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November 12, 2024

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MISO Committed to Crackdown on Interconnection Queue Submittals, Departures

MISO appears set on restricting the interconnection requests it will accept and under what conditions they can leave the line in order to purge speculative generation projects from its queue.

Staff again this week said they need to toughen rules around entering and exiting the interconnection queue so that MISO doesn’t devote time to studying projects that aren’t a sure thing. The RTO debuted its plan in late May. (See MISO Wants Tougher Obligations on Queue Entry and Exit.)

The collection of changes will likely include more expensive milestone payments, a clampdown on penalty-free withdrawals, stricter proof that developers have secured land and reinforcing harm calculations so withdrawing projects have a better chance of owing money as they exit the queue.

MISO plans to present a straw proposal at the July 19 Planning Advisory Committee meeting.

“We’ve come to the point where we need to make some enhancements to the queue intake process so we’re getting better projects and a smaller number of projects, and we need to do that before we have a ‘23 cycle,” MISO’s Andy Witmeier said at Tuesday’s Interconnection Process Working Group.

Witmeier said if MISO kicks off the 2023 queue cycle with its existing rules in place, it will likely be hit with 200 GW of new interconnection requests. Last year, the grid operator fielded 171 GW of requests. MISO’s current queue contains 1,379 active projects totaling a little more than 237 GW.

“As the queues get larger, they slow down because there are more points of interconnection, more dispatch assumptions and more potential overloads to study,” he explained. He said a queue comprised of fewer, more successful projects will lead to faster queue processing and more cost certainty on transmission upgrades.

Most of the projects in MISO’s queue that haven’t yet proceeded to generator interconnection agreements are experiencing delays. All entrants in the 2021 and 2022 cycles are trailing the queue’s approximate yearlong timeline because of studies MISO must undertake.

Witmeier said he’s already been in private discussions with “key” stakeholders to put together a proposal.

MISO is aiming to file its proposal with FERC by early September, get FERC permission on the plan by early November and close the currently open-ended 2023 queue application window in late November or early December, months later than usual. MISO has been keeping the 2023 queue deadline fluid while it works out how it can make its bursting-at-the-seams queue more scalable.

Witmeier said it’s currently much too easy for speculative projects to enter the queue and then drop out penalty-free, getting “all their money back with interest.” He said MISO needs to “weed out” the number of submissions.

He said withdrawn projects should be on the hook for some fees for disturbing other projects’ network upgrade cost estimates.

Witmeier also said MISO’s $4,000/MW second milestone payment could be ratcheted up to about $10,000/MW, considering current inflation trends and his opinion that MISO’s milestone fees are already too low in the first place.

He said in the past five to six years, MISO has levied harm payments on withdrawing projects for the consequences to lower-queued projects “fewer than a dozen times.” He said that’s evidence that MISO’s harm calculation payments are “way too lenient and need to be adjusted.”

“We are responding to consumer demand, but we realize that an unmanageably large queue doesn’t work for anyone,” Invenergy’s Sophia Dossin said.

Witmeier added that developers don’t tell MISO why they’re dropping out of the queue, whether that’s land or permitting issues or climbing network upgrade costs.

Stakeholders asked if MISO has considered limiting the number of interconnection requests or megawatt values that individual customers can submit per annual cycle.

Witmeier said that while MISO has discussed enacting a “hard cap” on individual developers, he said the RTO runs the risk of discriminatory treatment and still more proposed generation than MISO load can snap up. He said large developers typically account for only about a third of queue submittals and are often better prepared than their smaller counterparts when submitting projects.

“It would certainly help competition but is that better?” he asked hypothetically.

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Washington Lawmakers Field Ideas on Shifting from Guzzlers to EVs

Pickup trucks, vans and SUVs account for a disproportionate share of the gasoline consumed in Washington state.

On Tuesday, an engineering and consulting firm offered state lawmakers on the Senate-House Joint Transportation Committee ideas on how to replace those gas guzzlers with electric vehicles.

Jeff Doyle, a project technical leader from the Seattle office of Boston-based CDM Smith, told lawmakers that 10% of Washington’s vehicles account for 26% of the gasoline consumed in the state. Meanwhile, 6.3% of the state’s vehicle burn more than 1,000 gallons of fuel a year — the majority of those being pickup trucks, vans and SUVs.

The owners of those so-called “high-consumption fuel users” value them for their hauling and towing, Doyle said. Also, they are used for heavy commuting, rideshare programs and delivery services.

CDM Smith provide four suggestions to encourage owners of those heavy fuel users to switch to EVs:

        • Incentivizing owners to lease EVs for trips that don’t require medium-duty capacity. CDM Smith said the heavier vehicles average 25,000 miles annually, compared with an average of 9,000 miles a year for all vehicles. The incentives could be based on miles driven in the leased EVs.
        • Incentivizing trade-ins of fuel-burning pickup trucks and vans for EVs. The incentives could be based on miles driven annually in the new vehicles or on how much fuel is expected to be saved by switching to electric.
        • Creating a program in which drivers switch to EVs but are provided financial assistance to rent high-consumption fuel users when they need a vehicle to haul or tow. This program would be phased out as more medium-duty electric trucks and vans hit the market.
        • Providing rebates to all drivers — light- and medium-duty — to install electric chargers at their homes. The State Legislature has already exempted such installations from the state’s sales tax.

According to CDM Smith, gas-powered vehicle models still far outnumber EVs on dealer lots in the U.S. The company’s breakdown showed:

        • 138 models of gas-powered light-duty cars, compared with 25 EV models;
        • 174 models of gas-powered SUVs, compared with 22 electric models;
        • 34 models of gas-powered pickup trucks, compared with four electric;
        • 23 models of gas-powered vans, compared with one electric.

CDM Smith acknowledged that EVs are currently more expensive than gas vehicles but said their price tags are shrinking.

While some lawmakers asked clarifying questions on the presentation, none offered comments.

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NY Completes Smart Path Tx Upgrades

ALBANY, N.Y. — New York on Tuesday finished upgrading 78 miles of transmission lines that will enable the reliable transmission of clean energy from the north to the rest of the state.

The Smart Path project rebuilt and replaced aging transmission poles made from wood with steel ones capable of supporting 345 kV lines, as well as upgraded substations along the project’s path (18-T-0207).

The $484 million worth of upgrades span from Massena in St. Lawrence County to Croghan in Lewis County and were undertaken by LS Power Grid New York and the New York Power Authority (NYPA).

The newly energized Moses-Adirondack Smart Path line will operate at the 230 kV level until the completion of the attaching Smart Path Connect project, which rebuilds roughly 100 miles of transmission lines in the North Country and the Mohawk Valley.

The Smart Path Connect project is a partnership between NYPA and National Grid and construction is scheduled to run until December 2025.

These Smart Path projects are among the many transmission projects New York is developing to support its growing clean energy fleet. The announcement mentioned the Propel NY transmission proposal, which was selected by NYISO’s board to enable the delivery of offshore wind energy from Long Island to the rest of the state. (See NYISO Board Selects NYPA-Transco Project for Long Island Tx Needs.)

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The office of New York Gov. Kathy Hochul announced the completion of Smart Path and included statements from several high-ranking officials.

Justin E. Driscoll, acting president of NYPA, said, “the Moses-Adirondack Smart Path transmission line was the Power Authority’s oldest asset, built in 1942, acquired by the Authority in the early ‘50s, and now it has become one of our newest. I am immensely proud of the Power Authority team, the skilled laborers, and contractors who completed this challenging work on this major transmission artery safely under unusually difficult circumstances.”

Democratic state Sen. Kevin Parker, chair of the Energy & Telecommunications Committee, said, “we must embrace the opportunities to modernize our energy systems and invest in clean and sustainable solutions that ensure the resilience of our infrastructure, the protection of our environment, and the well-being of our communities.”

Democratic Assemblymember Didi Barrett, chair of the Energy Committee, said, “the newly completed Smart Path Transmission Project is integral to enhancing resiliency and modernizing the grid, which is necessary to achieve our climate goals, and will provide up to 900,000 homes with clean electricity.”

Bill Brown Jr., business manager of the International Brotherhood of Electrical Workers, which represents many of the workers who performed much of the specialized transmission construction like stringing lines by helicopter, also shared a comment.

“Our members will continue to offer the expertise and dedication necessary to help support Gov. Hochul and New York State in its efforts to support green energy,” said Brown.

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NYISO Selects Propel Project for Long Island Transmission

ALBANY, N.Y. — NYISO on Tuesday announced its Board of Directions selected a proposal from Propel NY Energy to fulfill the Long Island Public Policy Transmission Needs (PPTN) solicitation to unbottle local constraints and enable the export of future offshore wind energy throughout New York.

Propel NY, a partnership between the New York Power Authority and NY Transco, will build its Alternative Solution 5 project with the Long Island Power Authority and Consolidated Edison, with the goal of “advancing the state closer to its goal of 9,000 MW of offshore wind energy by 2035,” the board said.

NYISO estimated that the project will cost $3.26 billion. The developers will build a network of new transmission lines and substations connecting Long Island to New York City and estimate they will break ground in 2026. It has a required in-service date of May 2030.

Propel NY’s project (Project ID: T051) emerged as NYISO’s preference in early May and quickly obtained stakeholder votes of recommendation for approval before moving forward to the board for approval. (See “Long Island PPTN,” NYISO TPAS Briefs: June 16, 2023.)

In an interview with RTO Insider, Philip Toia, president of development at NYPA, and Paul Haering, vice president of capital investment at New York Transco, shared how excited they are to help deliver clean energy throughout New York and bring the state closer to its decarbonization goals.

Propel NY’s project “reinforces the backbone of the transmission system in Long Island,” Toia said.

It “checks a number of boxes that the NYISO evaluates, including transfer capability, expandability and operability,” said Haering.

The project will build six new underground transmission lines, including five 345-kV lines, that go between three ties connecting Long Island to the New York City metropolitan area and four new substations. It also upgrades several LIPA-operated facilities.

Haering said, “The goal of the PPTN was to improve the transfer capabilities between Long Island and New York City,” and the Alternative Solution 5 “proposal is going to greatly increase that capability” by enabling “offshore wind to get upstate” while “improving the ability for energy from upstate to get back onto Long Island when the wind isn’t blowing.”

Toia said there could be a few challenges, including unclogging an already a congested Long Island transmission system, getting community stakeholders involved via consistent outreach and permitting processes.

Haering noted ongoing supply chain disruptions also could be problematic should key components like high-voltage cables become unavailable. He added that their teams have worked aggressively to ensure that all the manpower, resources and equipment are available to execute the project.

Transmission projects in general, particularly those in crowded regions such as New York City and its eastern suburbs on Long Island, can draw opposition and pushback. Propel NY is taking an “early, often and inclusive” stakeholder approach to build support and head off opposition, Haering said.

Shannon Baxevanis, communications and stakeholder lead at NY Transco, said, “For the last two years, we’ve been undertaking an education and awareness effort with stakeholders that are within the [project’s] geographic footprint.”

Baxevanis said these have mostly been high-level conversations with politicians, economic development organizations, and environment or advocacy groups, but “that will really morph into a more developed granular ground game.”

“We are going street-by-street, neighborhood-by-neighborhood, getting to know residents, making them aware of what the project is and giving them the conduit to have a voice in our process,” she added.

Haering applauded the PPTN process, saying, “It is the poster child for how it should be done.”

Toia added, “We have confidence in the [PPTN’s] open process,” and, “when you look at New York, there’s a multitude of pathways for transmission to be built. … It’s an all-hands-on deck approach that has been successful for the state.”

RTO Insider asked about renewable and offshore wind development more broadly and whether New York could achieve its ambitious decarbonization goals.

Toia admitted the goals are aggressive but was confident that they could be reached via effective transmission development.

“Transmission is key to ensuring that renewable energy that is being built is able to get to the market and is not bottlenecked anywhere,” he said.

Haering pointed out that “because of our knowledge of the system, it was recognized by NYISO and its independent consultant that our project had some of the least amount of risk as compared to some of the other proposals,” and so, “hopefully that means this project will be delivered on time and on budget for the benefit of ratepayers.”

Haering said they anticipate filing relevant Article VII paperwork, which is the application material required for major New York transmission facilities, with the state’s Public Service Commission in the first half of 2024.

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DOE Under Secretary: Industrial Decarb Should Happen This Decade

WASHINGTON ― David Crane is serious about deadlines. As director of the Department of Energy’s Office of Clean Energy Demonstrations (OCED), one of his first jobs was turning down requests from 12 governors ― many of them Democrats ― to extend the deadline for concept papers for regional hydrogen hubs to be funded with $7 billion from the Infrastructure Investment and Jobs Act.

“Of course, all these Department of Government Relations folks … they’re like, ‘Of course we’re going to do that,’” he recalled during a “fireside chat” at the Bipartisan Policy Center (BPC) on June 14. “I’m like, ‘Hell no! We’re not going to do that,’ and we didn’t delay. … I’m not slowing down for anything or anyone. …”

“We have $20 billion in active solicitations out there right now,” said Crane, who was CEO of independent power producer NRG from 2003 to 2015. “[For] all that money, the people will be selected by the end of the year. So, the government is moving fast. The government is moving at private sector speed. So, it’s time to put up or shut up.”

Crane had come to the BPC straight from DOE, where he had just been sworn in as the agency’s first under secretary for infrastructure, confirmed by the Senate on a 56-43 vote on June 7.  On top of the OCED, he will now also oversee the Loan Programs Office and other initiatives funded through the Infrastructure, Investment and Jobs Act (IIJA), with a special focus on industrial decarbonization.

In addition to the hydrogen hubs, OCED’s portfolio of projects includes large-scale carbon capture pilots, regional direct air capture hubs, advanced nuclear reactor demonstration projects and long-duration energy storage projects. The final applications for the hydrogen hubs were due April 7 ― again, with no deadline extensions ― and announcements on selected projects are expected in the fall, according to the latest OCED update.

Crane’s conversation with Sasha Mackler, executive director of BPC’s energy program, capped an event focused on the future outlook for U.S. energy innovation, and the work of the BPC-sponsored American Energy Innovation Council (AEIC). Launched in 2010 by Microsoft founder Bill Gates and other non-energy CEOs, the AEIC has advocated for more public funding for the research and development needed to bring new energy technologies from the lab to the marketplace.

Even with the billions for energy innovation in the IIJA and the Inflation Reduction Act, government funding can still be critical for getting emerging technologies over the “valley of death,” the gap in funding between proof-of-concept and commercialization, said Norman Augustine, former CEO of Lockheed Martin and another AEIC founding member.

“One of the problems of energy [is] once you’ve got a laboratory prototype, you’re a long way from knowing, one, that you could scale it and, two, where it’s useful, and perhaps more importantly … is it economically viable,” Augustine said, during a panel discussion on the history of the AEIC and the evolving state of energy innovation.

“The basic assumption here is that industry has got to be the ultimate user” of innovative technologies, he said. But to advance new technologies at scale and unlock private investment will require government support minus government bureaucracy, he said.

Crane sees at least part of the solution in a new approach to public-private partnerships. “We’ve introduced something I call, ‘the credo,’ where it’s transparency, it’s replicability, its urgency, it’s shared success and it’s timeliness,” he said.

The focus on speed here is meant as a message to the private sector, Crane said. “If there’s anyone … who thinks that they’ve got time to just ponder whether they want to work with the government, you are sadly mistaken.”

The energy transition is going to be private-sector-led, but “government-enabled and government-accelerated,” he said.

‘Air of Inevitability’

Crane has a history of energy industry disruption, going back to his tenure as CEO of NRG Energy from 2003 to 2015. Under his leadership, the company began closing coal plants and deployed a number of renewable energy projects, including the Ivanpah concentrated solar project, which placed thousands of reflecting mirrors and three massive solar power towers in the Mojave Desert.

Crane was fired from NRG in December 2015, after the company’s stock price tumbled 63% in 11 months — a history that provoked tough questioning from Democrats and Republicans during his confirmation hearing before the Senate Energy and Natural Resources Committee in November 2022.

Crane defended his record, noting that a number of independent power producers had seen similar losses at that time, and that his long experience “at the intersection of big capital and big energy projects” gave him the skill set needed at the OCED. (See Former NRG CEO Faces Tough Questions at Senate ENR Hearing.)

With confirmation now behind him, Crane next wants to push heavy industry and heavy-duty land transportation sectors to raise their ambitions and cut their timelines for decarbonization.

“When the environmentalists labeled aluminum, steel, concrete, chemicals [and] petrochemicals as hard-to-abate sectors, they gave those industries sort of an easy pass to deep decarbonization in the 2030s, not the 2020s,” he said. With $6.3 billion in IIJA funding, Crane wants to kick industrial decarbonization timelines back into the 2020s.

“We need to create an air of inevitability that these things are going to happen so that everyone’s moving in the same direction,” he said. While the industry will always have first movers and fast followers that do early projects, “we just don’t want a lot of slow-moving laggards,” he said.

Creating early-stage demand for emerging technologies, like green hydrogen, will be another challenge, Crane said. He called the IRA “pretty inspired legislation,” but noted that “it mainly sort of [incentivizes] supply, and the history of energy … is that demand formation always lags supply.”

Crane pointed to DOE’s Clean Hydrogen Commercial Liftoff report, which identifies a buildout of hydrogen infrastructure ― first hubs and then wider storage and distribution systems ― as critical for unlocking new commercial applications and, ultimately, investment.

While not providing details, Crane said this kind of demand-building is a priority for DOE, the White House and other agencies.

Global Challenges

Speaking on the panel, Tom Steyer, co-executive chair of climate-focused investment firm Galvanize Climate Solutions, sees a similar sense of inevitability forming around the deployment of clean energy in the coming decade.

Permitting, supply chains and other logistical barriers notwithstanding, solar and wind will be the dominant energy sources, said Steyer, who briefly ran for president in 2020. At the same time, emerging technologies “where we have the technologies but not the market acceptance” will be facing “the same challenges about getting to scale.”

But Steyer sees impending growth in “the level of human capability in this sector. The number of people ― whether they’re repeat CEOs, entrepreneurs, venture [capitalists], young people coming out of college, grad school or just wanting to work in these areas ― [is] fantastic,” he said.

“Companies that have the technology, but need product-market fit to scale, that is going to be so much better than people broadly know,” Steyer said. “I think it’s going to knock people’s socks off.”

Steyer stressed that U.S. energy innovation must also respond to the global challenges of less developed and emerging economies in the Southern Hemisphere, where millions of people have no regular access to electricity, emit relatively small amounts of greenhouse gases but may be particularly vulnerable to the impacts of climate change.

“We have to develop and drive down these cost curves and have technology that is available to people in those countries so that it’s a good deal for them to do clean; it’s a good deal for them to build the structures that will not emit” GHGs, he said.

402 Days

For Crane, the obstacles ahead are political, technical and temporal. With congressional Republicans and some Democrats scrutinizing every IIJA and IRA dollar DOE is spending, he said, OCED is “parsing every word” in each of the statutes.

“If it’s in the statute, we do it exactly as the statute says,” he said.

Such scrutiny, however, may run into the technical and market realities of scaling new technologies. “None of these emerging clean energy scale-ups are going to go exactly as you say; so, you’ve got to be prepared,” Crane said. Federal, state and local policy —both mandates and incentives — will be needed to create markets for new technologies.

“Not everything we’re going to do is going to work,” he said, calling instead for a “portfolio” approach to innovation and risk. “We’ve got to be prepared to try some things. … If nothing we ever do fails, then we didn’t take enough chances.”

And the clock is ticking. Speaking at Crane’s swearing-in, Energy Secretary Jennifer Granholm reminded DOE staff that they have 402 business days until the end of the current administration in January 2025.

“That puts us all on a war footing, moving at an impossible pace,” Crane said. “We’re not taking anything for granted.”

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NJ BPU Outlines $150M Building Decarbonization Plan

The New Jersey Board of Public Utilities has released a $50 million-a-year, three-year plan to cut building carbon emissions by prioritizing a shift from delivered fossil fuels to electric heat pumps.

The proposal, which would work in conjunction with energy efficiency (EE) programs, outlines a series of possible building decarbonization (BD) start-up programs that target single and multifamily residential buildings as well as commercial buildings, placing a priority on low- and moderate-income customers.

The proposal arrives as state efforts to cut building emissions face resistance from the fossil fuel sector as well as business groups concerned about cost and whether the state will force building owners to make the transition.

The plan follows the strategy outlined in the state’s 2019 Energy Masterplan, which calls for buildings to be “decarbonized and largely electrified by 2050,” with fossil-fuel heating boilers and water heaters replaced by electric space heating and cooling systems and water heaters.

The decarbonization straw proposal is one of three plans in the second, three-year program cycle developed by the BPU, known as Triennium 2, to create energy efficiency and carbon emissions reduction programs as required by the New Jersey Clean Energy Act of 2018. (See NJ’s 3-year Energy Efficiency Plan Faces Scrutiny.) Another proposal released as part of Triennium 2 sets out the general goals and incentive mechanisms and a third part lays out demand response proposals.

“New Jersey’s ambitious greenhouse gas reduction goals require significant reductions in emissions from buildings on a rapid trajectory,” the proposal states. “This BD program is being launched as a first step towards large scale transformation in New Jersey’s buildings sector, while recognizing the likely market transformation that will result from federal EE and heat pump rebates.”

Working With Utilities

Joseph L. Fiordaliso, president of the BPU, called the proposal “an important step to work with utilities to measure and consider both energy savings and building emissions.”

The programs outlined in the proposal include:

    • the “design, launch and test” of programs offered by utilities to target the installation of space and water heating appliances in the residential and multifamily sectors, with a priority on low- and moderate-income customers;
    • a solicitation of programs to be offered by utilities to the commercial sector to encourage the switch to electric heat pumps, including proposals to encourage smaller commercial buildings to make the change, possibly incorporating district geothermal systems;
    • the development of “programmatic infrastructure to effectively market, deliver and track BD program impacts and costs;”
    • strategies to increase “market knowledge, infrastructure and capacity” to accelerate the shift to building decarbonization, and reduce the cost of pursuing it; and
    • an effort to collect performance and “market transformation-related metrics” and prepare evaluation studies.

The BPU staff’s intent in compiling the program proposals was to “initiate programs of large enough scale in Triennium 2 to achieve some material economies, market adoption, and lessons learned, while managing the total cost to a target level that is well below that of EE programs,” the proposal states.

The state estimates the BD programs combined will cost $50 million a year for three years, allocating the funds to the state’s four utilities in relation to the portion of territory they serve.

Seeking ‘Climate Friendly’ Technologies

The release of the proposal follows Gov. Phil Murphy’s unveiling in February of a sweeping package of new clean energy initiatives that called for all electricity sold in the state to be clean energy by 2035, rather than the previous goal of 2050. The package also called for the state to install electric heating and cooling equipment in 400,000 homes and 20,000 commercial properties by 2030. (See NJ Governor Sets Out Accelerated Emissions Targets.)

In a separate initiative, Murphy created a Clean Buildings Working Group to study the issue. (See Murphy Outlines NJ Building Electrification Push.)

Commercial and industrial buildings emit 17% of the state’s greenhouse gases, well behind transportation (42%) and electricity generation (19%), according to the state’s National Electric Vehicle Infrastructure plan.

The shift to electricity has stoked resistance from business groups, which worry about the cost and express concern that the state will “mandate” a shift to electrical heating and hot water. They back a bill, S2671, that would prohibit any state agency from mandating the use of electric building energy systems until the release of a government report on the costs and benefits of electric heating.

So far, however, the bill has not advanced in either house. State officials say there is no such mandate, and they will drive the transition by persuading the public of the benefits of electric heating and water delivery and by offering incentives.

Fossil fuel interests say the state should explore alternatives before plunging into what they say will be a highly expensive bet on electricity. And the New Jersey Department of Environmental Protection backed off introducing a ban on new commercial-size fossil fuel boilers in a rules package enacted in January after opposition from business and fuel groups. (See NJ Backs off Ban on Commercial-size Fossil Fuel Boilers.)

Catherine Klinger, executive director of the Governor’s Office of Climate Action and the Green Economy, said the plan would “increase utility customers’ access to money-saving energy efficiency measures and climate-friendly heating and cooling technologies.”

“Comfortable building temperatures should not create emissions that contribute to the climate crisis,” she said. “Utilities will be asked to help educate customers about the benefits of home electrification and open up access to federal incentives that put money back into customers’ pockets when they adopt heat pumps.”

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NYISO TPAS Briefs: June 16, 2023

Long Island PPTN

The NYISO Transmission Planning Advisory Subcommittee on Friday voted to recommend that the system impact study report results for Propel NY Energy’s Alternate Solution 5 project be approved by the Operating Committee.

Propel NY, a partnership between the New York Power Authority and New York Transco, proposed to build a transmission project to unbottle Long Island and enable the area to export offshore wind energy to the rest of the state as part of NYISO’s Long Island Public Policy Transmission Needs solicitation.

Propel NY’s Alternate Solution 5 proposal recently emerged as the ISO’s preferred project. (See “Long Island PPTN,” NYISO Business Issues Committee Briefs: May 24, 2023.)

System and Resource Outlook

NYISO announced it has kicked off this year’s annual System & Resource Outlook study and anticipates having the report finished by the second quarter of next year.

The outlook report forecasts system needs for 20 years, identifies challenges related to achieving New York’s policy objectives and builds upon past recommendations or observations. (See “NYISO Releases the Outlook,” NYISO OC Discusses NOPR Comments, High Temps, EDS Results.) It is part of the economic planning process of NYISO’s wider Comprehensive System Planning Process, and the ISO will spend upcoming meetings reviewing study assumptions, benchmarking results and discussing potential improvements.

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DC Circuit Overturns EPA Hydrofluorocarbon Rule

EPA will have to rework a recent rule implementing a cap-and-trade program on hydrofluorocarbons (HFCs) used in air conditioners and refrigerators after a court ruling on Tuesday.

A majority of a three-judge panel of the D.C. Circuit Court of Appeals found that the agency exceeded its statutory authority by requiring the industry to adopt a system of refillable containers that could be tracked with QR codes so it could effectively track overall HFC use.

Judge Justin Walker wrote the majority opinion, joined by Judge Karen LeCraft Henderson. Judge Cornelia Pillard wrote a partial dissent on the refillable cylinders issue, agreeing with her colleagues in rejecting other challenges to EPA’s rule.

HFCs are greenhouse gases that, the agency said, “can be hundreds to thousands of times more potent than carbon dioxide.” They have been used for cooling technologies since Congress required the industry to phase out chlorofluorocarbons in 1990, which were depleting the ozone layer.

“That prompted a shift to HFCs,” the majority decision said. “But Congress’ change swapped one environmental hazard for another.”

Congress in 2020 passed the American Innovation and Manufacturing Act, which required EPA to issue a rule phasing down HFCs through a cap-and-trade program. The law provided an outline for how that program will work, leaving the agency to fill in the details.

EPA is required to calculate the baseline levels of HFC production and consumption in the U.S. and then cap maximum production and consumption at a percentage of those baselines, with the aim of capping the gas at 15% in 2036. The agency hands out allowances to HFC users initially, but users can buy and sell them from one another to adjust their production or consumption capacity.

While it rejected two other challenges, the two-judge majority found that EPA exceeded its authority by requiring QR codes and refillable cylinders. The law lays out the rate of decline for the cap and tells EPA to “ensure” that happens, but the majority said the agency read too much into the word “ensure.”

Congress just wanted the agency to ensure that the annual cap was not exceeded, the majority ruled; it did not tell the agency how to get that done in that section of the law, but it did offer detailed instructions in other parts. The QR codes and refillable cylinders were expected to cost the industry between $441 million and $2 billion.

“Congress’ exhaustive instructions to the agency throughout the AIM Act make it less plausible that Congress meant the words ‘shall ensure’ in (e)(2)(B) to give the EPA broad power to pass new rules,” the majority said.

The majority’s decision did not rest on the “major questions” doctrine from West Virginia v. EPA, which was issued by the Supreme Court last year. (See Supreme Court Rejects EPA Generation Shifting.) Instead, the court relied on an older precedent from Whitman v. American Trucking Associations, which held that Congress does not alter the fundamental details of a regulatory scheme in vague terms or ancillary provisions.

“Ordinary readers of English do not expect provisions setting out math equations to empower an agency to prescribe other ‘fundamental details of a regulatory scheme,’” the court said. “Because the EPA’s interpretation of (e)(2)(B) seeks to do just that, it strains against the ordinary use of language.”

Pillard’s partial dissent would have sided with EPA on the QR code and refillable cylinder issue, saying they are valid regulations meant to ensure compliance with Congress’ directive.

“The agency determined that, to accomplish the HFC phasedown, it was necessary to require refillable cylinders with unique, trackable QR codes, so it promulgated a final rule to that effect,” Pillard wrote. “After all, requiring refillable and trackable cylinders is a straightforward way to ‘ensure’ that the regulated substances they contain correspond to allowances the statute requires. Without such tools, it is hard to see how EPA can ensure the phasedown.”

The majority decision will make it harder for EPA to “combat illicit trade,” making it less likely that the U.S. achieves the HFC cuts directed by Congress, she wrote.

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Texas PUC Ponders Market Design’s Next Steps

During their first open meeting since the recently concluded legislative session, Texas regulators discussed their next steps in changing the ERCOT market.

Texas legislators sidestepped the Public Utility Commission’s proposed performance credit mechanism (PCM) that would pay dispatchable generators credits for being available during peak demand. Instead, they capped the PCM’s costs at $1 billion annually and passed a measure that creates a $5 billion taxpayer-funded low-interest loan program for developers who want to build gas-fired generation. (See Clean Energy Escapes Texas Legislature’s Wrath.)

To help the PUC refocus and redouble its efforts, Commissioner Will McAdams filed a memo outlining the short-term operational flexibility challenge and the long-term resource adequacy problem facing the Texas grid.

“As the session has concluded, as we now know what tools we have available in our toolbox and also to bring forward a previously filed suggested framework on reliability standards,” he said during the commission’s June 15 meeting.

McAdams reminded his fellow commissioners that the operating reserve demand curve (ORDC) retains and attracts sufficient installed capacity but that the increased penetration by wind, solar and battery resources requires additional operational flexibility. He said ERCOT’s recent heavy use of reliability unit commitments (RUC) as part of its conservative operations posture is not the answer.

Instead, McAdams suggested using a multistep floor for the ORDC that ERCOT proposed as part of its bridge to the PCM. Adding one floor at 6,500 MW of remaining reserves and a second at 7,000 MW would address the disconnect between conservative market operations and price signals to generators, he said, pointing to the ISO’s modeling that indicated applying this change in 2020 and 2022 would have resulted in annual revenues of about $500 million to primarily dispatchable resources.

“Ultimately, I believe these solutions work in tandem with the PCM,” McAdams wrote in his memo. “The adjustment to the ORDC bolsters reliability in the real time energy market, changes to ancillary service products help the day-ahead market and [create] more operational certainty, while the PCM shores up long-term planning and reliability as an availability market.

“We are at the forefront of a major energy transition. Renewables are here and more are coming,” he said during the open meeting. “The effect is having the grid operator, ERCOT, having to do more to harmonize the flow of power with what is increasingly becoming a dominant variable, a resource mix that is dominated by variable resources. We don’t have a capacity market in Texas, but we’ve got a heck of a lot of renewables, and so revenues associated with managing this are only going to increase into the future.”

Commissioner Jimmy Glotfelty agreed with McAdams, saying any market solution for ERCOT should rely on a market-driven mechanism that can be deployed in an “efficient, expeditious” manner.

“RUC is an out-of-market action that has a distortionary impact on the market and has a physical impact on our older, long-duration generation assets that are needed to ensure reliability,” Glotfelty said. “Secondly, the bridge, by driving generation self-commitment and the real-time market, is where we see revenues that will help cover their marginal costs, thereby providing revenue stability to help retain existing generation and incent investment in new generation.

“A bridge solution should fulfill the objective of stabilizing the market by sending a stronger market signal to incent self-commitment. I think ultimately, we have a proposed solution and I look forward to further evaluate and open meeting and taking action.”

Lake Absent After Resignation

The open meeting marked Kathleen Jackson’s first as the PUC’s interim chair. She was named to the position after Peter Lake announced his resignation June 2. (See Texas PUC’s Lake Steps Down as Chair.)

Commissioner Kathleen Jackson | Admin Monitor

“Obviously, things look a little different up here today,” Jackson said, acknowledging the empty chair to her left. The commissioners excused Lake’s absence for a personal matter, though he officially leaves the panel on July 1.

She and the other commissioners thanked Lake for his “tireless dedication” to the PUC during the months following the deadly 2021 winter storm, which nearly brought down the ERCOT grid.

“He demonstrated extremely competent and able and steady leadership during that extraordinary time,” McAdams said, “when the commission, staff, ERCOT and the industry was asked to pick ourselves up, put ourselves back together and reassure the public that that ubiquitous essential service that we call electricity will remain on and will remain reliable.”

“It certainly was one of the most critically difficult and important times in the commission’s history, and stepping into a job like that is no easy job,” Commissioner Lori Cobos said. “[Lake] did the best he could to lead our agency for the last two years and implementing all the legislation that was passed.”

Following an executive session, the commissioners agreed to request the state’s attorney general file a motion with the Texas Supreme Court regarding the 3rd Court of Appeals’ recent ruling reversing a PUC scarcity-pricing order. (See Texas Appeals Court Reverses Another PUC Order.)

The appeals court ruled June 1 that the PUC violated the state’s Administrative Procedure Act’s rulemaking provisions when it approved an ERCOT protocol change related to pricing during certain extreme events. It also agreed with the lawsuit’s appellants, RWE Renewables Americas and Hereford Wind, that the order constitutes a “competition rule” and that the PUC exceeded its statutory authority with its approval (03-21-00356-CV).

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PJM Adds Seasonal Capacity to Stage 3 of CIFP Proposal

PJM presented a comprehensive look at its proposal to overhaul its capacity market during the opening meeting of the third phase of the Critical Issue Fast Path (CIFP) process Wednesday.

The package contains many of the changes PJM has discussed over several previous meetings, including reworking its risk modeling; considering resources’ reliability contribution to mitigating seasonal risks when setting accreditation; and shifting the reliability metric to expected unserved energy (EUE) to capture the depth and breadth of a potential loss of load. (See PJM Presents More Detail on CIFP Proposal.)

PJM has scheduled an additional CIFP meeting for this Wednesday to continue presenting its proposal, after only getting through about half of the presentation in last week’s meeting. Stage 2 focused on putting forth design components, priorities and issues that stakeholders felt are in need of consideration. (See PJM Stakeholders Complete 2nd Phase of CIFP.)

The bulk of last week’s conversation centered on PJM’s addition of a seasonal capacity market to the proposal, continuing a slate of changes proposed in response to analysis that found that the worst reliability risks are shifting from summer load peaks to extreme winter weather.

Walter Graf, PJM | FERC

Senior Director of Economics Walter Graf said separate winter and summer capacity products would create a more robust market in the face of uncertain risk patterns and could resolve much of the uncertainty with creating annual accreditation, procurement targets and other auction parameters.

“We think that this is the most straightforward way of reflecting in our market design the relative needs of capacity in different parts of the year … in a way that really maximizes the value of a competitive marketplace and reduces the need for administrative decision-making,” he said.

PJM is still working through the details of what a seasonal market could look like, but Graf said there’s a lot of “low-hanging fruit” in the existing market design that could be ported over and run twice a year with minimal modification needed.

Graf said PJM views this as another potential stage in the markets’ evolution, but not the final step. Long-term changes under consideration outside the CIFP process include continuing to refine accreditation; identifying how resource performance changes with ambient temperatures; and expanding the seasonal model by increasing the number of seasons or introducing monthly or hourly granularity.

“I think once you go from one season to two, it really blows open the doors to what’s possible,” Graf said.

Steve Lieberman of American Municipal Power said stakeholders have been suggesting a seasonal market for more than a year at the Resource Adequacy Senior Task Force (RASTF), which considered many of the same topics as those in the CIFP. He argued that stakeholders had favored a seasonal design with more than two seasons and that by making major changes to the market now while eyeing future changes, it may undermine investor confidence.

PJM Vice President of Market Design and Economics Adam Keech said the RTO is focused on making changes that can address its concerns within the time frame of the CIFP process. The stage 4 meeting, when stakeholders will vote on proposals, is set for August, with a goal of a FERC filing in October.

“We’re looking at what’s doable, what’s sort of the shortest path to getting the capacity market to recognize the bulk of risks in the time that we’ve got,” he said.

Graf said the largest limitation is the number of market components that could need to be changed as more far-reaching changes to the market are explored.

“The biggest constraint here is there are many inputs to a PJM auction, whether that be one season, two seasons or more, and many planning structures that go into it. … There are many dependencies and interrelationships between the capacity markets and other things related to it. … I would say this is the biggest step we can make given those dependencies and interrelationships,” he said.

James Wilson, a consultant for state consumer advocates, said he also believes an additional season would allow for pricing capacity in the offseason when the requirement is lower and there is much excess.

PJM’s Pat Bruno said resources will have to meet eligibility requirements to offer capacity for each season. While generators would typically meet the qualifications for both, he said it’s possible some might only be able to participate for one season.

Economist Roy Shanker said that if there are winterization requirements to offer capacity for that season, and it’s optional to make the investments to meet those, that essentially undermines the must-offer requirement.

Shanker said reaching an accurate accreditation for solar resources may require creating eastern and western regions in the RTO’s footprint to account for how solar panels will be performing at different times across the grid and how that interacts with the grid’s riskiest periods.

Expanding on PJM’s rationale for using a longer 50-year historical weather lookback, Graf said staff have found that they cannot estimate an accurate 10th-percentile winter with only 10 years of data.

Ryann Reagan, wholesale markets policy specialist for the New Jersey Board of Public Utilities, questioned if the new data and risk modeling built off it would capture the type of sudden temperature drop that has been credited with contributing to lost generation during the December 2022 winter storm.

Graf said that while the dataset wouldn’t explicitly capture the relationship between forced outages and ambient temperatures, as long as the historical generator performance and weather data characterize the variables implicitly, then the modeling would show those impacts.