerson, the ISO’s vice president of system planning and weatherization, told the committee during a Tuesday webinar that a lightning arrestor on a 345-kV line near Odessa faulted. Voltage briefly fell to 59.706 Hz before being restored to 60 Hz within two minutes.

The outage took 1.7 GW from 14 solar sites offline. Eight of the 14 solar sites also tripped offline last year in what is now called the “Odessa disturbance.” More than 1.1 GW of solar PV resources, up to 200 miles away, were affected.

Rickerson said staff has only just begun to collect data on the event as part of a full analysis required by NERC. He said preliminary results indicate a possible problem with the solar facilities’ inverter settings. Rickerson ­will discuss the event Friday with a task force addressing the growing dominance of inverter-based resources and also plans to bring a more detailed report to TAC’s June 27 meeting.

The committee also discussed its final comments to ERCOT’s proposed methodology for approving and denying planned generation maintenance outages in advance of the Board of Directors’ June 21 meeting. TAC Chair Clif Lange said he will share with directors the committee’s the “full range” of concerns with the methodology and why they exist.

Members and staff shared their respective comments on the maximum daily resource planned outage capacity calculation, the key feature in ERCOT’s plan to evaluate outage requests. TAC believes the calculation limits outages when compared to history and that a 10% growth rate for renewable resources is too low. Staff have said they want as much capacity and flexibility as possible for planned outages while maintaining reliability.

The board in April granted staff’s appeal of a revised nodal protocol revision request (NPRR1108) that gives the grid operator the authority to review, coordinate and approve or deny all planned generation maintenance outages. Stakeholders earlier rejected staff’s version of the measure, unanimously approving an NPRR as amended by several joint commenters. (See ERCOT Board of Directors Briefs: April 28, 2022.)

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NERC RSTC Briefs: June 8-9, 2022

Committee to Meet Face-to-face in September

NERC’s Reliability and Security Technical Committee (RSTC) plans to hold its next meeting in person in Atlanta, though the venue has not been chosen yet, committee leaders told attendees at its June meeting held via conference call on Wednesday and Thursday.

RSTC members have not met face-to-face since the committee’s first meeting, a short gathering in Atlanta in March 2020 at which attendees mainly discussed how to take over the business of the now defunct Planning, Operating and Critical Infrastructure Protection committees. (See RSTC Tackles Organization Issues in First Meeting.) The committee had planned to hold its first meeting of 2022 in person, but it was converted to a virtual gathering before the December conference call.

In that meeting, Secretary Stephen Crutchfield did not mention the change specifically but said the September gathering was “the only one [for which] we had a hotel booked currently.” On Thursday, Crutchfield said the meeting has changed from that location, the Grand Hyatt Atlanta in Buckhead, for unspecified reasons; however, he said NERC staff are “working on getting a new location” and that the committee does not intend to convert it to a conference call again.

December’s meeting is still being envisioned as virtual, but on Thursday, Edison Elizeh of the Bonneville Power Administration suggested that this gathering be held in person too, in light of the decision to cancel the physical meeting in April. Crutchfield said the RSTC executive committee plans to consider this at its upcoming meeting next Tuesday; NERC staff asked that attendees advise as to their ability to travel that month in light of “end-of-year responsibilities and the holiday.”

SARs Move to Standards Committee

Committee members endorsed two standard authorization requests (SARs) authored by NERC’s Energy Reliability Assessment Task Force on Wednesday. The goal of the project is to update NERC’s reliability standards (either by creating new standards or modifying existing ones) to require registered entities to perform energy reliability assessments in order to evaluate energy assurance and to develop corrective action plans to address any identified risks. The SARs will now be submitted to NERC’s Standards Committee for approval.

However, another SAR — proposed by the Inverter-based Resource Performance Working Group (IRPWG) to modify standard EOP-004-4 (Event reporting) to address a flaw identified in a report on the July 2020 San Fernando Disturbance — was rejected by the committee.

The incident involved a widespread reduction of active power from solar facilities across a large geographic area; the report’s authors said that EOP-004-4’s event-reporting requirements are intended for large synchronous generating resources and don’t address scenarios in which generation losses at a number of small facilities add up to a large loss.

Presenting the SAR to the committee, the IRPWG’s Julia Matevosyan said the goal is to “ensure that future events that are similar to already-experienced [solar] events … would be captured by this [new] generation loss criteria.”

Attendees expressed discomfort at the SAR’s proposal to make reliability coordinators responsible for reporting the relevant generation loss data. The SAR justified this suggestion on the grounds that RCs “are best suited for identifying widespread events … involving solar PV and wind resources [and] are also able to coordinate with [neighbors] to identify if the loss of resources spans across multiple footprints.” But Duke Energy’s Greg Stone, in comments that were echoed by other speakers, said this idea would put the burden on the wrong stakeholders.

“The RCs … are reliability coordinators, not reporting coordinators,” Stone said. “Given the commentary that we got in [Matevosyan’s] presentation that the collection and submission of this data is already problematic, we don’t need to be putting the RCs in the middle of that and especially create a compliance burden for the RCs to go hunt this down after the fact. … Put the burden of reporting the data on the people who have the data, and don’t put another function in the middle of that.”

While 17 of the 30 RSTC members in attendance voted to endorse the SAR, with 11 voting against it, the committee’s rules require a two-thirds majority for an item to be considered approved. As a result, the proposal failed. Receiving the RSTC’s endorsement is not technically required to proceed with a standards development project, but Matevosyan agreed to take the SAR back to the IRPWG and modify it based on committee members’ feedback.

Procedural Confusion on EMT SAR

The RSTC’s rules created some confusion around another SAR intended to ensure that transmission planners and planning coordinators “have accurate models necessary to adequately conduct reliability assessments under increasing levels of inverter-based resources” by requiring TPs and PCs to conduct electromagnetic transient (EMT) studies during the interconnection study process and annual planning assessments.

The vote on endorsement initially appeared to fail to meet the two-thirds threshold, with 19 votes in support out of 30 recorded. But committee staff pointed out that under RSTC rules, abstentions are not counted as votes cast — therefore, the three abstentions should be left out of the total. After this subtraction, the eight votes against endorsement were not sufficient to carry the field.

This decision led to several minutes of discussion over the procedural implications of the rule; while no members disputed the result of the vote, several said that the existence of an “abstain” option in Slido, the voting software used by the committee, was at least an implication that votes other than yes or no were possible. Staff agreed to change the options in Slido, renaming “abstain” to “present,” in hopes of preventing further misunderstandings.

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Conn. Climate Council Gears Up for New Work Session

Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes kicked off a new phase of work Wednesday for the Governor’s Council on Climate Change.

“We want to be flexible and encourage working groups to reconvene, refresh their membership … and have the chance for dialogue to see what flows out of that,” Dykes said during the council’s first meeting of the year.

The state has made significant progress on recommendations in the council’s phase one report released in January 2021, but the council has “a lot more to do,” she said.

During the meeting, Dykes highlighted recent legislative successes that stem from the council’s report, including passage in May of an act establishing a goal of 100% zero-carbon electricity by 2040 and an act that expands programs for distributed energy resources.

Gov. Ned Lamont signed an executive order in December that extended the council’s responsibilities to include reporting by the end of the year on mitigation and adaptation and resilience progress.

Six working groups, aligned under a mitigation subcommittee and an adaptation and resilience subcommittee, will convene with a focus on cross-cutting themes that the council identified during the phase-one report development. Those themes include environmental justice and leveraging Infrastructure Investment and Jobs Act funding.

The council will select subcommittee and working group members this month, and the groups will meet twice before October. Those groups will present the results of their meetings to the full council in December, and the council will make a final progress report to the governor in January, according to Rebecca French, director of the Office of Climate Planning at DEEP.

“This is not a one year and done process,” French said, adding that the groups will continue discussions “in 2023 and beyond.”

The “spirit” of the council’s work this year is to reinvigorate the relationships that members built while developing the phase one report, Dykes said. Working groups will have an opportunity to take an in-depth look at what is happening in their focus areas and “give people a sense of where to plug in and get involved,” she said. They also will look at next steps for policies that can support objectives in the phase one report.

“We’re eager to see what comes out of this activity over the next couple months,” Dykes said.

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DOE Conference Details Massive R&D Effort on Clean Hydrogen

The Biden administration’s efforts to develop a hydrogen market — from the generation of clean hydrogen to its use as a universal fuel across the economy — has expanded as if on a war footing, focusing the firepower of the National Labs alongside that of multiple industries and universities.

That was made clear this week at the U.S. Department of Energy’s three-day virtual symposium, which attracted thousands of engineers, scientists and curious members of the public, and covered every aspect of what has become a rush to move the nation from fossil fuel to hydrogen energy.

Even before President Biden unveiled the administration’s goals in a series of speeches during the first weeks of his term, DOE had in late 2020 published an updated hydrogen plan that predicted the federal push to combat climate change by moving the nation to hydrogen. That plan was an update on previous, but much less ambitious, plans dating back to 2002.

The accelerated efforts under this administration have even surprised Sunita Satyapal, director of the Hydrogen and Fuel Cell Technologies Office within DOE’s Office of Energy Efficiency and Renewable Energy (EERE). She was moderator of the initial plenary session on Monday that took a quick look at the hydrogen effort, from basic science to deployment.

“Keeping track of all the information out there because things are moving so quickly” has become difficult, Satyapal said. “There are so many offices, so much happening in the space.

“Please do keep track of the websites and newsletters,” she advised viewers and listeners before introducing Todd Shrader, head of one of DOE’s newest operations, the Office of Clean Energy Demonstrations. “What are the priorities that stakeholders out there should pay attention to from your perspective?” she asked.

Shrader’s response: “What’s it going to take to launch the new hydrogen economy itself?” he replied. “We can build hydrogen hubs 1 through 4, or 1 through 5 with government support,” he said in a reference to the department’s offer of up to $2 billion in matching grants to regions capable of cooperating to build regional developments producing clean hydrogen for use by nearby industries.

“But what’s it going to take to build plants 6 to 100? What’s it going to take to move to these [administration] goals by 2035 and 2050?” he said in a reference to the administration’s goal of building a carbon-pollution free U.S. power grid by 2035 and a net-zero carbon economy by 2050.

But producing hydrogen, whether by electrolysis with renewable energy or by splitting it from methane and capturing the resulting carbon dioxide, is a complex process.

Ned Stetson, a veteran hydrogen technologies researcher and now program manager at DOE, made that clear when explaining the efforts of his research team at EERE to develop electrolyzer and related technologies to produce hydrogen at a price comparable to steam reforming and ultimately even lower.

Steam reforming today produces about 99% of the hydrogen used by industry, and one reason is that electrolyzer technology, from efficiency to durability, cannot compete. Helping industry develop more efficient and more durable electrolysis technology is near the top of Stetson’s list. But it’s not alone.

“We cover everything from reducing the hydrogen molecule; to all the infrastructure needed to condition it, move it, store it and dispense it; to all these various end-use applications for power generation, industrial applications and so forth,” he said.

“We are also involved with blending hydrogen with the natural gas infrastructure, and in terms of transportation, we’re also developing the onboard storage technologies. So it’s a very large activity covering a lot of distance.

“We are really focused in our office on using the clean and sustainable energy resources and feed stocks to produce clean hydrogen. We look at several key pathways producing hydrogen, including direct solar water splitting, biological processes and, of course, electrolysis. And then once you produce the molecule, we work on the conditioning, liquefying it … purifying it, moving it, storing it and then finally dispensing it to the new application,” he said.

The Infrastructure Investment and Jobs Act has provided $1 billion in research and development funds for electrolysis, he said. The ultimate goal is reduce the price of hydrogen produced through electrolysis to $1/kg by 2031.

“The goal of the electrolysis program is reducing the cost of hydrogen produced with electrolyzers to less than $2/kg by 2026. That’s right in line with getting to $1 by 2031,” he said.

After asking for input in February from industry and other researchers about how these goals might be accomplished, the division received comments from 120 companies and individuals, he said.

“We asked about the key attributes for storage and infrastructure, the ancillary technologies, what would be some of the barriers for scale up. What are the needs for national test facilities for electrolyzers? We asked about recommendations to incorporate … diversity and equity. We got a lot of input from … manufacturers and developers including universities and a lot of end users and stakeholders,” he said. “We’re still digesting all the information.”

An example of DOE working with industry is its contract with Shell in October 2021 to develop very large liquid hydrogen storage tanks. Such tanks will be important for domestic storage and at export terminals.

“Shell is looking at designing … an extremely large liquid hydrogen storage vessel, 20,000 to 100,000-cubic-meter storage vessels. To put that in perspective, currently the largest liquid hydrogen storage vessel, just constructed at the Kennedy Space Center, and is about 4,700 cubic meters,” Stetson said.

Dimitrios Papageorgopoulos, program manager at DOE’s Fuel Cell Technologies, provided some perspective on the depth of the agency’s involvement in efforts to help industry develop fuel cell power systems capable of competing in, for example, heavy trucking, power generation or infallible standby generation.

“The goal is to develop fuel cells that are competitive with incumbent and emerging technologies across all these applications. The goal is to develop these fuel cells to meet market needs, and this is very important because we’re not looking to develop a technology for the sake of technology,” he said.

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NYISO 2022 Power Trends Report: Reliable Clean Energy Needed Quickly

NYISO continues to adapt its wholesale electricity markets and grid planning processes to accommodate a wave of widely distributed renewable resources more dependent on weather than traditional generation, according to the ISO’s annual Power Trends report issued Wednesday.

“The introduction of a lot of new resources and the planned exit of some high-emitting resources that we’ve relied on for quite some time has resulted in an increasingly dynamic, decentralized grid, which means it’s much more complicated to be able to manage and predict how the core functions are going to be satisfied,” CEO Rich Dewey said in a press briefing. “A lot of our focus is making sure that we’ve got the tools and capabilities to maintain the necessary level of reliability as we move through that transition.”

Reliability margins are shrinking as generators needed for reliability are planning to retire, and electrification of space heating will likely flip the peak load from summer to winter in the mid-2030s, according to the report, subtitled “The Path to a Reliable, Greener Grid for New York.” Meanwhile, delays in building new supply and transmission, higher-than-expected demand, and extreme weather could threaten reliability and resilience in the future, the report said.

Forecast Load Shapes (NYISO) Content.jpg2021 New York Control Area (NYCA) Bulk Electric System 2021 Actual and 2042 Forecasted Winter/Summer Load Shapes | NYISO

 

A successful transition of the electric system requires replacing the reliability attributes of existing fossil fuel generation with clean resources with similar capabilities, the report said. New transmission is being built, but more investment is necessary to support the delivery of offshore wind energy and to connect new resources upstate to downstate load centers where demand is greatest.

“We at NYISO have been firm advocates for the need for new transmission for several years now, and we’re happy to report that that New York state, not only the New York ISO, but also some of our state partners — the Public Service Commission and the New York Power Authority — are making meaningful progress in the development of new transmission that will be critically important to help move power from the upstate region,” Dewey said.

New York’s Climate Leadership and Community Protection Act (CLCPA) requires that 70% of the state’s energy come from renewable resources by 2030 and that its grid be 100% net-zero emissions by 2040.

FERC in May approved three changes to NYISO’s capacity market that were spurred by the CLCPA, such as excluding new policy-driven resources from its buyer-side market power mitigation (BSM) rules, which will eliminate offer floors for wind, solar, storage, hydroelectric, geothermal, fuel cells that do not use fossil fuel, demand response and other qualifying resources under the law. (See FERC OKs NYISO Capacity Market Changes Stemming from NY Climate Law.)

Hourly load profiles are also changing because of the growing impacts of behind-the-meter solar, EV charging, climate change and post-COVID-19 shifts in the occupancy rates of homes and businesses, the report said.

The ISO’s announcement for the report also includes a datasheet of key takeaways.

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ISO-NE Starts its Capacity Accreditation Journey

ISO-NE this week launched its effort to revamp its resource capacity accreditation process, a key fix to the capacity market that has been tied in with discussions around the contentious minimum offer price rule.

In a presentation to NEPOOL Markets Committee on Tuesday, ISO-NE’s Steven Otto laid out the beginnings of the RTO’s thinking and offered some early hints as to where it’s leaning as it prepares a more detailed proposal in the coming months.

The goals of the project are to boost reliability and maintain cost effectiveness as New England moves toward a decarbonized grid. The RTO’s current accreditation process is a mishmash of approaches that the grid operator has acknowledged doesn’t do a good enough job reflecting different energy sources’ contributions toward resource adequacy and reliability.

One of the key decisions that ISO-NE is thinking through, Otto said, is whether to employ an average or marginal approach to capacity accreditation.

Capacity accreditation (ISO-NE) Content.jpgThe pros and cons of marginal and average approaches to capacity accreditation | ISO-NE

 

Marginal approaches “set a resource’s accredited capacity based on the marginal reliability impact of an incremental change in size,” he said. Average approaches, on the other hand, set the accredited capacity based on the average reliability impact of a resource’s class.

The RTO is currently leaning toward a marginal approach, Otto said, sometimes also called a Marginal Reliability Impact value.

The advantages of a marginal approach, according to ISO-NE, are that it sends accurate entry and exit signals to market participants, can incorporate interactions between resource types, and provides the same compensation to resources that provide the same service.

It’s far from a settled conversation though: The grid operator is planning a roughly yearlong stakeholder process to hash out the details and decide on a proposal to send to FERC.

The first phase, involving conceptual design and education, is planned to go through October of this year. The RTO will start presenting a detailed design in November and move to finalize that design and produce tariff language by next spring. Stakeholder committee votes are planned for May and June of 2023.

Feedback on capacity accreditation will come both through the stakeholder process and outside of it: The Massachusetts Attorney General’s Office, for example, is planning to produce a report with recommendations in the coming weeks.

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Biden Administration to Order EV Charging Standards

The Biden administration announced Thursday it will require that electric vehicle chargers installed with federal funding meet minimum reliability standards and charging speed, work for all cars and take common payment methods.

“The new standards will ensure everyone can use the network — no matter what car you drive or which state you charge in,” the White House said in a fact sheet on the proposed regulations governing $7.5 billion in federal funding authorized by the Infrastructure Investment and Jobs Act (IIJA).

The Department of Transportation wrote the regulations in consultation with the Department of Energy in the administration’s bid to build a national network of 500,000 EV chargers.

The funding, which will be spent over five years, includes $5 billion allocated to states, D.C. and Puerto Rico based on a formula under the National Electric Vehicle Infrastructure (NEVI) program and $2.5 billion in competitive grants for smaller towns or tribes that may not qualify for the NEVI funds.

Transportation Secretary Pete Buttigieg said the chargers will be “available to everyone everywhere, whether driving in urban, rural or tribal communities. It means a standard to build EV charging stations every 50 miles, no more than 1 mile off the highway, with a focus on the interstate system and alternative fuel corridors.”

“Everyone should be able to find a working charging station when and where they need it without worrying about paying more or getting worse service because of where they live. You shouldn’t have to sort through half a dozen apps on your phone just to be able to pay at a charging station,” he added. “No matter where you live or where you’re headed, everyone should be able to count on fast charging, fair pricing and easy-to-use payment for their EVs.”

Deputy National Climate Adviser Ali Zaidi said the regulations will “democratize access to a cost-saving technology.”

Energy Secretary Jennifer Granholm said U.S. EV sales doubled in 2021 and could double again this year as rising gas prices make EVs more affordable.

“At today’s gas prices, EV owners can save about $60 bucks every time they charge up compared to an equivalent fossil fuel-powered vehicle,” she said. “This administration wants to make sure every American can reap those cost savings, and key to that mission is giving people confidence that they can drive an EV wherever they want to go and charge up wherever they live.”

Granholm reiterated her call for Congress to pass tax credits to incentivize EV purchases, “because if we’re going to build out infrastructure like we haven’t done since the Eisenhower era, we have to build it right.”

The standards will require at least four 150-kW DC fast charging ports per station so “if you get there and there’s a few people ahead of you, you can [charge] at the same time,” said Stephanie Pollack, deputy administrator of the Federal Highway Administration. 

“It has to be working 97% of the time; that’s a consumer complaint that we’ve heard,” added Pollack. “There’s a requirement for real-time data that will ensure that third-party apps can provide you information when you’re on the road so you can find not just a charger but the nearest charger. Is someone else using it? Is it currently operating?”

In February, DOT and DOE announced the first installment of funding, $615 million for 2022, ranging from a low of $2 million for Puerto Rico to $60 million for Texas. (See States to Get $615 Million for EV Charging from IIJA Funds.)

“These federal charging programs were designed to catalyze additional private sector investments that complement the buildout of a user-friendly, cost-saving and financially sustainable national EV charging network,” the fact sheet explained.

State plans are due in August, and FHWA will be approving them on a rolling basis. “As soon as the state has an approved plan, they can start putting that money to work,” Pollack said.

“People need to have confidence that they can find a charger so that they’re willing to buy electric vehicles,” Pollack said. “A national network means the experience [when] you pull up to that charger is the same no matter where you are.”

Economic Development

Officials also touted the economic development impacts of the spending.

Zaidi said EV companies announced 22,000 manufacturing jobs in the first quarter of the year, with companies locating in the U.S. to be part of the country’s supply chain. “It means we’re going to capture more of the economic upside here in the United States,” he said.

White House Infrastructure Implementation Coordinator Mitch Landrieu said the standards will “trigger competition” in the EV space, noting “the historic private investment from automakers like Ford, Stellantis and [General Motors], and EV charging manufacturers like Tritium and Siemens.”

Officials said the Joint Office of Energy and Transportation will select 25 members to serve on a federal advisory committee, the EV Working Group, to “make recommendations regarding the development, adoption, and integration of light-, medium- and heavy-duty electric vehicles into the transportation and energy systems” of the U.S.

The joint office also will engage the American Public Power Association, Edison Electric Institute and National Rural Electric Cooperative Association “to inform electric system investments and support state planning.”

Granholm said the administration plans to offer up to $30 million in funding for clean energy mobility pilots and demonstration projects in underserved and rural areas “to create solutions for overnight at-home charging in multifamily buildings. We want all these solutions, and we want experts across the country helping us to make sure we’re doing it right.”

Related Initiatives

Officials said the new regulations would supplement DOE’s May announcement of $45 million through its “EVs4ALL” program to develop very fast charging batteries.

The administration also touted the Department of Agriculture’s EV charging resource guide for rural property owners, states, territories, tribes and others, and a climate smart schools guide explaining funding for charging for rural school districts.

In addition, the General Services Administration has created blanket purchase agreements to help federal agencies and others to procure EV chargers and services at federal facilities.

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New York Utilities Support Incentives for EV Charge Station Buildout

New York investor-owned utilities last week said they support cost-of-service-based electric rates with time-bound incentives to provide cost relief for EV charging station owners, which they deem preferable to solutions based on rate design. (18-E-0138; 22-E-0236).

The rate-design-based solutions proposed by several stakeholders “are too broad-brushed and inflexible, do not reflect cost causation, and are inferior to targeted, transparent, flexible, and timebound non-rate design based incentive solutions,” the utilities said in comments filed with the New York Public Service Commission.

The proceedings concern EV supply equipment and infrastructure, and establishment of a commercial tariff or other solutions to facilitate faster charging for light-, medium-, heavy-duty and fleet electric vehicles (EVs). (See New York Utilities Report Slow Start to EV Fast Charging.)

The IOUs responding included Con Edison (NYSE: ED) and its subsidiary Orange and Rockland; Central Hudson Gas and Electric; National Grid (NYSE: NGG) for its Niagara Mohawk Power subsidiary; Avangrid (NYSE: AGR) subsidiaries New York State Electric and Gas (NYSEG) and Rochester Gas and Electric (RG&E); and PSEG Long Island operating for the Long Island Power Authority.

Cost Concerns

Advanced Energy Economy and the Alliance for Clean Energy New York asked the commission to “consider how to fairly spread the costs across all customers rather than commercial customers alone,” which the utilities said reflects the EV program being one of several public policies supporting clean energy initiatives.

Other stakeholders said that demand charges send important price signals but reducing or eliminating those charges in tariffs may be the only cost-relief option, an approach the utilities deemed “suboptimal compared to solutions that would provide cost relief and maintain appropriate price signals.”

For example, the Alliance for Transportation Electrification noted that “demand charges are a fair and efficient means of recovering the costs utilities incur … but can raise issues when included in rates paid by charging station operations.”

PowerFlex said that rates should align with grid needs so EV adoption does not become a cost burden to electric customers. It said that while demand charges encourage grid-beneficial behavior, they should not be so high so as to discourage EV charging station installation.

ChargePoint recommended reducing demand charges and increasing volumetric charges for at least 10 years, while Tesla supported shifting DCFC charging customers to rates with reduced or no demand charges. The Metropolitan Transportation Authority wanted utility rates to be set such that commercial EV fleet owners do not incur higher costs than when operating diesel and compressed natural gas vehicles on a cost per mile basis.

Vehicle weight classes (EPA) Content.jpgVehicle weight classes and EPA regulatory categories. | EPA

The utilities counter that targeted incentive-based operating cost relief can support EV fast charger installation while retaining the beneficial price signals in demand charges.

“Rate-design-based solutions also result in shifting more costs from EV charging station operators to other customers compared to incentive-based solutions. The bill impact of incentive-based cost relief programs can be smaller than that of rate-design-based solutions and more spread out both over time and across all customer groups, rather than concentrated in that year in a single service class,” the IOUs said.

Fast charger network Electrify America suggested that residential customers who charge their vehicles at home end up paying more than residents of multi-unit dwellings in urban areas who rely on public chargers, and that demand charges are “the largest differentiating factor between effective electricity rates billed by the utility to residential and to commercial EV customer accounts.”

While the disparity between at-home and public charging may be a barrier to more equitable EV adoption, moving away from cost-reflective utility rate design likely would create further inequities among utility customers and create disincentives for efficient investment and innovation, the IOUs said.

“Proposals for rate-design-based solutions are not aligned with appropriate and established rate design principles … and do not reasonably manage cost shifts while promoting access to benefits, i.e., availability of fast charging to all customer groups. Optimal solutions should instead seek to target incentives to reach only the charging stations that need them and thus avoid inadvertent or unexpected cost shifts to other utility customers,” the utilities said.

The New York Power Authority advocated partnerships between ride-sharing companies and public fast charging providers to spread demand costs among more users, increase utilization and help reduce the impact of these costs.

The IOUs said they “support solutions that leverage price signals to encourage the adoption of innovative business models and technologies that enable grid-beneficial behavior.”

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DR Provider Seeks NYISO Approval for Small Customer Aggregations

California-based demand response provider OhmConnect is seeking NYISO’s approval to this summer begin enrolling small customer aggregations (SCAs) as special case resources (SCRs) in the ISO’s wholesale capacity market.

“All residences will be Con Ed customers located in NYISO Zones H, I, or J,” John Anderson, director of energy markets at OhmConnect, said Tuesday in presenting the SCA proposal to the ISO’s Installed Capacity/Market Issues/Price Responsive Load Working Group.

OhmConnect has enrolled over 250,000 residential customers into its various programs in CAISO, ERCOT and Australia.

Most SCA proposals that come before the working group are trying to address the problem of a lack of available metering data and to win approval for alternative metering methodologies, but OhmConnect’s New York customers all have advanced metering infrastructure or smart meters, and the aggregator obtains the customer data directly from Con Edison through their Share My Data platform, Anderson said.

“The challenge we face is instead a technical one in the NYISO demand response information system (DRIS), and simply stated, the system as currently configured cannot accommodate customers whose average coincident loads are smaller than 1 kW,” Anderson said.

OhmConnect has in fact already signed up several thousand residential customers, approximately half of whom are already participating in the ICAP program, he said.

“These customers are sufficiently large that we were able to enroll them directly in the program, and our focus here today with the SCA proposal is on the remaining half of our customer base that was too small to enroll directly due to the current DRIS design,” Anderson said.

An SCA proposal must be approved by at least four of the chairs and vice chairs of the NYISO Management Committee and Business Issues Committee, and the chairs of the ICAP and Price Responsive Load Working Groups. The approvals were to be requested from the applicable approvers by email after the meeting, said Ethan Avallone, NYISO distributed resources operations manager.

“This metering meets the NYISO’s expectations for the SCR program participation, and the ISO supports enrolling these resources as a small customer aggregation in the SCR program,” Avallone said.

OhmConnect Event Timeline (OhmConnect) Content.jpgOhmConnect will initiate the following sequence of actions upon notification from NYISO of a mandatory or test ICAP-SCR event to commence at hour T and with duration of N hours. | OhmConnect

 

The SCAs will consist of the curtailment from residential customers who will participate in the ICAP-SCR program, and OhmConnect intends for these customers to participate in the 2022 Summer Capability Period as early as July and is requesting multiple SCAs for each zone to accommodate future anticipated customer growth, Anderson said. NYISO rules prohibit any change to an SCA within a given capability period.

“When a customer enrolls and authorizes us access to their data, we can use the data to directly calculate performance of the resources in an SCA. We do not need to infer that performance, but can measure it directly,” Anderson said.

Asked about the effect of customers opting out of a DR event, Curtis Tongue, OhmConnect co-founder and chief strategy officer, said, “We typically see opt-out rates from our customers at about 1% or less per event, so in practice it ends up being a relatively negligible impact.”

Several market participants asked how NYISO will ensure that any additional SCA proposals, whether to serve different load zones or not, would employ the same methodology being approved in this process.

If the aggregator has the first proposal approved in one methodology and comes the next month with another proposal, “we would validate that they are doing the same exact methodology,” said Steven Gill, technical specialist on the ISO’s distributed resources operations team. “We have correspondence back and forth with [OhmConnect] that it’s the same exact methodology and load reduction plan, and the same exact intentions and way they’re going to deliver megawatts to the grid.”

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MISO Bolstering Generation Retirement Studies Amid Capacity Shortage

As it stares down its footprint’s supply crunch, MISO is proposing to revise its generator retirement studies to include more notice, relaxed confidentiality rules, and stiffer adherence to local reliability requirements.

However, staff was firm during Tuesday’s Planning Subcommittee that the changes will not add resource adequacy considerations to MISO’s existing study process.

The grid operator announced last month that it was considering bulking up the studies under its Attachment Y process that determine whether retiring generation needs to stay online longer under a system support resource agreement. (See Capacity Shortage Prompts MISO to Consider Broadened Retirement Studies.) Presently, the retirement studies focus solely on the transmission system’s reliability, not resource adequacy; MISO does not have the jurisdictional authority to extend generators’ operational lives because of resource adequacy concerns.

The RTO’s Sydney Yeadon said staff seek to “mitigate some challenges” with escalating retirement notices coming from its membership.

She said MISO will impose a one-year notice requirement on retiring generation before MISO begins Attachment Y studies, a six-month extension of current practices.

“More time is needed to conduct more in-depth studies,” Yeadon said. She said the yearlong warning will give staff “greater visibility of the near-term resource mix.”

Anticipating more generation retirements, MISO also proposed to conduct retirement studies in batches on a quarterly basis instead of when the requests are received.

MISO’s Andy Witmeier said a quarterly kickoff of retirement studies will help staff better manage their workload. He said the RTO is never certain of how many retirement or suspension requests it will receive at any given time.

“We need more time in order to do the analysis,” he said.  

The doubled notice time and quarterly cadence will allow MISO to conduct stability studies on a more frequent basis. Yeadon said the extra studies are necessary as the amount of retiring baseload generation picks up.

The grid operator will also begin sharing the systemwide number and megawatt value of retirement requests, Yeadon said. She said MISO “obviously” won’t share the details of individual retirement requests.

Attachment Y notices are currently confidential unless an owner waives recission rights and places a unit directly into retirement, the generator doesn’t return to service when the recission period ends, or MISO evaluates the resource as a possible system support resource.

The RTO also plans to alter the customary mitigation practices used in the retirement study process’ steady state analyses. Staff allows load shed as a mitigation option when voltage and thermal violations are uncovered but going forward, staff wants to lessen wean reliance on load shed.

Stakeholders debated whether MISO’s proposed limits on load-shed mitigation amount a change rooted in resource adequacy concerns.

“We’re just trying to ensure reliability with the practices we have,” Yeadon said.

“That’s going to get litigated, I’m sure,” replied Customized Energy Solutions’ David Sapper, representing MISO load-serving entities.  

Witmeier said it’s not MISO’s purview to dictate when generation retires and that the grid operator is merely focusing on local reliability requirements.

“The enhancements that we’re proposing here are [an] improvement to the process,” he said.

Stakeholders asked whether MISO is considering further changes to its retirement studies to hang onto the capacity it has.  

“I feel like there’s been a lot of stakeholder discussion around this, and I wonder if MISO internally has been discussing some kind of joint forum on it,” Clean Grid Alliance’s Natalie McIntire said.

Witmeier said no such workshop is on the horizon for now. He said the stakeholder-led Resource Adequacy Subcommittee could pursue future discussions on Attachment Y process, but it hasn’t yet.  

MISO considers the issue a planning matter, though stakeholders have called for improving the Attachment Y process, given the topic’s implications to the footprint’s resource adequacy.

“We don’t want to slow down the improvements that we see could be done now,” Witmeier said.

“This is a step in the right direction, but it doesn’t go far enough,” Prairie Power’s Karl Kohlrus said of the study process changes.

Kohlrus said he’s concerned that staff isn’t reflecting all future baseload retirements in their transmission-planning models. He said MISO hasn’t yet accounted for all announced baseload retirements or impacts stemming from Illinois’ Climate and Equitable Jobs Act.

“I’m concerned that there’s no place for MISO to do accurate modeling … It’s kind of scary as a planner that you’re studying a future that won’t exist,” he said.

Staff said they will update planning models with the latest retirements later this year.

MISO Independent Market Monitor’s Michael Chiasson also said the RTO’s retirement and suspension practices have a loophole where a unit can remain on an extended outage for years without being pressured to designate its unit as either suspended or retired. Chiasson said resource owners who don’t want to replace their capacity are essentially allowed to “tie up interconnection” points with nonoperational units.

“I see a couple of examples here and there, not huge amounts … It’s not really widespread at this point,” Chiasson added. But he said as MISO reassesses its current retirement study practices, “it’s a good time” to also address the gap.

Coal Retirements Mounting 

Coal advocate America’s Power said it has tallied announced coal retirements in MISO at 19.3 GW in the 2022-2027 timeframe and 27.3 GW by 2030. The group said if utility announcements pan out, 35% of MISO’s current coal fleet will retire within the next five years, with half of the fleet idled by 2030.

America’s Power said its estimates don’t factor in coal retirements that might be spurred by reinvigorated federal regulations. The group said those regulations could lead to more than 30 GW of MISO’s existing coal capacity installing selective catalytic reduction and/or flue gas desulfurization.

“We are concerned that these facts about future coal retirements might not have received the attention they deserve,” the group said in a late April memo circulated within MISO.

America’s Power also said the coal generation that will retire over the next five years supplied an annual average of 16 percent of MISO’s energy during 2019-2021 with an average capacity factor of slightly more than 50%.