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.
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.”
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.)
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.”
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.
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.
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.
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).
PJMpresented 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.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
The committee will be asked to endorse proposed revisions to the PJM Tariff, Operating Agreement and Reliability Assurance Agreement, as endorsed by the Governing Documents Enhancements and Clarifications Subcommittee.
Endorsements (9:10-9:50)
Base Residual Auction Smooth Supply Curves (9:10-9:30)
PJM’s Skyler Marzewski will present proposed tariff revisions seeking to clarify that PJM will only publish smooth supply curves after Base Residual Auctions, not Incremental Auctions. The committee will be asked to endorse the proposed solution and corresponding tariff revisions. (See “First Read on Smooth Supply Curve Quick Fix,” PJM MIC Briefs: April. 12, 2023.)
PJM’s Darrell Frogg will present a proposal to create a cost-recovery mechanism for expenses related to making investments to comply with NERC Critical Infrastructure Protection standards regarding interconnection reliability operating limits. The committee will be asked to endorse the proposal and corresponding tariff revisions. (See “PJM, Monitor Review IROL-CIP Proposals,” PJM MRC/MC Briefs: May 31, 2023.)
The committee will be asked to endorse proposed revisions to Manual 15: Cost Development Guidelines to address heat input guidelines and the Independent Market Monitor’s opportunity cost calculator.
AUSTIN, Texas — The Edison Electric Institute’s annual thought leadership forum, EEI 2023, celebrated its 90th anniversary early last week with a focus on the clean energy transition and by sharing its vision of a carbon-free energy future with about 1,200 attendees.
EEI says “assessing the viability of new and emerging technologies is crucial to deploying clean energy reliably and affordably.”
It also helps to have a government or private investors willing to fund those technologies. Among those who came to Texas bearing the offer of gifts were U.S. Energy Secretary Jennifer Granholm and John Podesta, senior adviser to President Joe Biden for clean energy innovation and implementation.
The Inflation Reduction Act has given Granholm billions of dollars to hand out. The Transmission Facilitation program offers $2.5 billion for interregional transmission lines, and the Department of Energy’s Loan Programs Office can provide another $400 billion in loan guarantees. And then there’s the $10.5 billion Grid Resilience and Innovation Partnerships program to help build transmission, and that has attracted significant interest from MISO and SPP, among others. (See DOE Clears JTIQ Projects to Proceed with Funding App.)
“Do you ever remember the secretary of energy coming through one of these conventions in the past with so much resources?” Podesta asked during a panel discussion with Granholm and Portland General Electric CEO Maria Pope.
“We have so much money we want to give it away,” Granholm responded.
“Deploy! Deploy! Deploy!” a more politically correct Pope interjected.
Granholm pointed out that by one estimate, about $23 trillion of global investments will be made in clean energy by 2030.
“The question is, which nation is going to capitalize on it?” she asked. “We think you know now because of the most aggressive incentives in the world, the United States has become irresistible for investing in energy manufacturing, particularly those manufacturing plants. There’s about $200 billion of manufacturing plants that have been announced as the president took office and require a lot of electricity demand. Obviously, you are the tip of the spear.
“So please, if you haven’t already, apply for these programs,” Granholm told her audience.
“We need a transformation of the global economy and the size and scale that’s never occurred,” Podesta said, also addressing the attendees. “What can you do to help and work in partnership? I think building that energy system, taking on the challenge of increased supply of electricity so the rest of the economy can reduce its emissions as we move forward.”
“Sometimes, when you’re in the middle of history, it’s hard to tell,” Granholm said. “I guarantee that we are in the middle of this incredible moment in history that you’ll look back on and say, ‘I was in that business when we made incredible strides and set the table for us to reach these big, hairy audacious goals.’”
“Nobody wants to be building nuclear right now,” Kozeracki said. “The industry is stuck in a stalemate, where utilities are staring at reactor developers, and reactor developers are staring at their suppliers, and no one is really ready to move or make real capital decisions about building new nuclear.”
She suggested establishing a mandate for clean, firm power when there are few good options will help break the standoff.
“If we want to get serious about decarbonizing and live in a society where the lights turn on, that’s going to cost more,” Kozeracki said. “When you look at the value that nuclear provides for a resilient decarbonized grid, it means that nuclear doesn’t really have to compete with solar by itself or natural gas by itself. I think there’s this perception that nuclear is uniquely expensive or uniquely risky, or uniquely far off, but when you look at the competitor set for your clean, firm options, I actually see nuclear as having a pretty good competitive shake [at] 200 GW of that 700 or 800 GW of clean, firm capacity that we’re going to have to add to the grid by 2050.”
The loan office has shelled out about $12 billion to help Southern Power build two new units at its Plant Vogtle nuclear site. The construction is seven years behind schedule and has cost $35 billion so far. However, Kozeracki said “no one is more excited” than she is that Unit 3 is coming on line, and Unit 4 will soon follow.
Later in the week, on Friday, Southern subsidiary Georgia Power said Unit 3 has been delayed for at least another month after discovering a problem in the hydrogen system used to cool the main electrical generator. The unit’s testing is 95% complete, and it has already been generating power.
Kozeracki called for a “level of humility” around lessons learned from Vogtle, saying she is happy to talk about the controversial plant where others aren’t.
“Vogtle has a lot of lessons around ensuring that your design is complete enough before you begin construction; around ensuring that you do a detailed resource-loaded schedule before you put a shovel in the ground; around ensuring you have a quick enough turnaround in the [quality assurance] process,” she said.
“I sometimes hear people not really wanting to talk about it, and I think quite the opposite. We should all be talking about Vogtle, learning from it as much as possible and ensuring we incorporate that into new builds to ensure that we’re set up for success,” Kozeracki added.
Long-duration Storage is Key
Clean technologies will be crucial to reducing carbon emissions across the U.S. economy, several speakers said. Among the emerging clean technology is long-duration energy storage, whose proponents say could strengthen grid resilience, increase renewable power generation’s adoption and improve energy security.
“There is just no energy transition without decarbonizing the grid,” Quidnet Energy CEO Joe Zhou said during a panel discussion. “One of the harshest realities facing this transition is just how expensive it is to store electricity. Imagine going to the store and spending $10,000 on a bottle to store $1. That pretty much sums up the state of electricity storage today. We need to make that drastically cheaper.”
Enter, then, DOE’s chief commercialization officer and director of its Office of Technology Transitions, Vanessa Chan.
“We want to try to get renewables onto that grid and to do that, we need to make sure that we’re able to get the energy when the sun isn’t shining and the wind isn’t blowing,” Chan said. “How do we get that flexibility and reliability that is not present in renewables without utility storage? What do we have to do at the state and ISO level in terms of the regulatory and market changes needed to happen so that people actually get compensated for this flexibility and reliability that is being done?
“Right now, there is no business model for them,” she said. “We want to make sure that we are able to help the established players and navigate this because it’s a new thing.”
Mateo Jaramillo, co-founder and CEO of storage developer Form Energy, said he has the scars from 20 years in the battery business. His company has developed an iron-air battery that takes advantage of the rusting process to store electricity for 100 hours that he said is cost competitive with legacy power plants.
“How do [utilities] functionally replace the thermal plants that they know are going out of their system?” Jaramillo said, explaining his thought process. “To sort of prove to myself that there was something that could cost-effectively address that and really try and precisely answer the question, well, what is it that you need? How many hours do you need? Do you need eight hours? Do you need 100,000 hours? By going through a lot of analytics, I ended up settling on roughly a 100-hour duration as the duration that really solves that capacity problem.”
During the forum, Form announced it had signed a definitive agreement to sell Georgia Power a 15-MW/1,500-MWh iron battery system to come online by 2026. It is also working with Xcel Energy on a multiday energy storage project that the company’s CEO, Bob Frenzel, was only too happy to discuss.
“We’ve reached a point in [Xcel’s] penetration [of the renewable energy market] where long-duration storage is a very interesting resource for us to pursue,” Frenzel said. “We recognize that to move a technology forward, we have a role to play as a company and an industry. Doing it effectively from the standpoint of our shareholders and customers means it needs to be cost-effective.”
“What’s next for long-duration energy storage? It is starting to make real these projects and products in the market,” Jaramillo said. “The future is happening right now. It is imperative to scale up and deploy.”
Transmission Developers Get Creative
Transmission developers, faced with permitting and siting challenges that can add years to a project, are looking for innovative financing solutions that involve new partnerships. Others, like commodities trader John Arnold, a former Enron executive and a billionaire since 2007, have put their millions into building HVDC transmission lines.
“This industry kind of ran out of funders, and so that’s where I really saw the opportunity to step in,” said Arnold, who has partnered with former Clean Line Energy Partners CEO Michael Skelly to create Grid United. The joint venture has nearly a dozen projects underway or in the pipeline. (See Skelly’s Grid United Quickly Making Waves.)
“I became convinced that interregional transmission is a necessary component of [integrating renewables], and every study that has come out has shown that,” Arnold said. “When I started to come around to this in 2019 and 2020, my question was, ‘Why isn’t anybody doing this?’”
He said many of the hindrances to developing HVDC lines began falling away in recent years.
“I think it’s very clear now: Utilities that are trying to meet goals or mandates for 2030’s decarbonization need to do this,” Arnold said. “I think the permitting has gotten easier and some of the federal incentives have gotten easier. I think the big challenge in the 2010s was how do you take wind and solar from very expensive resources to being cost-competitive with natural gas. The challenge this decade is how do you take a portfolio of low-carbon generation assets and have that match the load profile from the utility space and do that with the reliability that Americans expect and demand.”
Citizens Energy, a Boston-based nonprofit founded by Joseph P. Kennedy II, has added a transmission business that helps finance projects in return for a share of the profits. The company has collaborated with San Diego Gas & Electric on a 500-kV project through California’s hardscrabble Imperial Valley.
“We partner with developer and incumbent utility, anybody that is willing to take us on and say, ‘Hey, rather than our partner financing 100% of the transmission line, let’s let Citizens finance a portion of that,’” said Joseph P. Kennedy III, the company’s managing director. “We essentially purchase a 30-year interest in the capacity of that line.”
Citizens then takes half the profits it generates from its ownership percentage and turns that over to local communities so they can invest it.
“It is the only scalable, replicable model that I know of that treats stakeholders as truly stakeholders and communities as stakeholders in the project without increasing costs, while also giving investors the same rate of return off their portfolio,” Kennedy III said.
SDG&E CEO Caroline Winn said the valley is rich with solar, wind and geothermal resources, the electricity from which now flows to San Diego.
“But because of the work that Citizens did, it immediately provided these clean energy benefits to the lowest low-income communities in the valley,” Winn said. “So they very much were a big part of the successful line in really working with stakeholders and giving back to the community. What I really saw of the Citizens model was being able to ensure that constituents and the communities that are impacted by these lines can also benefit from the clean energy that the lines are bringing.”
Pizarro, Pope to Lead EEI Board
EEI’s board of directors, comprising its members companies’ CEOs, on June 12 elected Edison International CEO Pedro Pizarro and PGE’s Pope as its chair and vice chair, respectively.
Pizarro replaces Warner Baxter, executive chair of Ameren. EEI’s chairmanship rotates on an annual basis.
EEI CEO Tom Kuhn, who is retiring at the end of the year after 35 years at the helm, thanked Baxter for his “sustained engagement and clear commitment to deliver resilient clean energy to customers” during the organization’s work with lawmakers to pass the Infrastructure Investment and Jobs Act and the Inflation Reduction Act’s clean-energy tax package.
“These historic laws are driving significant investments in critical energy infrastructure and represent an unprecedented commitment to addressing climate change and to deploying more clean energy affordably and in ways that directly benefit our customers,” Kuhn said in a statement.
Awards
EEI honored PPL Electric Utilities with the 95th Edison Award for being the first electric utility in the U.S. to install and integrate the dynamic line ratings (DLRs) on its transmission system into market operations. PPL now sends hourly day-ahead ratings forecasts to PJM’s market operations to help coordinate more efficient generation and ensure reliability.
EEI said the company’s functionalities and methodologies that it has developed and implemented while integrating DLRs into real-time and day-ahead market operations with PJM are novel for the U.S. electric power industry.
The organization also recognized Italian transmission system operator (TSO) Terna with the 2023 International Edison Award for its interconnection between Italy and France. Terna partnered with RTE, France’s TSO, on a DC line that, at 118 miles, will be the world’s longest electrical infrastructure, crossing the Alps. The line is fully integrated into existing road infrastructures with “zero impact” on the surrounding environment, according to EEI.
EEI’s Thomas F. Farrell II Safety Leadership and Innovation Award went to CenterPoint Energy’s Al Payton (member company executive), Florida Power & Light’s Joe Suarez (member company employee leader) and Duke Energy (organization).
Continuing its recent trend, FERC on Thursday found that another set of transmission providers had mostly complied with Order 881 but failed to adequately explain their timelines for calculating and submitting ambient-adjusted line ratings (AARs), as the order requires.
The transmission owners and operators that FERC told to submit additional compliance filings for AAR timelines included ISO-NE and its participating transmission owners (ER22-2357, ER22-2467), MISO (ER22-2363), Idaho Power (ER22-2292), Public Service Co. of New Mexico (ER22-2335), Puget Sound Energy (ER22-2361) and Golden Spread Electric Cooperative of Amarillo, Texas (ER22-2161).
The decisions followed a similar grouping of orders in April in which FERC found that a handful of transmission providers, including NYISO and Arizona Public Service, had not complied with Order 881’s timeline requirements. (See FERC Approves Batch of Line Ratings Compliance Filings.)
In each of the cases, FERC acknowledged that software and other implementation tools are still being developed, so that “timelines may not be determined until closer to AAR implementation and that additional time may be necessary to comply with this requirement.”
Order 881 takes effect July 12, 2025. The commission gave the parties until November 2024 to submit further compliance filings.
Issued in December 2021, Order 881 requires transmission providers to employ AARs for short-term transmission requests of 10 days or less on lines affected by air temperatures. Seasonal ratings will be required for long-term service.
The commission said the current practice of rating lines based on conservative assumptions about worst-case weather scenarios has caused underutilization of available transmission capacity and driven up wholesale electricity prices. (See FERC Orders End to Static Tx Line Ratings.)
FERC did not specify timelines by which transmission providers must submit their AARs. Instead, it said transmission providers “already manage similar timing issues” for load forecasts, renewable generation and generation bid deadlines.
“It may be that the deadlines for AAR calculation and submission are not significantly different from existing deadlines for submission of updates to generation supply offers and load,” FERC repeated in its recent orders.
FERC found additional compliance problems in some of Thursday’s cases.
Citing Order 881’s requirements, it directed ISO-NE to revise its filing to “specify that transmission service at ISO-NE’s seams use AARs as the basis for evaluation for near-term transmission service requests or explain why it should not be required to do so.”
The commission found that proposals by ISO-NE and its transmission owners related to a transmission line ratings database fell short.
In MISO, FERC instructed the ISO to address “whether or how its proposed tariff language requires MISO to use updated AARs” in its day-ahead and real-time markets, including reliability unit commitment and look-ahead commitment processes, as required by Order No. 881.
It gave MISO 60 days to update its filing.
MISO has said it plans to function as a ratings clearinghouse for real-time and forecasted AARs by gathering “all known line-rating information, including from neighboring reliability coordinators,” and sharing that information with interested parties.
Late last year, MISO said its top priority for Order 881 compliance was creating an interface for its transmission owners to submit variable ratings starting as soon as the fourth quarter of 2023. Two of its transmission owners (TOs) started AAR pilot programs in 2022, with more to follow this year.
