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November 17, 2024

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Eclipse Barely Dims CAISO Operations

CAISO maintained normal grid operations during Saturday morning’s solar eclipse, with swings in solar production that were more muted than what the ISO had modeled based on clear-sky conditions.

As the moon obscured much of the sun throughout California and other Western states, solar production in CAISO’s territory dropped to 3,434 MW at 9:30 a.m. PST, following an early morning peak of around 8,100 MW shortly before 9 a.m. That’s a drop of 4,666 MW.

As expected, net demand in the ISO spiked at 9:30 a.m. as both utility-scale and behind-the-meter rooftop solar dropped off. Still, demand of 24,023 MW at 9:30 a.m. was well within the 44,756 MW of available capacity at that time. Energy supplies from natural gas and imports increased between 8:30 a.m. and 9 a.m. as solar output fell.

After bottoming out at 9:30 a.m., solar output quickly climbed to nearly 11,000 MW around 11 a.m. The eclipse lasted from about 8 a.m. to 11 a.m.

The eclipse-day figures are from CAISO’s daily outlook data posted to its website on Saturday.

“The power grid remained stable throughout the duration of the eclipse, and system operations returned to normal shortly after the conclusion at 11:05 a.m,” CAISO spokesperson Anne Gonzalez told RTO Insider in an email Monday. “Overall, generators followed their forecasted dispatches closely, and ramping was smooth heading in and out of the eclipse.” 

The ISO plans to release a full analysis of eclipse operations in December, she said. 

In modeling of eclipse impacts ahead of the Oct. 14 event, CAISO had forecast a dip in solar production to 3,240 MW at 9:30 a.m., with a rapid ramp up to 14,041 MW at 11 a.m.

In a technical bulletin released in August regarding the Oct. 14 eclipse, CAISO identified that ramping period as a time of “operational interest” that it would study “to ensure adequate supplies of generation [reserves] are available to mitigate any adverse effects of the anticipated steep up-ramp in solar production.” (See CAISO Sheds Light on October Solar Eclipse Preparations.)

The swings in solar production seen on Saturday were less intense than what CAISO had modeled. CAISO had estimated a ramp-up rate of 120 MW per minute between 9:30 and 11 a.m. The actual rate was roughly 84 MW per minute.

CAISO’s modeling was based on a day with clear skies, when the drop-off and return of solar would be most marked. The ISO noted the modeling was a “high impact” scenario, and that cloudy skies on Oct. 14 would lessen the impact.

Saturday’s weather conditions included cloudy conditions in parts of California.

The Oct. 14 event was a partial — or annular — eclipse, in which the sun was obscured by 65% to 90% within the Western Energy Imbalance Market territory.

In its technical bulletin, CAISO contrasted Saturday’s event with the total eclipse on Aug. 21, 2017.

Since 2017, grid-scale solar within the CAISO footprint has increased from 10,000 MW to 16,500 MW, and behind-the-meter solar has grown from 5,700 MW to 14,350 MW. That raised concerns that this year’s eclipse might have greater impacts than the 2017 event.

On the other hand, because the Oct. 14 eclipse fell on a Saturday, demand was expected to be less than it would have been on a weekday. The 2017 eclipse was on a Monday morning.

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DOE’s Hydrogen Hubs Seek to Balance Industry, Political Priorities

With the Port of Philadelphia as a backdrop, President Joe Biden on Friday touted the $7 billion in federal funds going to seven regional hydrogen hubs spread across 16 states as “one of the largest advanced manufacturing investments in the history of this nation.”

The White House and the Department of Energy announced the hubs Friday morning, with the Philadelphia speech following in the afternoon. (See DOE Designates Seven Regional Hydrogen Hubs).

One of the clean energy initiatives created by the Infrastructure Investment and Jobs Act (IIJA), the hubs are demonstration projects aimed at building out commercial-scale clean hydrogen facilities that combine production, storage and end-use applications, while cutting greenhouse gas emissions in hard-to-abate industrial and transportation sectors.

The chosen projects still have to negotiate their awards with DOE. In most cases, the hubs involve a team of public and private stakeholders, such as large corporations, state and city governments, nonprofits and academic institutions.

“These hubs are about people coming together, across state lines, across industries, across political parties to build a stronger, more sustainable economy and rebuild our communities,” Biden said.

As part of his typical stump speech equating climate change with jobs, the president shared details on the Mid-Atlantic Clean Hydrogen Hub, which will include 17 sites in southeastern Pennsylvania, Delaware and New Jersey.

“The Delaware City Refinery in my state, vacant, … and a former jet fuel terminal in New Jersey will use renewable energy like solar power to produce clean hydrogen,” Biden said. “Plumbers, pipe fitters are going to replace and retrofit oil pipelines to transport the hydrogen here, where fueling stations in the Port of Philadelphia in partnership with Philadelphia Gas Works will provide clean hydrogen to people to power trucks [and] heavy-duty equipment.”

Philadelphia and the Southeastern Pennsylvania Transportation Authority will run their heavy-duty vehicle fleets on clean hydrogen, and Dupont is going to use clean hydrogen to power a large research and development facility in Wilmington, Del., he said.

All told, the hub could produce up to 100,000 tons of clean hydrogen per year and create an estimated 20,800 jobs, Biden said.

The project has been designated to receive $750 million in IIJA funds, supplemented with $2.25 billion in private investment.

Overseen by DOE’s Office of Clean Energy Demonstrations (OCED), the competition for the hub awards was intense. An estimated 79 projects submitted initial applications for the funding, and at least 22 were encouraged to submit full applications, according to an analysis from Resources for the Future.

OCED said the criteria for choosing the final seven included technical merit and impact, financial and market viability, how quickly the project could begin operation and the creation of community engagement and benefit plans covering workforce development, job creation and diversity and equity initiatives.

All prospective hubs also had to show they would be able to produce 50 to 100 metric tons of clean hydrogen per day and cut greenhouse gas emissions.

In addition to the Mid-Atlantic hub, the other winners are the Appalachian (Pennsylvania, West Virginia and Ohio), Midwest (Michigan, Indiana and Illinois), Heartland (Minnesota, North and South Dakota), Gulf Coast (Texas), Pacific Northwest (Montana, Washington and Oregon) and California hubs.

All Things to All Stakeholders

From their inception, the regional hydrogen hubs reflected an attempt to balance the conflicting political and energy industry interests that went into the writing and passage of the infrastructure bill.

For the fossil fuel industry, the hubs validate its promotion of hydrogen as a complementary fuel that can be mixed with natural gas and transported through existing natural gas pipelines. For clean energy advocates, government support for hydrogen provides another driver for increased deployment of solar and wind, while the nuclear industry gets assurance of ongoing demand for existing and new reactors.

To be all things to all stakeholders, the IIJA spelled out very specific requirements for the hubs.

“Feedstock diversity” was a top priority, requiring that at least one hub produce hydrogen from fossil fuels, one from nuclear energy and one from renewables.

Geographic diversity also was mandated, with each hub to be located in a different region of the United States, using energy resources that are most abundant in that area. At least two of the hubs had to be located in regions with large natural gas resources.

Finally, the IIJA requires end-use diversity, with at least one hub producing hydrogen for electric power generation, one for the industrial sector, one for residential and commercial heating and one for transportation.

Those requirements are well-represented in the final seven projects, and the mixed reception they have received. (See Hydrogen Hub Announcement Draws Praise and Scorn.)

The DOE’s Pathways to Commercial Liftoff: Clean Hydrogen report, released in March, frames clean hydrogen as essential for cutting U.S. greenhouse gas emissions in industrial and transportation sectors where electrification may not be a feasible option, such as chemical production or aviation. A rapid scale-up could allow the U.S. to produce up to 10 million metric tons (MMT) of clean hydrogen per year by 2030 and 50 MMT per year by 2050, cutting the country’s GHG emissions 10% below 2005 levels, the report says.

With their combination of production, storage and end-use applications, the hubs are aimed at jump-starting expansion of clean hydrogen demand and infrastructure over the next three years.

They also will benefit from clean hydrogen incentives in the Inflation Reduction Act (IRA), including either a 30% investment tax credit or a production tax credit of up to $3 per kilogram.

With the IRA incentives set to last 10 years, private investment then could become a core driver of growth as the industry scales and prices fall, the report says. “These investments, including the build-out of midstream distribution and storage networks, will connect a greater number of producers and offtakers, reducing delivered cost and driving clean hydrogen adoption in new sectors.”

But the report also sees significant headwinds to commercialization of clean hydrogen, noting that even with the regional hubs and tax incentives, demand may lag production. In July, DOE announced it would use another $1 billion from the IIJA to develop a “demand-side support mechanism” for clean hydrogen. For example, the agency might act as a “market maker,” buying clean hydrogen from the hubs and then selling it to offtakers. (See DOE to Invest $1 Billion to Build Demand for Clean Hydrogen.)

Deployment of sufficient solar and wind to produce “green” hydrogen also could affect market growth, the report says. Without enough solar and wind, by 2050 the U.S. could see 80% of its clean hydrogen produced from natural gas with carbon capture.

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NJ Energy Conference: Business Skepticism vs Government Resolve

EDISON, N.J. — New Jersey’s commitment to a rapid adoption of clean energy will be unwavering, the newly appointed head of the New Jersey Board of Public Utilities (BPU) told a conference of skeptical business leaders last week, underscoring their concern with the state’s push to make electricity the prime energy source.

In one of her first public speeches as BPU president, Christine Guhl-Sadovy told the annual energy conference organized by the New Jersey Business and Industry Association (NJBIA) that her clean energy policies would be largely unchanged from those of her predecessor, Joseph L. Fiordaliso, 78, who died unexpectedly on Sept. 7, while still in office. (See NJ BPU President Fiordaliso Dies.)

Guhl-Sadovy will “carry on his legacy on advancing the clean energy economy,” she said at the conference, characterizing her task as seeking to mitigate climate change while advancing the energy economy.

“For those people who say we are moving too fast or being too ambitious, my first response is always we can’t afford to wait,” said Guhl-Sadovy, who was appointed by Gov. Phil Murphy (D) on Sept. 11. That position is partly driven by the urgency of climate change, but also by the wealth of federal funding available to pursue clean energy projects, she said.

“Why wouldn’t we want to take full advantage of that?” she asked.

Uninformed Certainty

The BPU chief’s comments capped a day-long conference that highlighted the challenges facing New Jersey in meeting climate change and underscored the sense that even as Gov. Phil Murphy has moved aggressively to meet them, there’s a wide diversity of opinion in the business community about whether the strategy is the right one.

The NJBIA is one of the most vocal opponents of Murphy’s policies. The association has raised concerns about costs, especially with the offshore wind program, and has pushed back on Murphy’s effort to cut building emissions by electrifying heating and water systems. The association is leading a coalition of business groups in opposition to the state’s adoption of California’s Advanced Clean Cars II rules. (See NJ Businesses Demand Halt to EV Sales Promotion Rules.)

The conference offered a broad range of perspectives, including that of Judith Curry of the Climate Forecast Applications Network, who opened her presentation by saying Murphy’s climate change strategy reflects “political bias and uninformed certainty.” She argued that — despite the opinions of numerous scientists that climate change is an urgent, man-made threat — the change stems in large part from “natural climate variability” and the main problem is that the world has overplayed its response.

“Making Net Zero targets is causing us to make bad choices about future energy systems,” she said, arguing as an example that “widespread implementation of wind and solar power is impairing grid resiliency and reliability.”

Still, Ray Cantor, the NJBIA’s main lobbyist, framed the conference more moderately in his opening remarks.

“There’s no doubt that we have to decarbonize,” he said. “The real question is, how do we do it?”

Imbalance of Power

Whatever the path taken, the challenges facing the state, like others, will be immense as it puts together a network of solutions at unprecedented speed that can cut emissions while maintaining customer service, speakers said.

Timothy Burdis, lead strategist of state government policy for PJM, laid out the delicate balancing act the RTO will have to make in the next few years as New Jersey and the other 13 PJM members adopt differing levels of renewable energy development.

New Jersey at present generates about 14,000 MW, of which about one quarter is generated by nuclear energy and about two thirds by natural gas generators, according to his presentation. Solar energy accounts for about 1.5%, and the state, with a demand for about 20,000 MW of electricity, is an energy importer, and so relies on energy generated by other PJM members, Burdis said.

Timothy Burdis, PJM | © RTO Insider LLC

Yet even as states ramp up clean energy production, a crunch moment looms because generating capacity will decline as plants — mainly coal generators — are closed, either because they are uneconomic or state and federal environmental laws require it.

The PJM system has about 260,000 MW of new capacity waiting in the queue, of which about 26,000 MW is in New Jersey, Burdis said. Historically, only about 10% of the capacity in the queue makes it to completion, although that percentage may increase because of government funding and programs designed to support clean energy projects.

In comparison, PJM predicts that far more capacity — about 40,000 MW — will come offline in the next seven years, Burdis said.

“Even those resources that make their way through our queue are not necessarily coming online at the pace that we need them to,” Burdis said, citing financial, supply chain, siting and permitting issues. “With these resources coming on and the resources coming off, it starts to get a little tight at around 2030.”

Ensuring the tightness doesn’t become a crisis will partly require PJM and the utilities in its system to improve their performance, to ensure those facilities providing electricity can produce at critical moments, such as during storms, he said. In addition, PJM and utilities will have to manage carefully the timing of plant retirements to match the loss in power with the rate at which new plants are coming on, he said.

“It’s looking at the stuff coming off of the system and what do we need to do to preserve it if we have to, to encourage it to stick around, encourage it to make investments that it has to,” he said.

Decarbonization Playbook

Planning for the change will be key, not only to prepare for the dramatic increase in demand for electricity, but when it’s needed, said Richard T. Thigpen of PSEG. He presented a slide that showed that by 2040 or 2050 existing demand patterns will have reversed.

Richard Thigpen, PSEG | © RTO Insider LLC

“The peak demand is going to switch from summer to winter,” he said. “And that’s something that the experts with planned distribution systems seem to talk about quite a bit, it’s something that we’re going to have to think about very carefully in terms of managing our costs as we go forward.”

Yet a well-planned, aggressive move toward renewable energy production at PJM can yield big benefits for the company’s customers, said Jesse Jenkins, an assistant professor and energy system engineer at Princeton University, outlining what he called a “decarbonization playbook.” Jenkins leads a team that has studied the impact on clean energy development of the federal Inflation Reduction Act and the infrastructure law.

Without the federal funding, the sector’s current trajectory would see emissions increase by about 14% between now and 2035 and the wholesale cost of electricity decrease by about 30%, he said. With federal funding in place, costs will decline by about one-third and emissions will reduce to 36% below 2021 levels, he said.

If PJM added to that by requiring 80% of its energy to be clean electricity, emissions would be cut 80% to 90% while customers would pay about the same as at present, or less, he said.

So “maintaining affordability, reliability, across the clean energy transition” is achievable if “we follow the decarbonization playbook,” he said.

To get there, New Jersey and other states need to take three steps, he said: build wind and solar projects at a “record pace;” expand the grid to handle electrification and renewable energy; and retire coal-fired generating plants.

New Fuel in Old Pipes

Representatives of natural gas supplying utilities urged the conference audience to not discount the use of gas in the state’s future energy mix, saying it would continue to be a key energy in any transition to renewable energy.

Stephen D. Westhoven, president and CEO of New Jersey Resources and New Jersey Natural Gas, said the state had invested too much into the infrastructure to discard it in favor of building up the electricity infrastructure.

“We’ve got a $17 billion head start. It’s really the investment that we’ve already made in the pipeline grid, here in New Jersey,” he said, adding that the 35,000 miles of pipeline “[supply] energy to 75% of New Jersey residents.”

“We have an electric system, we’ve got a pipeline system, and they work together to serve the energy needs of our state,” he said. “We’re already building renewable to put clean electrons on the electric grid. So, the question I ask is why don’t we have the same commitment to put renewable energy clean fuels into our pipeline system?”

That could include renewable natural gas, synthetic methane and hydrogen, Westhoven said, noting the federal government has allocated $8 billion for hydrogen hub development. It also could include biogas, extracted from the state’s landfills and could provide as much as 10% of existing customer usage, he said.

“They allow us to use our pipeline assets to reduce emissions,” he said.

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ERCOT Smoothly Handles Annular Solar Eclipse

ERCOT said it did not experience grid reliability issues with the loss of solar generation during Saturday’s annular solar eclipse, in what some saw as a performance check before next year’s total eclipse.

“It should be a really good test case,” ERCOT COO Woody Rickerson told the Public Utility Commission during an open meeting Thursday. “We don’t expect any problems.”

The Texas grid operator had several ancillary services available should there have been an “unknown, unforeseen” issue, he said. (See ERCOT Prepared for Eclipse, Loss of Solar.)

Solar production dropped from just over 7,000 MW to 1,474 MW between 10:49 and 11:49 a.m. CT as the eclipse’s “ring of fire” traversed Texas. Natural gas resources helped compensate for the solar drop with more than a 4,000-MW increase in their generation.

ERCOT’s fuel mix during the eclipse. | ERCOT

“A solar plant will experience a shadow moving over it, but at a different time than other solar plants,” Rickerson said.

A total eclipse will cross over Texas from Mexico and continue into Canada on April 8. It will be last eclipse visible in the continental U.S. until 2044.

ERCOT has almost 12 GW of solar capacity available during the fall season. The resource was credited with helping the grid operator meet record demand during a blistering summer this year, accounting for about 15% of the grid’s fuel mix during the heat of the afternoon.

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Hydrogen Hub Announcement Draws Praise and Scorn

Reaction to the Department of Energy’s hydrogen hub announcement Friday was swift and, in some cases, passionate.

Environmental advocates have been suspicious of or downright hostile to policymakers’ pursuit of hydrogen as a way to decarbonize sectors such as heavy industry and shipping.

Depending on how it is generated, it can carry a significant carbon footprint even as it displaces fossil fuels. And burning hydrogen is not an emissions-free process, even if it does not emit carbon dioxide. Of the seven hubs selected, four — the Appalachian, Texas, Midwest (Illinois, Indiana and Michigan) and Heartland (Minnesota, North Dakota and South Dakota) hubs — plan to use natural gas with carbon capture, or “blue” hydrogen. (See DOE Designates Seven Regional Hydrogen Hubs.) So it was no surprise that environmentalists pounced on Friday’s announcement, calling it “absurdly expensive,” “outrageous” and “reckless.”

But those advocating for hydrogen, particularly those on the winning side of Friday’s announcement, ranged from pleased to ecstatic by the promised investments and jobs.

Bragging Rights

Houston Mayor Sylvester Turner said his city, the center of the Gulf Coast Hydrogen Hub, “is uniquely able and willing to lead in the global energy transition.”

“There is no better place to produce American energy than in Texas,” said Texas Gov. Greg Abbott (R).

U.S. Sen. Joe Manchin (D-W.Va.) boasted in a news release that West Virginia, a part of the Appalachian Hydrogen Hub with Ohio and Pennsylvania, “will be the new epicenter of hydrogen in the United States of America.”

“As chairman of the Senate Energy Committee, I wrote and fought for the bipartisan infrastructure law to include $8 billion to establish hydrogen hubs to demonstrate the production and use of clean hydrogen — and now, West Virginia will be on the leading edge of building out the new hydrogen market while bringing good-paying jobs and new economic opportunity to the state,” he said.

Doubts on Carbon Capture

But Chelsea Barnes, director of government affairs and strategy for environmental group Appalachian Voices, expressed skepticism, saying DOE should invest in proven renewable energy technologies and “not further our reliance on methane gas.”

“While the hydrogen produced by these hubs will provide direct emissions reduction benefits to several forms of industry like chemical production and alternative fuels, the emissions reduction benefits are much more speculative for energy generation sites,” she said. “Carbon capture at these facilities is an unproven technology at this scale. There is only a modest reduction in greenhouse gas emissions from hydrogen blends.”

Seth Mullendore, president of the Clean Energy Group, which manages and staffs the Clean Energy States Alliance, a  coalition of state energy organizations, said the hub announcement was “worse than expected.”

“We are particularly disappointed in the administration’s investment in blue hydrogen, which would more accurately be called fossil hydrogen with carbon capture. The fact that more than half the hubs will be using fossil gas is outrageous. This reckless buildout of hydrogen infrastructure does nothing to advance climate goals, and the related emissions will harm environmental justice communities.”

Mullendore cited peer-reviewed analyses that he said found that, even with carbon capture and sequestration, “the production and combustion of hydrogen derived from natural gas produces more greenhouse gas emissions than directly burning natural gas.”

“Current CCS technology can only capture about 55% of carbon emissions in the hydrogen production and combustion cycle, and it does nothing to stop fugitive methane emissions, which have a significant global warming impact. CCS also increases harmful particulate matter by up to 60%.”

Discord in California

The California Hydrogen Coalition was elated at the selection of the California Hydrogen Hub, saying it will “drive additional investment in the hydrogen infrastructure California and our nation need, securing California’s status as a leader in environmental innovation and policy.”

California Gov. Gavin Newsom (D) also celebrated, saying the hub “will cut pollution, power our clean energy economy and create hundreds of thousands of good paying jobs.”

But Food & Water Watch California Director Chirag Bhakta said the state should not be pursuing hydrogen production.

“Hydrogen is not a clean energy solution — and it is especially ill-suited for areas where water scarcity is a problem. Hydrogen is water intensive, which is particularly dangerous in a state that lacks water resiliency like California. Throughout its lifecycle, each megawatt-hour of ‘green’ hydrogen consumes at least 5,000 liters of water — far more than clean energy sources like wind or solar. California’s water supply is already at risk.”

Endangering the Great Lakes

Susan Thomas, director of legislation and policy/press at Just Transition Northwest Indiana, said steelmaking regions will not be well-served:

“Fossil fuel-produced hydrogen and carbon capture and storage will irrevocably endanger the Great Lakes ecosystem while further harming the region’s already overburdened communities. As a historic steel hub, Northwest Indiana is an epicenter in the fight for a just transition to renewable energy. We deserve the right to green jobs and a healthy environment, not more false solutions. These hydrogen hub announcements are more of the same carbon schemes from corporate polluters.”

Also critical was Julie McNamara, deputy policy director of the Climate and Energy Program at the Union of Concerned Scientists.

“Given the magnitude of investment, ambition and geographic reach of the H2Hubs program, the federal government holds enormous sway over the future direction of the hydrogen industry — with serious implications for climate, health and justice on the line,” she said. “Concerningly, today’s H2Hubs announcement advances multiple projects premised on fossil fuel-based hydrogen production and risky hydrogen end uses. Billions of taxpayer dollars are at risk of perpetuating fossil fuel industry injustices and harms while subsidizing fossil fuel greenwashing. This is an untenable point of focus for funds intended to spur the buildout of our clean energy future.”

David Schlissel, director of resource planning analysis at the Institute for Energy Economics and Financial Analysis, said his group’s research has shown that the government is “significantly understating the impact of producing blue hydrogen on global warming.”

“The reality is that blue hydrogen is not clean or low-carbon. Pursuing this technology is wasting precious time and diverting attention from investing in more effective measures to combat global warming like wind and solar resources, battery storage and energy efficiency.”

‘Significant Breakthrough’

Sasha Mackler, executive director of the Bipartisan Policy Center’s Energy Program, welcomed the news. “Today, we are on the cusp of a significant breakthrough in the pursuit of cleaner, more sustainable energy solutions,” she said. “The H2Hubs program represents a monumental stride towards harnessing the potential of clean hydrogen to decarbonize multiple sectors, address our pressing environmental challenges and launch a new clean economy.”

Lisa Jacobson, president of the Business Council for Sustainable Energy, called the announcement “an important milestone in building up the U.S. clean hydrogen industry and lowering emissions from hard-to-decarbonize sectors. Clean hydrogen is a critical tool in the broad portfolio of energy solutions our country needs to reduce carbon pollution, increase energy security, and create good-paying American jobs.”

North America’s Building Trades Unions President Sean McGarvey hailed the potential for organized labor.

“The future of hydrogen in the U.S. is now. The Department of Energy, through its commitment to expanding the deployment of this clean-burning energy resource, continues to demonstrate the Biden administration’s support of union workers. Through President Biden’s bipartisan infrastructure law, the establishment of regional clean hydrogen hubs will bolster communities and the environment and uplift America’s middle class with more building trades lifelong, sustainable career opportunities.”

Ben Hunkler, communications manager with the Ohio River Valley Institute, is skeptical about the economics of the still-developing technology, however.

“Methane-derived blue hydrogen — and the carbon capture that supports it — is economic for only a few niche industries. Investing in these unproven, absurdly expensive technologies risks locking our region into a gas-based economy that has proven incapable of generating sustained job growth and has placed community health and safety in harm’s way,” he said.

It Depends

Several commenters said it was too soon to tell if the initiative will be beneficial or not.

Holly Reuter, climate and clean energy implementation director at Clean Air Task Force, struck a tone of cautious optimism:

“This first-of-its-kind demonstration program presents real opportunities to position the U.S. as a leader in the clean hydrogen economy while helping us achieve our climate goals and improving public health. As attention turns to the next phase of planning, DOE, hub developers and states must be closely coordinated and transparent and seek external expertise as the hubs move forward. While this announcement is exciting progress, it is critical we get this program right. That means taking the time to engage with communities, experts, and other stakeholders to maximize the climate, economic, and public health benefits the hubs can provide.”

Jill Tauber, vice president of litigation for climate and energy at Earthjustice, wants to see more details.

“Hydrogen can be a clean energy solution, or it can drive us deeper into the climate crisis and hurt communities. Hydrogen produced from fossil fuels is not a solution — whatever the color,” she said. “Green hydrogen that is powered by new renewable resources can play an important role cleaning up what we cannot electrify, like steel manufacturing. Strong policies and smart, targeted investments can ensure the right path.”

She said her group will be evaluating the hub proposals and work “to ensure transparency, meaningful community engagement and full consideration of climate and community impacts. We will continue to fight against a fossil fuel buildout.”

Erik Kamrath, federal hydrogen advocate at the Natural Resources Defense Council, said “the stakes couldn’t be higher” with the development of the hydrogen industry.

“This provides an exciting stimulus for green hydrogen but includes a concerning focus on blue hydrogen and diverting clean energy sources that are currently powering our homes, which will make it a steeper path to align hydrogen to U.S. climate goals. We need the strictest possible guardrails to mitigate the risk of hydrogen stalling climate progress and perpetuating pollution and public health risks for communities on the frontline of the climate crisis. We need strong guardrails to ensure that U.S. hydrogen does not create an emissions mess and that we are not subsidizing hydrogen that is clean in name only.”

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California PUC Launches New Resource Adequacy Proceeding

California utility regulators voted Thursday to launch a proceeding to establish rules and requirements for the state’s resource adequacy program from 2025 to 2028.

“This rulemaking continues the California Public Utilities Commission’s oversight of the resource adequacy program, establishes forward RA procurement obligations applicable to load-serving entities beginning with the 2025 compliance year and considers structural reforms to the program,” the commission said in the order instituting rulemaking (OIR) approved last week.

“Reliability is a critical priority for California’s electric system. Resource adequacy ensures reliability in real time, and I look forward to building on the work we’ve done in recent years to refine the program and support the achievement of our ambitious climate goals,” CPUC President Alice Reynolds said in a statement after the commission approved the proposal.

The CPUC said the “preliminary scope” of the proceeding would include adoption of LSEs’ local capacity procurement requirements for 2025-2028 and flexible capacity procurement requirements for 2025 and 2026. Both sets of requirements will be rooted in CAISO’s annual local capacity area technical study, the commission said.

Other matters to be considered in the rulemaking include:

    • potential modification of the state’s new 24-hour “slice-of-day” planning framework, which requires LSEs to show they have enough resources on hand to meet load and planning reserve margin requirements for the day with the highest peak load in each month;
    • potential changes to the RA penalty structure and consideration of new ways to incentivize compliance;
    • increased coordination with utility integrated resource plan activities, including consideration of “appropriate” planning reserve margin requirements for short-term planning compared with the longer time frame for IRP proceedings;
    • exploration of changes to the methodology for counting qualifying capacity from resources, including demand response resources; and
    • the possible application of an unforced capacity methodology “for resource counting that would account for ambient derates and forced outages.”

The agency also will use the proceeding to seek additional suggestions from affected parties, it said.

Comments on the scope, schedule and administration of the proceeding are due no later than 20 days after approval of the OIR, and reply comments are due within 30 days after that. A prehearing conference for the rulemaking is scheduled for Nov. 17, and the commission seeks to issue a scoping memo in December. A proposed decision is slated for May 2024, with a vote on the final plan expected in June.

“California’s resource adequacy process is critical to ensuring sufficient resources are available to the California Independent System Operator for the safe and reliable operation of the grid, to advance our clean energy goals and to minimize costs to ratepayers,” Commissioner Darcie Houck said.

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ISO-NE Details FCA 19 Domino Effect

A one-year delay of Forward Capacity Auction 19 (FCA 19) would have cascading effects in the five subsequent auctions, ISO-NE told the NEPOOL Markets Committee on Thursday.

ISO-NE has recommended a one-year delay of the auction to implement resource capacity accreditation (RCA) changes and discuss moving to a prompt and/or seasonal market for FCA 19. The auction is scheduled for 2025 and would apply to the 2028-29 Capacity Commitment Period. (See ISO-NE Recommends Delaying FCA 19.)

Alan McBride of ISO-NE presented to the MC on a proposed schedule for FCA 19 through FCA 25. Following a one-year delay of FCA 19, subsequent auctions would be conducted on a 10-month timeline, instead of the typical 12-month timeline. This would return the FCM to the typical 3½-year forward auction process for FCA 26.

This would mean that along with the delay of FCA 19, five auctions in a row would be delayed to some extent, while the first annual reconfiguration auction for capacity commitment periods 19 through 24 would be eliminated. If ISO-NE moves to a prompt capacity market for FCA 19, these changes would become obsolete.

ISO-NE has emphasized the importance of implementing RCA for FCA 19 but would not be able to accomplish this under the current timeline. The RCA changes will alter how ISO-NE accredits resources like oil and gas generators and energy storage in the forward capacity market.

The RTO said it hopes to submit the filing as early as possible in anticipation of a potential government shutdown in November and has scheduled an extra MC meeting on the morning of Oct. 26 to vote on the proposal. It then would go to a general vote at the Nov. 2 Participants Committee meeting.

Some clean energy stakeholders have expressed concerns about the effects that delaying FCA 19 would have on new resources looking to secure capacity rights in the auction.

Mike Berlinski of BlueWave, a company that develops, owns and operates solar and storage projects, said it’s “disappointing that ISO-NE had not considered the impact of delaying FCA19 by a year on the ability of new resources to participate in the Capacity market in the 2025-2026 period.”

“Because new resources need to go through an FCA qualification process in order to be eligible for a reconfiguration Capacity auction, which unlocks capacity payments for near-term periods, pushing back the FCA19 process … would create a one-year gap where new resources could not enter the capacity market,” Berlinski told RTO Insider, adding that this could hurt projects in development and lead to decreased supply in reconfiguration auctions.

“If ISO-NE is determined to delay FCA19, we hope they will agree to implement some alternative process to enable capable projects to participate in the capacity market in the interim period,” Berlinski said.

Analysis Group Report on Prompt, Seasonal Construct

Chris Geissler of ISO-NE detailed scope of work for the Analysis Group report on the potential structural changes to the forward capacity market.

The intent of the Analysis Group study is to weigh the “pros, cons and key considerations associated with moving to a prompt and/or seasonal capacity market,” Geissler said, adding ISO-NE will use this study to inform its ultimate recommendation.

The report will focus on the effects on market efficiency, entry and exit decisions, price volatility, interactions with capacity accreditation, and supplier offers and risk. Geissler added the analysis will be quantitative and qualitative.

Geissler asked for feedback as soon as possible, as ISO-NE hopes to share the report with stakeholders in December.

“Due to the limited time to complete the assessment, AGI may not be able to complete analysis that addresses every stakeholder request,” Geissler said.

The Analysis Group is planning to present the methods of the report at the November MC meeting.

Upward Mitigation Prevention

The MC approved one aspect of ISO-NE’s proposed compliance to FERC’s show cause order (EL23-62) on Wednesday. The show cause order directed ISO-NE to change or justify parts of its tariff relating to “mitigation rules that can result in market power mitigation that increases the offers of a market participant.”

To prevent potential upward mitigation, ISO-NE proposes to “compare each financial parameter (e.g., block or component) of the Supply Offer and Reference Level and use the lesser of the two values when performing certain automated mitigation procedures,” Andrew Withers of ISO-NE told the MC in September. “This differs from current practice, where the entirety of the Supply Offer is replaced with the Reference Level.”

Withers also detailed the RTO’s proposal to allow two fuel price adjustments (FPAs) to the supply offer, compared to the single FPA currently allowed. The higher FPA of the two would be triggered at a designated MW threshold and is intended to better represent how fuel costs can increase as energy output increases.

Withers said ISO-NE still is evaluating the viability of this proposal and the tariff changes it would require.

FRM Market Power Concerns

Ash Bharatkumar of ISO-NE presented on proposed changes to the Forward Reserve Market (FRM) to address market power concerns raised by the Internal Market Monitor in the spring markets report.

ISO-NE proposes to reduce the Forward Reserve offer cap from $9,000/MW-month to $6,300/MW-month and move to a 12-month delay on the publication of auction offer data, compared to the current four-month delay.

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Load Flexibility Could Hold Key to California Grid Constraints

Load flexibility is the fastest and cheapest way to prepare for rising electricity demand, and both the residential and commercial building sectors could be tapped as renewables supply an increasing portion of power, attendees at the Building Electrification Summit co-hosted by the California Energy Commission (CEC) and the Electric Power Research Institute (EPRI) heard last week.

Building electrification and the rise of EVs mean California needs to plan for using more electricity, not less, said CPUC President Alice Reynolds. When it comes to avoiding grid upgrades and coping with growing demand, moving the time at which electricity is consumed can be a massive lever. Load flexibility refers to the ability to change when electricity is consumed, and it can range from turning off an HVAC system for a short period during peak demand times to delaying EV charging until evening.

“Luckily these appliances that we’re all talking about growing, including electric vehicles and heat pumps, are the type of load that is flexible, so we have a lot of reasons for optimism,” especially as the grid moves to 100% clean energy, Reynolds said.

“Load flexibility is one of the cheapest and best approaches to improve grid reliability as far as greening our grid,” said Stefanie Wayland, load management standards lead at CEC. “We know that load flex works both at grid scale and at local scale, whether you’re doing it for sub-generation or for non-wire solutions where you’re avoiding distribution upgrades,” she said.

As buildings and transportation are electrified, the size and seasonality of peak demand will change, said Jessica Granderson, director of Lawrence Berkeley National Laboratory’s Building Technology and Urban Systems Division.

Granderson said that from 2025 to 2050, peak demand would increase from about 30 GW to 40 GW, while annual peak would shift to winter — when renewables generate less power — due to the load created by electric heating.

“As we successfully decarbonize the grid, we’re seeing this increase in the mismatch between that clean supply and the downstream demand from our buildings and increasingly our vehicles,” she said.

As buildings and transportation are electrified, the need for load flexibility will grow, along with the ability to control those loads through software.

Load flexibility is important during times of both excess and shortages of power, said Cisco DeVries, CEO of OhmConnect.

“So how do we adjust demand? We do that at home, in part through controlling devices and appliances directly in people’s homes. everything from EV chargers and battery storage systems all the way to hot water heaters’ spark plugs and thermostats,” DeVries said. “That allows us to very quickly and effectively reduce energy use in homes and help people get control of their energy bills, which is really critical.”

Labor Day in September 2022 proved the value of load flexibility in California. On a day when extreme heat produced high demand that was expected to lead to potential blackouts, OhmConnect’s customers were proactively reducing load. “They reduced 1.6 GWh of electricity over a few days, and we paid them over $2.7 million for the help that they gave. And that’s one of the reasons we didn’t have blackouts that day,” DeVries said.

The commercial building sector also offers significant opportunities to implement load flexibility strategies, Ammi Amarnath, principal technical executive at EPRI, said. For example, there are 12,000 convenience stores with significant refrigeration loads in California, most with present defrost cycles that can be reprogrammed. “A small change in the defrosting cycle in these small food stores can save up to 10 to 20 megawatts of electricity during those peak hours” in Los Angeles County alone, he said.

The 10,500 larger supermarkets, along with 112 refrigerated warehouses, each with peak demand of 250 kW to 4 MW, offer even larger load flexibility potential, Amarnath said, with a current EPRI project showing power can be modulated up to 25% while keeping the facilities within the carefully controlled temperature bands required.

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Rhode Island Energy Issues Offshore Wind RFP

Rhode Island Energy has issued a new Request for Proposals (RFP) for up to 1,200 MW of offshore wind capacity, the utility company announced on Friday, marking the largest solicitation of clean energy in the state’s history.

The announcement comes amid a period of setbacks for the industry due to escalating costs from supply chain constraints, high commodity prices and increased interest rates. Rhode Island’s most recent offshore wind solicitation received just one bid, which was rejected by Rhode Island Energy in July. (See Rhode Island Energy Rejects Revolution Wind 2 Proposal.)

“We know there’s a sense of urgency to get more renewables online and we believe this next RFP will give developers a new, unique opportunity to think creatively about how they can meet the state’s clean energy and economic development goals, while balancing our customers’ affordability needs,” Dave Bonenberger, president of Rhode Island Energy, said via press release.

Bids are due at the end of January, aligning the state’s timeline with the solicitations in Massachusetts and Connecticut. Earlier in October, Rhode Island, Connecticut and Massachusetts announced an agreement to coordinate their solicitations, hoping to bring down costs and leverage their collective buying power. The agreement will enable multistate bids to two or all three of the states. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.)

“With a larger capacity available, a streamlined application process, additional flexibility on contract durations and the potential for multi-state coordination, we believe this solicitation could provide greater economies of scale for developers,” Bonenberger said. “We’re providing more tools to help drive affordable offshore wind opportunities to our state and we look forward to seeing how it spurs innovation and competitive pricing from offshore wind developers.”

Rhode Island Energy said that selected bids (if any) will be announced in the summer of 2024.

On Thursday, the New York Public Service Commission rejected requests for inflation adjustments on 90 clean energy projects, including four offshore wind projects totaling over 4 GW in capacity. (See NY Rejects Inflation Adjustment for Renewable Projects.)

The developers of these projects have expressed concern about the viability of their New York contracts without the extra money requested. The developers could look to New England as a place to bid their projects if they back out of their current contracts, albeit under a tight timeline to submit bids.

“It’s not easy to pivot all aspects of a project — especially interconnection and state-specific supply chain, workforce and economic development investments — to another market,” Bob Grace, president of Sustainable Energy Advantage, told NetZero Insider. “However, the developers of offshore wind projects with New York OREC contracts that are no longer financially viable have to consider offering bids into the upcoming synchronized Massachusetts, Rhode Island and Connecticut offshore wind procurements, particularly from lease areas off of New England.”

Meanwhile, the New York State Energy Research and Development Authority has yet to clarify what the rebidding process for projects in New York might look like, but the state has announced it’s pursuing an expedited procurement process to make up for any canceled contracts.

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ERCOT Defends Admin Fee Increase Before PUC

ERCOT’s senior leadership defended the grid operator’s 2024-25 budget and its planned 27.9% increase to its system administration fee during a public hearing Friday before the Public Utility Commission’s legal counsel.

CEO Pablo Vegas said the ERCOT board’s Human Resources and Governance Committee invited stakeholder feedback regarding strategic priorities and objectives for the next five years. He said that feedback informed the budget’s development.

The ISO is proposing the first increase to the administration fee since 2016, raising it from $0.555/MWh to $0.710/MWh. Much of that difference will be passed on by retailers to ratepayers. Consumer advocates didn’t oppose the increase, saying it was long overdue and will help pay for the real-time co-optimization project that is expected to save billions.

The biennial budget will provide ERCOT with $424.03 million and $426.99 million in 2024 and 2025, respectively. That will cover operating expenses, project spending and debt-service obligations.

The board approved the budget and administration fee increase during its June meeting. (See “Board OKs 27% Increase in Admin Fee,” ERCOT Board of Directors Briefs: June 19-20, 2023.)

“The board’s approval reflects that the budget complies with ERCOT’s financial corporate standard and associated financial metrics approved by the board,” Vegas said, reading from his tablet. “The board, along with ERCOT management, supported the reasonableness of the budget request to provide for ERCOT operations and meet our strategic objectives for 2024 and 2025, including the commission’s requests.”

Vegas told Kasey Feldman-Thomason, the commission’s general counsel and the hearing’s moderator, that ERCOT considered several alternatives to the administration fee’s increase. Management looked at an increase each year, every other year, or every four years.

The board, after “significant deliberation,” ultimately approved a rate increase that keeps the admin flat for four years, Vegas said. The next increase is projected to occur in 2028.

“This option was selected for three principal reasons” he said. “One, it addresses potential liquidity constraints in 2024 and 2025, resulting from deferring the expected increase from 2022 into 2024. Second, it provides great stability to Texas consumers. And three, it helps to minimize the potential intergenerational inequity issues among the ratepayers by appropriately charging ratepayers for the services they are receiving.”

ERCOT held off on increasing the fee in 2020. The deadly 2021 winter storm has increased the grid operator’s costs for legal support and IT projects, the latter a result of recent legislation.

“ERCOT maintains acute awareness that consumers of Texas fund ERCOT,” Vegas said.

The grid operator has asked that the budget be approved by Nov. 15. It will become effective Jan. 1.

Will McAdams | Texas PUC

During the PUC’s open meeting on Thursday, Commissioner Will McAdams encouraged stakeholders to participate in the budget hearing.

“The magnitude of the increase is significant, and I want to hear from stakeholders,” he said. “We so far have heard nothing about that within the ERCOT process … I’d like to know a little bit more detail about if there are questions or concerns and then how that affects the commission’s deliberations.”

The Texas Industrial Energy Consumers and Sierra Club were the only two groups to ask for more information from ERCOT during the hearing. They asked for more analysis of some of staff’s assumptions and questioned the need for additional legal and public affairs staff.

The hearing’s notice was not posted to the PUC’s online calendar until Thursday over what the commission’s executive director, Thomas Gleeson, called an “oversight.” He said a different meeting accidentally was posted first.

Nuclear Group Names Members

Commissioner Jimmy Glotfelty said he has a “well-rounded” members’ list for the PUC’s Texas Advanced Nuclear Reactor Working Group he is chairing (55421).

“We are going to be moving very [quickly], but we are excited to be moving forward,” he told the commission. “I’m just happy that we got over this hurdle.”

The 17-member list, released Oct. 10, includes ERCOT CEO Pablo Vegas; Entergy’s Dillon Allen, senior manager of advanced nuclear development; CPS Energy’s Bret Colby, nuclear oversight principal as part of the municipality’s ownership stake in the South Texas Project; and Clayton Scott, executive vice president of business development for NuScale, a developer of advanced nuclear reactor technology.

Glotfelty said those not selected shouldn’t feel they’re not part of the group. He said six or seven more teams will be formed to address specific issues such as supply chains and high technology interest in the Texas workforce, similar to the commission’s Aggregated Distributed Energy Resources (ADER) task force.

“We had two leaders and we had about 70 people participating,” Glotfelty said. “That’s what we want in this.”

Texas Gov. Greg Abbott (R) in August ordered the working group’s formation. It is to evaluate what steps need to be taken so advanced nuclear reactors can provide power for Texas. The group must report its findings and recommendations to Abbott by Dec. 1, 2024.

PUC Missing RRs’ Discussion

The PUC approved 29 ERCOT protocol changes and other revisions, but not before Glotfelty questioned the grid operator’s COO, Woody Rickerson, to better understand the revisions’ effect on the ERCOT market (54445).

“I don’t feel like we get the benefit of the discussion when these protocols are being approved,” Glotfelty said. “There are a lot of policy issues in here that I think rise to the commission level that we should take a position on … I also think that there has been some shyness to speak your mind during the ERCOT committee process as a result of feared backlash.”

Under legislation passed after the 2021 winter storm, the PUC now must approve revision requests after they emerge from the stakeholder process. ERCOT’s Board of Directors approved the last round of revision requests in June with minimal discussion.

The pre-Winter Storm Uri board would hold closed sessions before its meetings so the independent directors could ask clarifying questions about the changes.

“We’re supposed to all be working in one direction, but I do think the reason we’re asking these questions … is how do we stay out of this technical condition of potential system failure?” McAdams said. “The stakeholder votes on these policies are extremely important and we look to those. So, if they’re not 100% on board, we need to know that.”

The commission also approved publication of a rule that repeals and replaces the state’s renewable portfolio standard with a temporary solar-only renewable energy credit as required by 2023 legislation. The temporary program will expire Sept. 1, 2025 (55323).