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November 18, 2024

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NYISO CEO Warns of Tightening Resource Adequacy

NYISO CEO Rich Dewey on Wednesday told reporters that anticipated fossil fuel-fired plant retirements could shrink reliability margins to the point that they may have to be delayed.

“We’ve got to be really careful not to prematurely retire resources if we don’t have replacement supplies at the ready,” Dewey said.

The comments came as part of Dewey’s presentation of the ISO’s annual Power Trends report, the findings of which were similar to those of last year’s: NYISO has its hands full as state public policies drive rapid fossil plant retirements, while the interconnection of new clean resources is not keeping up. (See NYISO 2022 Power Trends Report: Reliable Clean Energy Needed Quickly.)

“We’re mindful that the number of interconnection requests has quadrupled, but this is a priority for us, and we are doing everything we can to make sure this process is as efficient and effective as possible,” Dewey said.

To meet the goals of New York’s Climate Leadership and Community Protection Act, which mandates 70% of the state’s energy come from renewables by 2030 and its grid be 100% net-zero by 2040, more must be invested in the research and development of emissions-free resources that will be needed to replace the capabilities of the retiring traditional plants, the report says.

Dewey last month told attendees at a conference hosted by NY-BEST, a battery storage consortium, that dispatchable emission-free resources must be quickly introduced onto the grid, and NYISO is committed to developing the right price signals that incentivize these technologies to enter New York’s markets. (See New York Fine-Tuning its Market for Energy Storage.)

NYISO has a “robust portfolio of new market enhancements that recognize the pricing signals that are necessary to attract the right resources to the right locations on the grid,” Dewey said Wednesday.

Transition to winter peaking system (NYISO) Content.jpgFigure showing transition to winter peaking system | NYISO

 

Other findings discussed during the conference also were familiar: a rise in carbon dioxide emissions partly attributed to the deactivation of the Indian Point nuclear power plant (21-01188); an acknowledgement that electrification will create higher demand and shift the grid to a winter-peaking system; and that unbottling intermittent resources via transmission upgrade investments can help bring upstate energy downstate to offset fossil fuel retirements.

“New York has enjoyed a surplus of energy supply over the last few decades, and that surplus has allowed us to manage the grid through contingencies and severe weather events,” Dewey said, “but as supply margins shrink, it has become more complicated and tighter operationally to make sure we can maintain and balance reliability.”

“Given that the number of deactivations has outpaced the number of new additions, that balance has come into sharper focus, and as [NYISO] looks forward, we are mindful of assessing and evaluating planned deactivations to ensure we maintain the tight balance necessary to operate the power grid,” he added.

NY Historical generating capacity (NYISO) Content.jpgHistorical generating capacity for New York from 2000 to 2023 | NYISO

 

Multiple reporters asked NYISO about thinning reliability margins across the state and what is the level of concern.

Dewey conceded that NYISO expects to see available megawatts shrink as fossil fuel plants retire and that the ISO needs to better understand whether these plants may need to remain in operation.

“It seems likely that some component of those peakers that are targeted for retirement would need to stay on,” Dewey added, “because it seems unlikely that we’ll have enough market-based solutions to eliminate the need for some element of those peakers to be extended for some period of time.”

In response to a question about the Public Service Commission opening a review process that could expand the role of nuclear and other technologies (15-E-0302), NYISO Executive Vice President Emilie Nelson said, “The incredible diversity [New York] has on supply-side technologies today is something that [NYISO] looks forward to seeing in the future years. We need a combination of technologies that can operate on the grid to really continue providing reliability day-in and day-out, so we look forward to exploring all technologies.” (See NY Renewable Portfolio May Come up Short on Getting to Net Zero.)

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Ex-ERCOT CEO Kahn Returning to Austin Energy as GM

Austin Energy announced Friday that it has brought former ERCOT CEO Bob Kahn back to the utility as general manager.

Kahn is currently general manager of the Texas Municipal Power Agency (TMPA), which represents 72 municipal utilities. He was ERCOT’s CEO from 2007 to 2009, and he replaces Jackie Sargent, who retired after controversial extended power outages in February.

“I’m very excited to return to Austin Energy and look forward to working with the community and the hardworking, dedicated staff at Austin Energy to accomplish the City Council’s goals,” Kahn said in a statement.

Bob Kahn (TMPA) Content.jpgBob Kahn, TMPA | TMPA


Before taking the ERCOT leadership role, Kahn was Austin Energy’s deputy general manager, general counsel and vice president for legal services. He served on ERCOT’s Board of Directors from 2002 to 2006, and returned to the board in 2021 following the disastrous winter storm, but resigned shortly thereafter over a conflict of interest with his TMPA leadership position. (See Former ERCOT CEO Kahn Resigns from Board.)

Kahn’s first day back with the utility will be July 3.

Interim City Manager Jesús Garza, who returned to the Austin government after Spencer Cronk was fired for the utility’s response to the storm, announced other leadership changes as well.

“I am confident the changes announced … will strengthen the City of Austin as we continually work to improve the services we provide to our residents,” he said.

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FERC Approves PJM Capacity Auction Delay to 2024

FERC on Friday approved PJM’s request to delay its Base Residual Auction for the 2025/26 delivery year, directing the RTO to submit a compliance filing that sets a June 2024 date (ER23-1609).

The commission’s ruling came just a day before its 60-day deadline to act; the RTO had said it would hold the auction as originally scheduled this Wednesday if the commission did not rule on its request. (See PJM Capacity Auction Weeks away with No Answer on Delay.)

PJM sought the delay to give itself more time to craft changes to its capacity market through its Critical Issue Fast Path process in reaction to the December 2022 winter storm. In its filing, it included a potential, “illustrative” schedule for the 2025/26 auction and three subsequent auctions, along with their respective Incremental Auctions, until it could resume its normal schedule beginning with the 2029/30 BRA in May 2026.

FERC approved the request, conditioned on PJM using that schedule.

“We find that the potential scope and magnitude of the capacity market-related reforms PJM is considering in its stakeholder process provide sufficient justification under [Federal Power Act] Section 205 to delay the auctions until after the commission has an opportunity to act on any proposals that PJM may file following that stakeholder process,” FERC said. But “we agree with commenters that the proposed tariff revisions afford PJM with overly broad discretion to set the auction schedule and fail to provide market participants with sufficient certainty as to the auction start dates for the [2025/26 through 2028/29] delivery years. … PJM must include the [illustrative] schedule in addition to PJM’s proposed tariff language stating that it will post the revised auction schedule on its website.”

The RTO’s schedule is based on it filing revisions by Oct. 1 and winning FERC approval of them without material changes by Dec. 1.

FERC also granted PJM’s request for 10 business days of leeway for specific pre-auction deadlines, agreeing that it would be administratively burdensome to file new tariff revisions for each one if there is a need for a change. “However, we recognize PJM’s commitment to post the specific dates of pre-auction activities no later than eight months prior to the commencement of any associated BRA in order to ensure that all market participants are aware of the relevant deadlines,” it said.

Commissioner James Danly concurred with the order, but he highlighted the move as an “extreme measure.”

“I only support delay in this case because PJM’s existing Reliability Pricing Model mechanism is manifestly unjust and unreasonable, and continuing to run auctions under the current rules will continue to produce unjust and unreasonable rates,” Danly wrote. “My colleagues, however, have not to date supported my calls to issue a Federal Power Act Section 206 investigation into PJM’s markets and its administration of them. Thus delaying the unjust and unreasonable auctions for PJM to develop market ‘enhancements’ is an appropriate exercise of our Section 205 authority and, given my colleagues’ reticence to act, the best we can hope for at present.”

Commissioner Allison Clements dissented, saying PJM failed to demonstrate its proposal to delay the auctions was just and reasonable. While she said she appreciated that the majority required “at least a minimal level of clarity” by directing the RTO to file the illustrative schedule, the order “sets a dangerous precedent that may essentially allow RTOs to schedule auctions according to their own whims, undermining certainty and stakeholder confidence in market rules and utility tariffs across the country.”

“If the mere possibility of future market reforms constitutes grounds for delaying particular auctions, absent evidence that existing rules are in fact unjust and unreasonable, how can market participants have any confidence in auction schedules memorialized in their current tariffs?” Clements wrote in a lengthy dissent. “PJM’s proposed delay is predicated on the need to wait until its current market rules are reformed, but PJM does not even specifically detail what those market reforms will be, let alone make out a legal case for why those reforms are necessary.”

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LPO Announces $850M Conditional Loan for Ariz. Battery Cell Plant

The Department of Energy’s Loan Programs Office (LPO) announced Friday it has made a conditional commitment for an $850 million loan to KORE Power to help the Idaho-based battery cell manufacturer construct a 1.3-million-square-foot plant in Arizona.

The KOREPlex facility, now under construction, will produce battery cells for both the electric vehicle and stationary storage markets. Located in Buckeye, Ariz., west of Phoenix, the plant will have an initial capacity to produce 6 GWh of battery cells, enough to power more than 28,000 EVs annually, according to the LPO.

“Onshoring battery manufacturing is critical to reducing America’s reliance on other nations, such as China, which currently dominates the industry and supplies many American companies with materials to resell foreign-made batteries,” the LPO announcement said.

Scheduled to begin commercial production in late 2024 or early 2025, the facility is being built with two manufacturing lines, one for lithium-ion nickel, manganese, cobalt (NMC) cells and one for lithium-ion iron phosphate (LFP) cells. While NMC batteries have been widely used in electric vehicles, some EV manufacturers are starting to use LFP cells, which are cheaper and do not use critical minerals such as cobalt.

The tradeoff is that they are not as energy dense as the NMC cells, which means EVs with LFP batteries may have a shorter range before they need recharging.  

Tesla is now using LFP batteries in some of its Model 3 EVs, according to the company website. Ford is also planning to produce LFP batteries for some of its EV models at a plant in Michigan, the company announced in February.

KORE plans to target smaller EV equipment manufacturers requiring lower production volumes. It is working with local colleges and universities to train area residents for the 1,250 permanent jobs the factory is expected to create.

Domestic Content Controversy

The KORE Power conditional loan commitment is the seventh the LPO has made under its Advanced Technology Vehicles Manufacturing Program in the past year, the agency said, and comes at a time when EV and energy storage supply chains have become a political flashpoint.

Batteries are critical to the achievement of President Joe Biden’s goals to decarbonize the electric power grid by 2035 and to crank up EVs to 50% of all new car sales by 2030. Republicans in Congress — and some Democrats, such as Sen. Joe Manchin (D-W.Va.) — have criticized these targets as potentially increasing U.S. dependence on foreign supply chains for battery cells and other clean energy technologies.

China, in particular, dominates the lithium-ion battery supply chain, controlling 75% of all battery cell manufacturing and 90% of the manufacturing of anodes and electrolytes, key battery components, according to BloombergNEF.

Manchin crafted the EV tax credits in the Inflation Reduction Act with rigorous domestic content provisions intended to support the build-out of a domestic supply chain for lithium-ion batteries. To receive the full $7,500 tax credit, final assembly of an EV must be in North America and 50% of the value of battery components and 40% of the critical minerals in the battery must be produced, processed or manufactured in the U.S.

The domestic content percentages will increase every year, to 80% for critical minerals by 2027 and beyond and to 100% for battery components by 2029 and beyond, according to the Internal Revenue Service guidelines released in March.

Conditional commitments do not guarantee the LPO will award a loan. “Several steps remain for the project to reach critical milestones, and certain conditions must be satisfied before the department issues a final loan,” the agency said.

Other recent LPO conditional commitments have included a $2.5 billion loan to Ultium Cells to support new EV battery cell plants in Michigan, Ohio and Tennessee, and a $107 million commitment to Syrah Vidalia to expand a plant in Louisiana that produces graphite, another core component of lithium-ion batteries.

Ultium is a joint venture of General Motors (NYSE:GM) and LG Energy Solution.

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Report Documents Growing Local Restrictions on Renewable Energy

Mid-2023 finds the U.S. charging ahead with its clean energy transition in policy and deed — except where it is not.

A new report compiles some of the hundreds of local laws nationwide that restrict, delay or block renewable power projects, in almost every state.

“This report demonstrates that ‘not in my backyard’ and other objections to renewable energy continue to occur throughout the country and can delay or impede project development,” the authors write.

“Opposition to Renewable Energy Facilities in the United States: May 2023 Edition” is an update of 2021 and 2022 reports by Columbia Law School’s Sabin Center for Climate Change Law.

The 2023 report notes 293 contested projects, 228 local restrictions and nine state-level restrictions, a major increase over the 2022 report, the authors write. The increase includes 59 restrictions imposed since the 2022 report and 58 restrictions adopted earlier but not included in the 2022 report.

And it likely is still a far-from-comprehensive list, the authors acknowledge. The National Renewable Energy Laboratory, for example, has compiled databases of thousands of state and local wind and solar ordinances nationwide.

But the Sabin report is limited to restrictive ordinances, a narrower focus than NREL takes.

Local Laws Matter

The federal and state governments issue sweeping visions and ambitious timelines for the clean energy transition, but in many instances, the rubber hits the road in one or a handful of communities at a time, and it is there that the transition can accelerate or bog down.

New York, for example, is one of the bluest of Democratic-controlled states in the nation and one of several to assign a superlative claim, such as “nation-leading,” to its climate-protection plan.

It also has a strong home-rule tradition codified in its constitution, and that can clash with the state’s vision for towering wind turbines and solar arrays spanning dozens or hundreds of acres.

The state has moved to sidestep local opposition by creating the Office of Renewable Energy Siting and giving it power to overrule local authority on renewable projects of 20 MW or greater capacity. But that does not stop local governments from trying to limit renewables, particularly in the more conservative, more rural upstate region, where wind and solar projects have proliferated. The Sabin report counts 21 restrictive local ordinances across New York.

Local restrictions such as these are not a theoretical impediment: NREL has used geospatial modeling to show a roughly sevenfold variance in wind energy siting potential nationwide depending on whether the least or most restrictive siting constraints are in place. Regulations are one part of that equation.

The Sabin report documents moratoria, bans and de facto bans that trend toward the most restrictive model.

Among the takeaways:

  • Alaska, Alabama and Missouri are the only states where the researchers could not find any restrictive laws or contested projects.
  • At least 13 counties in Ohio have prohibited large-scale renewable energy projects within most or all of their land area since October 2021.
  • The Ohio Power Siting Board never rejected a solar project before October 2022 but has rejected at least three since then.
  • At least nine Nebraska counties have enacted wind power ordinances with highly restrictive language since March, including setbacks of up to 3 miles from property lines and 5 miles from any dwelling.
  • At least seven counties in Virginia adopted restrictive solar power ordinances or moratoria between June 2022 and May 2023, some of them “exceptionally burdensome.”
  • In the Midwest, a movement is growing to ban construction of solar energy systems on farmland, including in at least two Michigan townships and four Wisconsin towns.

Sabin said the report’s authors do not make judgments on the merits of any particular ordinance or project cited in the report, but they note that taken as a whole, local opposition presents a significant potential impediment to achieving climate goals.

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Panel Explores Consumer Connections to Western RA

During a blistering 10-day heat wave last September, California residents helped the state avert rolling blackouts by acting on an emergency text that called for reduced electricity consumption as solar output began rolling off the system during the evening of a day of record-setting demand.

Within 20 minutes of the Sept. 6 call for conservation by the governor’s Office of Emergency Services, CAISO’s demand dropped by 2,385 MW. (See CAISO Reports on Summer Heat Wave Performance.)

The consumer response, which was also seen outside the ISO’s footprint, was not so much a spontaneous reaction as a product of a long process of relationship-building, according to Sherrie Villmark, program director with the Community Energy Project, a Portland, Ore.-based nonprofit that works with utilities and local government to provide free energy-efficiency services to low-income households.

Speaking Thursday during a WECC webinar on consumer considerations related to Western resource adequacy efforts, Villmark described a meeting with a Sacramento Municipal Utility District (SMUD) employee involved in communicating with customers during last summer’s emergency. The staffer recounted that SMUD had spent “years” engaging with community members to prepare for such an event, building a “social piggy bank” that the utility was able to draw on at a critical moment.

The webinar’s other panelist, Utah Office of Consumer Services Director Michele Beck, offered a “contrarian view” on the California response — and one that revealed potentially divergent Western perspectives on the consumer’s role in RA efforts.

“I believe, even though I’m hearing it secondhand, that California put the effort into the piggy bank, but I think that’s hard,” said Beck, who is also a member of WECC’s Member Advisory Committee. “I think that many, many jurisdictions do not have the systems to do that, and so I think that unless there is … a formalized system like that in place, policymakers should be cautious about using that sort of call to action as an actual resource.”

Beck questioned how often electricity customers would be willing to answer such calls before wondering whether others were bearing their share of the burden.

Her view echoed that of WECC CEO Melanie Frye, who, in speaking about the California event, said demand response is “a great tool, but that’s not the way we want to deploy that as a resource.” (See WECC Heat Wave Analysis Evokes Calls for Caution, not Celebration.)

“I’m still a little skeptical, to where I think it shouldn’t be a resource; that resource adequacy means that we don’t have to call people and say, ‘Hey, can you turn your air conditioning down?’” Beck said. “We need to have adequate resources; that should be our plan.”

‘Education and Access’

The two panelists were less divided — if not quite united — on how to get residential electricity customers to participate in other DR programs that can contribute to resource adequacy, such as use of “smart” technology to automatically adjust electricity consumption throughout the day.

For Villmark, those efforts require “a mix of education and access.” For Beck, it comes down to program design that makes participation as simple as possible.

“I have found that when it comes to education, experts are usually not the best educators,” Villmark said. “When you develop a deep expertise in something, you often forget what it’s like to not know those things deeply.”

She contended that third parties can be more effective at educating consumers because utility-based education programs are typically developed and conducted by engineers, who tend to delve into technical concepts that most audience members don’t understand or consider to be “trivia.”

Villmark said utility education often assumes a level of accessibility among consumers that doesn’t account for socioeconomic variables. For example, many residents don’t own their own homes or still can’t afford the internet service needed to take advantage of “smart” energy programs, she said.

Beck agreed with Villmark’s views on education but disagreed about the utility’s role, arguing that utilities are often the best partners in areas that don’t enjoy the level of resources available in a metropolitan area such as Portland.

“I also think that access is the key, and it’s certainly true that a lot of people are really interested in energy and do want to understand it better — but there’s also a lot of people who never will,” Beck said. “So, I think it’s incumbent on us to design programs so that they’re very easy to participate in [and] understandable. And on the program design level, we need to think about things like internet access, and we need to think about things like how do we make this a set-it-and-forget-it kind of a program. Because ultimately, if we want large participation in the residential and small commercial sectors, that’s going to have to be what it is.”

‘Blackout Blackmail’

Panel moderator Branden Sudduth, WECC’s vice president of reliability planning and performance analysis, appeared to push the consumer advocate hot button for Beck when he asked how utilities should invest in RA to ensure that electricity remains affordable for low-income households.

Beck said that conversation should expand to include more than just low-income customers, because electricity costs are increasingly jeopardizing affordability for those at a higher level of income who do not qualify for bill payment assistance. She pointed to what consumer advocates refer to as “blackout blackmail”: when a utility urges regulators to allow a resource to be rolled into customer rates “because we won’t be able to keep the lights on if you don’t do it.”

“Yes, we need to have resource adequacy, so let’s set the standard, but let’s still require that utilities meet the standard in the most cost-effective way,” Beck said.

Villmark cautioned that “certain cost-effective standards when it comes to [things] like energy-efficiency upgrades … can really work against us at times, because not everything is a straightforward calculation.” She said measurements that only consider cost can ignore other important benefits such as health, safety and climate resilience.

Beck clarified that she was talking about the cost-effectiveness of a utility’s overall resource mix.

“I think that if a utility wants to build this resource ‘X,’ but resource ‘Y’ is cheaper, they shouldn’t be automatically allowed to build resource ‘X,’ even though all of us want them to have sufficient resources,” she said.

Villmark questioned whether that would mean a requirement for utilities to build a coal-fired resource over solar if the former were cheaper, even in areas seeking to adopt cleaner resources.

Beck countered that the cost-effectiveness rule can still apply to a transitioning grid. “As I say all the time, set the goal and achieve the goal in the most cost-effective way. So, if you’re in a jurisdiction that’s evolving out of fossil fuels, now you’ve reset the goal, [and] you should still achieve that new goal in the most cost-effective way.”

In response to a question from RTO Insider about whether any utilities or jurisdictions are specifically focusing on residential energy efficiency to alleviate the West’s RA challenges, Beck said that both DR and EE are a “significant component” of PacifiCorp’s integrated resource plan.

“I’ve got certainly quite a number of concerns about the IRP, but I also have a long history of working collaboratively with their [demand-side management] folks, and I’m impressed with the programs that they design,” she said.

“We’re part of a study from the Department of Energy and [the National Renewable Energy Laboratory] that’s looking at that very thing — like exactly how much can you squeeze out of the house in that regard?” Villmark said.

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Pioneering Solar Project Prepares to Set Sail in NY

COHOES, N.Y. — A small upstate city is awaiting the final permit to build a pioneering solar array on its reservoir.

The 3.2-MW “floatovoltaic” project, three years in the works, apparently will be the first in the nation owned and operated by a municipality and apparently the first floating array of any kind in New York state.

The financials look very good at this point: The city has obtained multiple grants to help cover the estimated $6 million price tag, and solar panels’ electrical output is expected to far exceed the city’s consumption, zeroing out an electric bill that now exceeds $600,000 a year.

Even the notoriously slow process of interconnecting with the grid is complete.

“We were through the interconnection process with the utility six or seven months ago,” City Planner Joe Seman-Graves told NetZero Insider last week.

The last remaining hurdles are approval from the state Department of Health for modifying a public drinking water supply and a dam permit from the state Department of Environmental Conservation, the latter because the square reservoir is formed by earthen embankments.

The array will be held in place by 90 anchors placed in those embankments, which are a century old and hold back 50 million gallons of water on a hilltop residential area.

Why Rent When You Can Own?

Seman-Graves said the idea began to form in city leaders’ minds when one energy service company after another pitched the city on electricity-saving projects.

The reaction, he recalled, was: “If they’re looking at this and making money, how can we do it?”

Cohoes opted to undertake by itself the LED streetlight project that ESCOs were pitching. It issued bonds to cover the upfront cost of the lights and several other green projects.

Three ESCOs independently pitched nearly identical figures for savings with the LED lights — $9 million in 20 years, which Seman-Graves thought was a bit high. He recalculated the numbers, factoring in zero inflation over the two decades, and they still yielded savings.

Just as important, the bond served as equity to leverage millions more in grants for everything from smart city technology to historic preservation.

Then the city considered solar power, to eliminate the electrical bills altogether.

Ground-mounting a solar array was not an option. Cohoes is only 4 square miles. Part of that is under the Mohawk River, and most of the rest is occupied by homes and industrial facilities.

The only one of three city reservoirs still in service was the best option.

Cohoes did not initially look to become a solar owner-operator, Seman-Graves said, but it could not find a developer willing to be a pioneer on floating solar.

“So we said, hey, why not own it?” he said.

Long but Productive

That was a little more than three years ago. Creating a model for a first-of-its kind project dragged out the schedule for Cohoes, but it also provided time to find technical and financial assistance.

Nearby Rensselaer Polytechnic Institute helped the city with some of the research, demonstrating the project’s value proposition. Also assisting was the National Renewable Energy Laboratory, which has estimated there are 24,000 manmade bodies of water nationwide that could host enough floatovoltaics to meet 10% of the nation’s electricity needs.

Working in Cohoes’ favor as it sought funding was its status as a low- to moderate-income community. The per-capita income of its 18,000 residents is 19% lower than nationwide, and the city’s poverty rate is 39% higher.

In March 2022, the city’s representative in Congress — Democrat Paul Tonko, a former president of the New York State Energy Research and Development Authority — announced a $3 million federal allocation for the floating solar array as a demonstration project.

Two months later, National Grid committed $750,000 in economic development funding.

So the city already has about half the project budget in hand. It has spent $400,000 on design and $250,000 on interconnection costs.

New York’s NY-Sun program will provide additional assistance, as will the federal Inflation Reduction Act, although Seman-Graves has not yet fully researched the details of the latter.

The cost was estimated at $6 million three years ago; some components are more expensive now, and some are less. The city will get a firm price tag after it seeks bids, which it hopes to do this summer, after the DEC permit is in hand.

The lead time is as much as 50 weeks on some components, pushing installation back to summer 2024. But once it finally starts, construction should be straightforward, taking only five to six weeks, Seman-Graves said.

The panels will cover about half of the water surface and are projected to generate 4.153 GWh per year. The city needs only 60% of that to power municipal operations and may provide the remainder to the school district.

The site is secure, behind a chain link fence, and because of the embankments, the panels will be invisible from street level, averting the aesthetic complaints often leveled against large solar installations.

“We have people who don’t even know [the reservoir is] there; people think it’s a hill,” Seman-Graves said.

There is more concern about water quality than about aesthetics, he added. The water in the reservoir is not pristine: It is pumped directly from the Mohawk River to await treatment at the city water plant, next door.

NREL has talked about potentially placing a few ground-mounted solar panels on the site, Seman-Graves said. Floating solar is believed to have potential efficiency advantages over ground-mounted solar because the water can cool the panels and reflect sunlight at them.

Co-locating the two types of panels in Cohoes, he said, would provide comparative performance data that is lacking in the U.S., which has lagged behind other countries in developing floatovoltaics.

To get a sense of the process and mechanics, Seman-Graves visited the 8.9-MW Canoe Brook floating solar array while it was under construction in Short Hills, N.J. That site officially went online last week as the largest in the nation. The previous largest floating solar array in the U.S., a 4.4-MW facility in Sayreville, N.J., was already complete by the time Cohoes began its own process in earnest.

Also assisting Cohoes with the formative stages of the project were RETTEW, its contracted design firm; US Floating Solar, which gave guidance on the early iterations; the DEC and NYSERDA; the University at Albany’s Atmospheric Sciences Research Center; and the Capital District Regional Planning Commission.

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MISO Defends Renewable Ramping Stance to FERC

MISO defended its plan to bar renewable energy from supplying ramping reserves to FERC last week, saying its proposal doesn’t amount to undue discrimination between resources because of the “significant differences” between renewable and non-renewable resources’ ability to deliver ramp product (ER23-1195).

In a June 5 response to a deficiency letter, the grid operator said because so many of renewable resources’ ramping capability is essentially undeliverable, it becomes a “legitimate” factor that “can support different treatment of different types of resources” within MISO. FERC issued the letter in May. (See FERC Questions MISO Plan to Drop Renewables’ Ramp Eligibility.)

MISO said that dispatchable intermittent resources (DIRs) in the real-time market cleared 15% of the megawatt hours needed for up ramping last year. The RTO said 99.7% of the cleared output was “economically undeliverable” because the DIRs’ cleared ramp negatively affected transmission constraints.

Intermittent resources’ average marginal congestion cost was -$73.33/MWh, MISO said. Other resources providing ramp capability for the remaining 85% of MWh experienced uneconomic deliverability issues only 31% of the time, the grid operator said, with an average marginal congestion cost of -$5.83/MWh.

MISO said its data demonstrates “the extraordinary behavior of DIRs in MISO markets with regard to the clearing of reserve-type products such as up ramp capability.”

“Deliverability is important because mere ability to produce output, without deliverability of that output, renders any such would-be output useless to meet operational or market needs,” the RTO said. It said if it allowed ramping capability from DIRs, it would have to redispatch other resources to reduce flows on the limiting transmission. That would result in higher production costs.

“Such an outcome is plainly uneconomic for MISO’s markets, and it is more reasonable for MISO to refrain from dispatching such zero or negative [marginal congestion cost] resources — rendering them undeliverable for economic reasons, which are also linked to the need to reliably manage binding transmission constraints,” MISO said.

The grid operator also said that when it clears DIRs’ undeliverable up ramping, it depresses ramp pricing and hamstrings staff from “effectively redispatching the non-DIR fleet to optimize ramping capability.”

MISO said its wind resources tend to be geographically concentrated and likely to be trapped behind the same transmission constraints. MISO does not use locational considerations in its markets to determine which resources should be eligible to provide ramping reserves. It said DIRs’ offer profiles allow them to be cleared for up ramp at zero dollars when they’re undeliverable due to the negative impact of their marginal congestion costs on constraints.

In comparing DIRs to other resources, MISO said they have “fundamentally different” market participation characteristics and behavior. It said DIRs “almost exclusively” clear for up ramping when they’re already being dispatched down to manage transmission constraints. The RTO added that when DIRs aren’t being curtailed, it’s more profitable for them to offer all available energy to the grid rather than ramping product. MISO said when there’s no network congestion, DIRs opt to provide energy.

“The root problem is that curtailed DIR capacity is not economically deliverable to provide up ramp irrespective of its location, which prevents the market from acquiring sufficient ramping flexibility during periods of high ramping needs,” MISO said. “In other words, there is a significant difference in the manner as well as the degree to which DIRs versus non-DIRs are stranded/trapped behind transmission constraints.”

MISO said solar generation has a similar offer profile to wind generation and almost always clears for ramp when they’re being curtailed and thus, undeliverable. The grid operator said solar should also be excluded from providing ramping reserves.

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Salaries, Benefits Push MISO over Budget

MISO CFO Melissa Brown said last week that payroll and medical benefit expenses will push the grid operator over budget through year-end.

Brown said during a Wednesday meeting of the Board of Directors’ Audit and Finance Committee that as of April, base expenses are almost 3% over budget by $2.9 million. MISO expects to spend $324.5 million in base expenses and be over budget by $14 million, or 4.5%, before the year is up.

She told board members expenses are over budget mostly because of staffing levels, employee compensation and medical benefits.

Brown said MISO originally budgeted a 6.5% vacancy rate this year, expecting the same employee turnover it has experienced since 2021. However, that rate recently dropped to 4%. She said Human Resources Director Allegra Nottage and her team are doing a good job keeping MISO adequately staffed.

“We didn’t know how successful we’d be in getting our vacancy rate turned around. It’s very difficult to prepare for,” Brown said of the anticipated continuing trend of a tight labor market or a recession. She said MISO will forecast a further decline in its vacancy rate, “bringing us closer to full employment.”

Director Robert Lurie asked whether staff should be more conservative in forecasting spending given the current financial uncertainty. Brown said MISO will analyze this year’s variables and reflect those dynamics in next year’s budget.

MISO’s project investment expenses are under budget by about $1 million (10.6%) year-to-date, driven by equipment delivery delays and limited external resources. Brown said supply chain issues continue to persist, leading to “ups and down” among the RTO’s internal projects.

Brown will deliver a second financial report to the full board in Madison, Wis., this week.

Lurie asked that going forward staff include a statement in future financial reports that MISO is complying with its investment policy. The policy is conservative in nature because it invests its members’ funds to securities backed by the U.S. government, highly rated money market investments and dollar-denominated obligations held by entities rated AAA by at least one organization.

Lurie said that because MISO manages other people’s money, it is appropriate that it reiterate that investments comply with the policy.

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Activists Want ISO-NE to Push for Renewables

Thursday’s ISO-NE Consumer Liaison Group meeting was largely a forum on the merits of energy storage and fossil-fuel generation and a critique of ISO-NE for continuing to power the grid with one instead of advancing the other.

The tone was due in no small part to the meeting being held in Peabody, Mass., where a controversial gas-fired peaker plant was recently built near environmental justice communities.

Two older gas- and oil-burning units stand near the new one.

Peabody resident Susan Smoller, a representative of Breathe Clean North Shore, asked: “What is the plan to replace these peakers with batteries and renewables?”

She called on ISO-NE to be sure the higher-emissions fuel — oil — is not used in the older units if gas is not available and urged that demand peaks be reduced so the Massachusetts Municipal Wholesale Electric Co.’s new 55-MW peaker plant is never turned on.

“In the least, let’s make sure that it is the last new fossil fuel infrastructure built in Massachusetts,” she said to applause from some of the 200-plus attendees.

“It’s ISO New England that holds the power to decide when our peakers run, and what they burn,” Smoller said.

Other speakers drilled down on the idea that ISO-NE favors fossil fuel interests.

“Every time we come and ask for a just transition, we hear these arguments that ‘ISO has to be neutral; we can’t take a political stance on one form of energy over another,’” another speaker said. “ISO is already deciding what fuels are present on our grid and picking fossil fuels. My question is, how do we fix this? Do we need to change the tariff? Do we need to abolish [the] ISO itself?”

Another speaker paraphrased a prior statement by ISO-NE that it would prioritize grid reliability and proper market function as the clean energy transition moved forward.

“I’d like you to reverse that,” he said — make preserving conditions for life on planet Earth the priority rather than keeping the lights on and the capitalist free markets functioning.

“What we really want to hear is that your heart is in saving life — not in the lights coming on every time someone wants to make an egg,” he said.

ISO-NE Vice President Anne George pushed back on almost every point.

“Reliability also affects lives,” she said to the last critic.

ISO-NE’s mission and vision statements show its commitment to a successful transition to a clean energy future, George said, but “we have to do it in a reliable way.”

Some of her other rebuttals:

  • Anyone can participate in the wholesale market ISO-NE operates, if they meet reliability standards.
  • The RTO is independent and is not beholden to fossil fuel interests.
  • It agrees climate change is a threat and will use its tools to facilitate the energy transition.
  • The RTO lacks authority to make the changes suggested at the meeting.
  • It has advocated putting a price on carbon and embedding that into the wholesale electricity market to make renewables more competitive, but the RTO has found little support for such a move.
  • ISO-NE provides the “huge” value of an independent body to oversee the market.

The transition of the market toward renewables will not be as rapid as critics are calling for, George said.

“It is not going to happen overnight, and it is not something we are dragging our feet on.”

Energy Storage

The variable nature of the wind and solar power the clean energy transition — at least in its early stages — will rely heavily on makes a fallback power source indispensable.

A major theme of Thursday’s meeting was using energy storage rather than fossil-fired peakers to meet that critical need.

Rosemary Wessel, founder of No Fracked Gas in Mass, and Chris Sherman, a vice president at Cogentrix, related their collaboration in western Massachusetts.

Wessel listed the health problems in neighborhoods surrounding two Cogentrix peakers in the heart of Pittsfield.

Sherman recounted the company’s decision to retire both, and to retire a third peaker in West Springfield, Mass.

NE Proposed energy storage (ISO-NE) Content.jpgThe ISO-NE interconnection queue shows a large quantity of energy storage proposed in New England. | ISO-NE

The West Springfield site, with its three interconnections, will host a 45-MW/180-MWh battery energy storage system. The site could host as much as 100 MW, but 45 MW is what Sherman could convince the company and its investors to back.

Colette Lamontagne of National Grid said the utility has installed five storage systems in Massachusetts as demonstration projects and a nonregulated affiliate is developing renewable power generation.

Storage will be useful in easing the peak-demand transmission bottlenecks likely to arise as communities ramp up their use of electricity, she said, and provide a less expensive, more flexible alternative to building a new substation.

Jason Houck of Form Energy described the Massachusetts-based company’s pre-commercial efforts to develop longer-duration storage.

Sen. Joe Manchin and Energy Secretary Jennifer Granholm joined Form Energy in Weirton, W.Va., on May 26 to break ground on its first factory. At least 750 people are expected to eventually work there, fabricating iron-air batteries.

Form plans to build a 1.5-MW/150-MWh system in Minnesota next year for Great River Energy as a pilot project, then two 10-MW/1,000-MWh systems for Xcel Energy in 2025, one each in Minnesota and Colorado.

Both areas are seeing wind power replace coal power, Houck said, and have weather extremes, all of which creates the demand for storage.

An audience member at Thursday’s meeting asked him why Form Energy was not putting the projects in Massachusetts.

“We’d love to,” Houck said. “It comes down to the market structure. It’s a regulated market.”

It is easier to work under the other states’ integrated utility model, he added.

“In New York, New England, other markets, the utilities no longer own assets and don’t do planning; who do we partner with? In this region, the ISO has not historically played a role in commercializing new technologies.”

Priya Gandbhir, senior attorney at the Conservation Law Foundation, made a similar point about ISO-NE.

“We need the ISO to reform its market structure and prioritize getting clean energy up and running. We need the ISO to stop [looking] at the problem of how to fit clean energy resources into its existing market structures and rather to prioritize the just transition to our clean energy future.”