In what’s beginning to feel like déjà vu, Cardinal-Hickory Creek’s last unconstructed mile again is subject to a preliminary injunction.
Last week, U.S. District Judge William Conley granted conservation groups’ preliminary injunction request, preventing American Transmission Co., ITC Midwest and Dairyland Power Cooperative from finishing the 102-mile, 345-kV line’s final stretch through a wildlife refuge.
The injunction halts the land exchange of more than 35 acres in Grant County to add to the Upper Mississippi River National Wildlife and Fish Refuge for almost 20 acres of the existing refuge in Clayton County, Iowa, to be cleared for the line.
The Driftless Area Land Conservancy, Wisconsin Wildlife Federation and National Wildlife Refuge Association filed the latest lawsuit on the controversial line earlier this month, charging that the U.S. Fish and Wildlife Service, U.S. Rural Utilities Service and U.S. Army Corps of Engineers violated three federal laws when they approved permits and greenlit the land exchange to assemble the final mile-long stretch of the 102-mile, $650 million transmission line through the Upper Mississippi River National Wildlife and Fish Refuge. (See Conservation Groups File Another Lawsuit to Stop Cardinal-Hickory Creek’s Last Mile.)
The parcel swap was OK’d by the U.S. Fish and Wildlife Service (FWS) and set to occur March 22, with ITC and Dairyland positioning construction equipment near the refuge’s edges.
Conley said he would like to see documents that give more insight into the lead-up to the land deal’s approval. The conservation groups said Conley implemented a “stopgap measure to prevent irreversible destructive activity in the refuge while he awaits an administrative record.” Attorneys for both sides will have 30 days to submit briefs.
In a statement, Driftless Area Land Conservancy (DALC) Executive Director Jennifer Filipiak said her organization is thankful for the judge hitting “the pause button.”
“DALC has consistently maintained that it is inappropriate to cross a National Wildlife and Fish Refuge with this massive transmission line. The transmission companies did not evaluate alternative crossings outside of the refuge in their environmental impact statement, and we should not set a precedent that a simple land swap is all it takes to plow through a national treasure,” Filipiak said.
Environmental Law and Policy Center Executive Director Howard Learner, representing the conservation groups, said he’s confident the groups will prevail. In a statement, Learner said FWS shouldn’t be free to “create statutory loopholes with a land exchange.” He warned of a “dangerous precedent for running more massive high-voltage powerlines through other protected National Wildlife Refuges.”
Learner argued in front of Conley last week that FWS didn’t offer the public the opportunity to comment on its February finding that the land exchange wouldn’t significantly affect the refuge.
However, Reade Wilson, a U.S. Department of Justice attorney representing FWS, responded that the agency wasn’t obligated to solicit public opinion on the no-impact decision.
ITC Midwest and Dairyland Power Cooperative criticized the injunction and said Cardinal-Hickory Creek is “a backbone project for the Midwest’s regional power grid that is necessary to improve grid reliability, lower consumer electricity costs and enable renewable energy to be brought to market, resulting in a significant reduction in carbon emissions.”
American Transmission Co. has built and energized its eastern portion of the line.
The two developers also repeated their assertion the wild refuge will be better off — and larger — because of their land offer of prime habitat.
“This latest lawsuit, which is misguided at best, only serves to delay completion of this important energy infrastructure and further increase costs to customers. The plaintiffs have raised meritless arguments in multiple cases, all of which have been rejected. This is just another attempt by plaintiffs to sideline this critical 345-kV tie between Iowa and Wisconsin,” ITC Midwest President Dusky Terry said in a statement.
ITC and Dairyland pointed out that the Cardinal-Hickory Creek project has survived multiple lawsuits in state and federal court from the same conservation groups seeking to stop construction.
“The co-owner utilities have successfully navigated no less than three separate injunctions, won appeals before the Wisconsin Supreme Court and received three different favorable opinions from the U.S. Court of Appeals for the Seventh Circuit,” ITC and Dairyland wrote in a statement.
The U.S. Department of Energy on March 25 announced $6 billion in funding for 33 projects that are meant to help decarbonize difficult-to-abate, energy-intensive industries.
The money comes from both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act and is meant to accelerate the commercial-scale demonstration of emerging industrial decarbonization technologies that are crucial to meeting the Biden administration’s long-term goals to cut emissions.
“Spurring on the next generation of decarbonization technologies in key industries like steel, paper, concrete and glass will keep America the most competitive nation on Earth,” Energy Secretary Jennifer Granholm said in a statement. “These investments will slash emissions from these difficult-to-decarbonize sectors and ensure American businesses and American workers remain at the forefront of the global economy.”
The projects focus on the highest emitting industries, including aluminum, iron, steel, cement and concrete, chemicals and refining. Altogether, they are expected to avoid about 14 million tons of CO2 each year, which is equivalent to taking 3 million internal combustion cars off the road.
While the electric industry has seen a lot of progress when it comes to getting renewables onto the grid, many of the industries impacted by DOE’s funding announcement need technologies that at least have yet to be proven at scale, Jeffrey Preece, the Electric Power Research Institute’s director of research and development, said in an interview.
“They can’t go and procure alternatives that they have today that meet the low-carbon future while also meeting affordability, reliability and, in these cases, supporting their bottom lines,” Preece said.
Industries like concrete, chemicals and steel making compete globally, and they need economic alternatives available, he added.
Many of the projects will deploy technologies that have never been used domestically and have the potential to be adopted across the entire sector, which multiplies the magnitude of potential emissions cuts, DOE said.
“Some of these technologies are likely to play a role across many different industries,” Preece said. “So, it’s not necessarily creating unique pathways for one industry, but there should be opportunities to share more broadly to help other industries.”
Industry contributes nearly one-third of the country’s emissions, and the federal investment will use more than $20 billion to demonstrate commercial-scale decarbonization needed to move industry toward net-zero emissions, DOE said. The projects will cut emissions at the various sites by an average of 77%.
The sector’s complex decarbonization challenges will require specific and innovative solutions that use multiple pathways, including efficiency, electrification and alternative fuels, and feedstocks, such as clean hydrogen.
EPRI has estimated that about 50% of industrial demand could be met with electricity, which would mean significant new load for the power industry, but Preece said some applications work better with other energy sources, and all of those are running on fossil fuels.
“Heavy industry generally requires firm, baseload electricity supply,” Preece said. “And various industries rely on heat sources … that are best served by a fuel.”
While all the industries can benefit from ramping up their efforts around energy efficiency, a lot of work on deploying new alternatives such as hydrogen, carbon capture and storage, and advanced nuclear needs to be done in the next couple of decades.
“If history is our guide, it can take decades to commercialize technologies,” Preece said. “Looking at today’s power generation assets, to your other energy projects, from concept to pilot testing, to first-phase deployment of large-scale, repeatable, replicable commercial deployment, it can take 20-plus years for technology to go from start to fully commercial.”
Many of EPRI’s efforts are focused on trying to speed up that process because avoiding the worst impacts of climate change means significant cuts in CO2 emissions by midcentury, he added.
“The question becomes: How do we do that in a way that doesn’t move one area too quickly and forces an issue in affordability and reliability?” Preece said. “So, our approach to that is working with industrial clusters, hubs, regional groups of industry and power generation, and communities to help assess what technologies might be most impactful for their decarbonization goals and their regional energy supply and use scenario.”
DOE noted that it still has to go through a negotiations process with the projects, and it “may cancel negotiations and rescind the selection for any reason during that time.” Lead applicants can also change during those negotiations. If awarded funds, the projects will go through a phased approach with a number of “go/no-go” decision points where DOE can evaluate the implementation progress.
“Industrial decarbonization is a pathway to creating new jobs, increasing American manufacturing competitiveness, improving local communities and protecting our climate,” Renewable Thermal Collaborative Executive Director Blaine Collison said in a statement. “The Department of Energy’s awards today are important partnerships that will help deliver all these benefits to our people, our economy and our environment. These DOE-industry collaborations will help drive transformation and scale.”
The funding goes hand in hand with other policy measures such as “buy clean” incentives, CeCe Grant, director of the Sierra Club’s Industrial Transformation Campaign, said in a statement.
“We are excited for private industries to take a leading role in cleaning up our industrial sector and will work to ensure that fenceline communities and workers have a real seat at the table to shape the vision for a just transition,” Grant said.
Citing “glaring exceptions and vague requirements” with the proposed cold weather standards submitted by NERC last month, members of the ISO/RTO Council on March 21 expressed “united opposition” to their approval and urged FERC to direct the ERO to submit a revision addressing RTOs’ and ISOs’ concerns within the next four months (RD24-5).
NERC filed EOP-012-2 (Extreme cold weather preparedness and operations) with the commission Feb. 16, the day after the organization’s Board of Trustees approved the standard at its open meeting in Houston. (See “Cold Weather Standard Accepted,” NERC Board of Trustees/MRC Briefs: Feb. 14-15, 2024.) It serves as successor to EOP-012-1, which FERC approved in February 2023 while ordering NERC to develop a replacement within a year.
In its filing, the IRC emphasized that it supports the commission and the ERO’s efforts to prevent future major outages due to cold weather, such as those during winter storms Elliott and Uri, through the development of reliability standards. The council said it “has actively engaged” during all stages of the standards development process “to advocate for durable requirements that will lead to effective winterization” and “was careful to propose specific language to address the concerns it raised.”
However, although the IRC acknowledged the standards drafting team modified the standard in response to some of its comments, it said the submitted standards leave the “most significant concerns … unaddressed.” It warned that approving the standard will lead to more reliability issues, causing additional work for FERC and greater cost for generator owners and the public.
“It is admittedly unusual for the IRC members in the United States to unanimously urge the commission to reject and remand a NERC reliability standard,” the IRC wrote. “The IRC does not take this step lightly, but given … the need to ‘get it right’ rather than just ‘getting it done,’ the IRC urges the commission to carefully weigh the fact that the record reflects the united opposition of all the RTOs and ISOs throughout the [U.S.] (and the [Independent Electricity System Operator] in Canada) to the exceptions and low winterization bar included in the proposed standard.”
Cost Concerns Misplaced, IRC Says
The IRC listed multiple issues with the standard, but a common theme was that NERC’s proposed requirements were “subjective [and] unclear.”
For example, Requirement R7 of EOP-012-2 excuses generator owners from implementing freeze protection measures if those measures would cause a “generator cold weather constraint” — meaning that the measures cannot be “implemented at a reasonable cost consistent with good business practices, reliability or safety.” Unreasonable costs include “prohibitively expensive modifications or significant expenditures on equipment with minimal remaining life.”
The IRC said this definition gives GOs multiple avenues to avoid implementing freeze protection measures, and forces NERC and the regional entities to judge the reasonableness and accuracy of an entity’s estimated costs. Pointing out that this is not normally the ERO’s jurisdiction, the IRC said the commission should direct cost-based constraints to be removed from the standard. Instead, IRC suggested constraints should be granted on a per-unit basis on grounds of technical feasibility, which the IRC observed falls under NERC’s expertise.
In addition, the IRC warned the standard “provides far too much discretion to [registered entities] to interpret whether freeze protection measures are available for [their] equipment when determining whether a basis exists to declare a constraint.” It noted that the standard’s definition of “freeze protection measures” refers to practices and technologies “generally implemented by the electric industry in areas that experience similar winter climate conditions.”
The council expressed concern this language would create difficulties with auditing the standard, because GOs could simply declare a constraint on the grounds that there are no available measures that are “generally implemented” by their peers. This could also “delay and disincentivize” the adoption of new technologies. IRC’s filing said the ERO should be directed to require measures that “would reasonably be expected to result in effective facility performance while operating at the extreme cold weather temperature.”
Exemptions Too Generous
IRC also took issue with the standard’s exemptions for existing generating units. The standard exempts units from some winterization requirements if they “may be called upon to … assist in the mitigation of … emergencies during periods at or below a temperature of 32 degrees Fahrenheit.” IRC suggested that this exemption should apply only to “truly seasonal generating units that will not be called upon to operate during freezing conditions” so that units unsuited for cold weather are not called on in emergencies.
NERC’s proposed timelines for implementing corrective action plans on units that experience cold weather-related emergencies — with entities’ required actions that can be completed within 24 and 48 months — were also a subject of the IRC’s criticism, with the council worrying that these periods “do not appropriately reflect the urgency of winterizing generating units.” It supported reducing the timetables to 12 and 24 months, along with requiring GOs to receive approval from NERC or their REs for longer implementation timelines.
In a statement, NERC said that EOP-012-2 is part of a “suite of cold weather standards [that] are key to addressing” grid impacts of severe cold weather. The ERO pointed to EOP-012-2’s clarifications of applicability, GOs’ eligibility for exemptions and shortening the implementation timeline as “key modifications that build on the general framework and principles established in EOP-012-1,” and said NERC is committed “to monitoring the effectiveness of the standard.”
HOUSTON — CERAWeek 2024 by S&P Global was supposed to explore “strategies for a multidimensional, multispeed and multifuel energy transition” and the energy industry’s response to growing demand for emissions reductions and cleaner forms of energy.
However, the two buzziest words during the weeklong conference March 18-22 turned out to be “data centers” and “artificial intelligence,” or AI, and their effect on growing electricity demand.
During one panel discussion, AES CEO Andrés Gluski noted the demand generated by data centers.
“I’m glad you mentioned data centers,” interjected the moderator, S&P Global’s Xizhou Zhou, “because every session seems to have to mention data centers or AI.”
“Coming out of the pandemic, we started to see demand increase two years in a row,” said Independent Electricity System Operator executive Chuck Farmer. “We’re less worried right now about data centers, but frankly, I wasn’t that worried about data centers until I came to this conference.”
Energy Secretary Jennifer Granholm said the explosive growth of data centers, cryptocurrency miners and AI-fueled technologies is what keeps her up at night.
Cryptocurrency miners have flocked to the U.S. after China’s 2021 crackdown on the industry. The U.S. Energy Information Administration says their energy demand could represent as much as 2.3% of electricity consumption, or 19 GW, according to the Cambridge Bitcoin Electricity Consumption Index (CBECI).
The CBECI estimated the U.S.’s global share of crypto mining went from 3.4% in 2020 to 37.8% in January 2022. ERCOT has 41 GW of requests for new mining capacity in its interconnection queue; about 9 GW have been approved for planning studies, according to NERC.
“Energy demand has been sort of flat because of energy efficiency, and now all of a sudden we’re seeing this huge increase because of AI, because of data centers, because of Bitcoin, because of crypto, because of the additional manufacturing facilities that are coming online because of electrification of transportation,” Granholm said during her appearance. “As the AI revolution has come upon us, I think we have to think a little bit differently about how we ensure that we’ve got enough power.”
Indeed. Experts say AI could be instrumental in creating additional energy efficiency and decarbonization tools. The DOE already has a pilot program to evaluate whether the huge amount of available data can speed up permitting timelines.
“Here’s the hopeful thing,” Granholm said “We really think that AI can be really helpful on quick permitting because with these huge datasets of land characterization, for example, and a huge amount of information already in the public datasets that DOE has access to through our national labs, we think that machine learning can speed up significantly permitting times.”
Microsoft co-founder Bill Gates said during his plenary session that AI can be used to determine the best ways to reduce demand at data centers that naturally will pop up where electricity is cheaper. AI also can be used to calculate emissions climate effects and improve efficiency.
“All of our sort of grid modeling and management, these AI tools will come in and play a role,” he said. “But the current techniques require a lot of electricity.”
Pattern Energy Eyes Next Project
Pattern Energy CEO Hunter Armistead, whose company recently broke ground on what may be the largest clean energy infrastructure project in U.S. history, a 550-mile HVDC line from New Mexico into southern Arizona, offered his own thoughts on speeding up transmission permitting.
“Tight timelines to respond also have timelines for challenge,” Armistead said.
Pattern’s SunZia Wind and Transmission project was placed on the drawing boards in the mid-2000s, back when Blackberrys ruled the business world and Taylor Swift’s “Love Story” first caught Armistead’s attention.
“[‘Fearless’] was a badass album, by the way. I mean, I became a Swiftie early on,” he said.
Pattern didn’t become involved in SunZia until 2018, and it secured FERC’s approval of its tariff only last year. All told, breaking ground on a project that should be commercially available within the next two years took 16 years. (See FERC Approves Tariff for SunZia Transmission.)
“Sixteen years … we can’t do that again. We have to learn from this arc of time and figure out how to shrink it quite a bit,” Armistead said.
While the project’s costs have risen to $11 billion and while Armistead said he hopes Pattern never does a deal that large again, he called SunZia a “transformative moment for our industry.”
“Deals like this more naturally don’t get done. The part that really just struck home with me is how critical this was to so many people,” Armistead said. “My absolute hope for the future is that this is only the beginning. As an organization, Pattern has had the opportunity to learn what this all takes to do.”
He said the company’s next “most ambitious project” is Southern Spirit, formerly known as Southern Cross. The project involves 320 miles of 525-kV HVDC transmission facilities interconnecting ERCOT with MISO and grids in the southeast. The project gained regulatory approval from the Texas commission in 2022 after seven years of review, and FERC has said Southern Spirit will not trigger its jurisdiction over ERCOT. (See “SCT Proceeding Closed,” Texas Public Utility Commission Briefs: Sept. 29, 2022.)
“It is going to be even more awesome [than SunZia],” said Armistead, who said he told staff Southern Spirit is his favorite operational project.
“The reality is the complexity of integrating to ISOs, the disparate weather patterns between what goes on in the southeast and the complication of integrating renewable generation that’s available to the southeast, yet being able to provide capacity back into ERCOT,” he said. “I have no idea how we’re going to structure the commercial side of it, but that’s what makes it super-duper fun.”
Glick Doesn’t Miss Politics
Former FERC Chair Richard Glick popped up at CERAWeek’s Innovation Agora, the conference’s technology and innovation programming center, to promote Hydrostor’s compressed-air, long-duration storage.
Glick told RTO Insider he is “fascinated” with the Canadian company’s technology. Hydrostor uses compressed air and water to store energy produced during the compression. The energy is then used to generate power when it’s released from underground rock caverns.
“We’re like a pumped hydro asset,” Hydrostor President Jon Norman said.
One of consulting firm Glick & Quinlan’s clients raised the former commissioner’s awareness of long-duration storage, defined as eight hours or more.
“There really is a need for longer storage, so I thought this was really kind of the right time to get in and talk about some of the policies. It’s been fun so far,” Glick said. “There are enormous benefits from an environmental perspective and from an economic perspective.”
Glick, who left FERC after 2022 when the U.S. Senate’s Energy & Natural Resources Committee refused to hold a confirmation hearing, said he misses his work at the commission. (See FERC’s Work in 2022 Left in Doubt by Manchin.)
“The issues are really interesting, obviously, and you’re in the middle of everything these days, for good and for bad,” he said. “I don’t miss some of the machinations, some issues that came up over time.”
Perhaps aware that three potential successors would be going before the Senate Energy Committee, Glick added, “I certainly don’t miss testifying on Capitol Hill.”
SMRs Could be Answer for Nukes
Texans have a reputation for talking big, and Jimmy Glotfelty is no exception. The regulatory commissioner has been tasked with leading a task force on whether the state can deploy small modular nuclear reactors (SMRs), but he’s not stopping there.
“This is an opportunity for us to open the door and lay out the welcome mat that we are interested in nuclear,” Glotfelty said during an Innovation Agora pod discussion. “We want to hear from you. If you all want to build, if you need to de-risk projects and we can help you do that in some way, let us know what that way is. That’s what we want to do here.
“We don’t want to be like every other state. We want to be ahead of every other state, and we want to build a business and an industry here for a global nuclear business,” he added. “That’s the way we are looking at this. Not to build one or two plants, but to build a community and to build an industry that will serve the world.”
The task force must deliver a report to the governor and the Legislature by December that outlines how plants are built and designed, how sites are identified, and whether any changes to laws or ERCOT protocols need to be made.
“We should look at nuclear plants in the long term like a dispatchable gas facility. I think as the cost curve comes down, [nuclear and gas] are going to be the same,” Glotfelty said. “That’s our expectation, that gas plants or nuclear plants can support the market’s reliability in an equal fashion.”
Speaking on a separate panel, former U.S. Energy Secretary Ernest Moniz, now CEO of the nonprofit Energy Futures Initiative, said nuclear technologies come in several flavors besides SMRs and include micro-reactors, light water, heavy water, fourth generation, thorium, liquid metal and molten salt.
Moniz said his initiative has put together a suggestion to kick-start SMRs’ deployment, noting it is translatable to gigawatt-scale reactors.
“The issue is getting an order book of sufficient scale to justify investments,” he said, suggesting the order book be put together by the government. “Government has a role to help this happen in the United States when it’s ultimately in the private sector, facilitating to share financial investment, because especially with a new design, the first reactor is likely to be substantially more expensive. If you can share the financial burden and price an order book for 10, 20 reactors or whatever you choose, that would be good.”
That’s exactly what the U.S. government is doing for TerraPower’s planned Natrium reactor in Wyoming. The Gates-founded group has about $1 billion in private funding and a reported $2 billion from the government supporting the project.
TerraPower CEO Chris Levesque told the Financial Times the plant could begin construction in June and enter commercial operation in 2030.
FERC on March 21 upheld its May 2023 order reinstituting de-pancaking provisions in Louisville Gas & Electric and Kentucky Utilities’ transmission rates, which the utility has challenged before the D.C. Circuit Court of Appeals (ER23-2656-001, et al.).
The commission’s May 2023 order reversed its 2019 decision allowing the company to remove provisions that de-pancaked its rates as a condition of LG&E/KU’s 2006 withdrawal from MISO, ensuring customers wouldn’t pay duplicate rates across the merged company’s territory.
FERC’s reversal followed a D.C. Circuit order remanding the 2019 decision back to the commission after several municipal utilities in Kentucky sued.
Upon reconsideration, FERC decided that removing the de-pancaking mitigation “will have an adverse effect on rates for the customers involved.” It directed LG&E/KU to reinstitute the provisions, retroactive to March 2021.
LG&E/KU complied, but not without protest. It filed both its new de-pancaked rates (Rate Schedule 525) and a request for rehearing of the order on remand. FERC in November found that the utility had only partially complied with its directive, as it had not fully restored the provisions of its pre-2019 rates (Rate Schedule 402). The utility also requested rehearing of this order.
FERC automatically rejected the utility’s rehearing request after not acting within 30 days. The order issued at the commission’s March 21 open meeting rejected the utility’s arguments as out of time: FERC found that it raised issues that should have been in response to the order on remand, not to the order on the company’s compliance filing.
“LG&E and KU’s substantive arguments, however numerous or illustrative, go beyond compliance with the remand order’s directive,” FERC said. “Further, contrary to LG&E and KU’s argument that this compliance filing was the first opportunity to address the justness and reasonableness of RS 525, LG&E and KU had a full opportunity to raise arguments supporting their request to end de-pancaking mitigation in the proceedings leading to the remand order, as well as raise arguments concerning the remand order’s compliance directive to reinstitute the de-pancaking provisions of former RS 402, now found in RS 525, in their subsequent request for rehearing of the remand order.”
FERC also issued a letter order March 21 approving the utility’s revisions to RS 525 (ER23-2656-002).
LG&E/KU will now take its arguments to the D.C. Circuit, where it filed a petition of review over FERC’s 2023 order in February.
ALBANY, N.Y. — New York’s transition to a deregulated wholesale power market helped drive the state’s adoption of innovative energy technology and policies, panelists said March 19 at the Independent Power Producers of New York’s 38th spring conference
“We’ve seen a transformation in front of our eyes,” said FERC Chair Willie Phillips.
IPPNY President Gavin Donohue also celebrated the 25th anniversary of New York’s market deregulation, highlighting the state’s achievements in reducing greenhouse gas emissions, transforming its energy investment strategies and taking the cost burden of transmission development from “the backs of ratepayers.”
According to IPPNY, energy market deregulation has kept wholesale electricity costs below inflation rates, halved carbon emissions, reduced sulfur dioxide and nitrogen oxide emissions by over 90% each, and spurred billions of dollars in grid investments by independent power producers.
However, Phillips said the state and country face new challenges, noting that, after years of flat demand, electricity use is spiking due to large load facilities such as microchip manufacturing plants and the energy-intensive data centers required for artificial intelligence computing.
“We’ve seen demand increase in a way we didn’t expect,” he said, “and this means, after being flat for the past decade, New York is grappling with how to bring new resources on to match the demands our system and also, at the same time, transition to a clean, more renewable energy future.”
Phillips said this is “the background we come to this conference with, as we talk about and celebrate the 25th anniversary of [New York’s] market.”
Reflecting on 25 Years, Looking Ahead to 25 More
NYISO, approved by FERC in 1998 as the New York Power Pool’s successor, initiated its competitive electricity markets on Dec. 1, 1999, and initially oversaw a transmission grid spanning over 10,700 miles powered almost entirely by fossil fuels, according to the New York State Energy Research and Development Authority.
“When we started to work on setting up market rules for competitive markets, we were primarily interested in creating the nuts and bolts of a competitive market: efficiency, lower costs and innovation,” said Suedeen Kelly, a partner at Jenner & Block and former FERC commissioner. “And it worked, and it’s continued.”
The ISO now manages over 11,000 miles of transmission, according to its 2023 Gold Book, and operates a system increasingly supported by a diverse group of resources such as solar or wind.
Saying that regulators appreciate how “New York takes risks,” Kelly praised the state for both adapting to evolving challenges and striving to incorporate new technologies into its market.
IPPNY estimates New York’s generation fleet has grown from 28 GW in 1999 to about 41 GW today. However, according to NYISO’s 20-year outlook, to meet its Climate Leadership and Community Protection Act (CLCPA) obligations, the state will need between 111 and 124 GW of installed capacity by 2040, with at least 95 GW of this coming from a blend of intermittent, energy storage and dispatchable emissions-free resources. (See “NYISO Releases the Outlook,” NYISO OC Discusses NOPR Comments, High Temps, EDS Results.)
Following the CLCPA’s ambitious decarbonization goals — 70% renewable electricity by 2030, 100% zero-emission electricity by 2040 and net-zero emissions statewide by 2050 — New York has adopted a more proactive legislative strategy, focused on promoting clean energy, retiring fossil fuel plants and expanding transmission.
“Everything in our industry is changing,” said Phillips, in response to a question raised by Donohue about how regulatory frameworks must adapt to future challenges like climate change and more energy-progressive policies.
“We as regulators have to change the way we approach these issues,” he added, “and we need a new generation to think differently about these problems.”
However, 25 years ago, this way of thinking would have been anathema to many New York legislators and regulators.
“That’s not the case anymore,” said William Flynn, industry team leader at law firm Harris Beach and a former PSC chair.
“Now, another branch of government is actively involved in shaping the future of the energy sector, which obviously impacts the future of competitive markets” he said, “but, no stone should be left unturned if we want to be truly successful in taking competitive markets to the next level.”
New York policymakers and agencies now aggressively seek to cut GHG emissions, invest in transmission buildout and resilience, and develop net-zero resources to replace an aging fossil fuel fleet, a marked shift in policy thinking made possible by market deregulation, according to IPPNY panelists.
Case in point, according to the New York Department of Environmental Conservation, which reports the state’s decarbonization progress annually, statewide GHG emissions in 2021 were 10.2% below the baseline limit adopted by the CLCPA’s regulations, with the energy sector’s emissions in 2021 being 19% lower than in 1990 but still accounting for about 76% of the state’s total emissions.
However, the Legislature is likely to accelerate the state’s decarbonization efforts as it considers bills like the NY HEAT Act (S2016A), which would eliminate the 100-foot rule requiring gas be provided to new customers, or another that expands New York’s hydraulic fracking ban by prohibiting carbon dioxide in natural gas extraction (S8357).
‘Magic’ in the Transition
In his keynote, PSC Chair Rory Christian reflected on the commission’s evolution after deregulation and how it can now harness the “magic” of new advanced technologies to address CLCPA mandates and tackle today’s challenges.
“While we can understand and marvel about the technology we all possess,” he said, “one thing I think most people don’t take into consideration, however, is the fact that our ability to wield this magic is defined by the availability of cheap, reliable, safe energy systems, and that our daily lives depend on our ability to wield this magic.”
Christian said New York’s “departure from a vertically integrated utility model to a restructured wholesale electric market” set the stage for the PSC to support the CLCPA’s net-zero goals, since it allowed the commission to incorporate competition into the state’s energy markets, mitigating financial risks to ratepayers by shifting development costs to private entities.
“New York utilities have either maintained or improved their reliability and have done so while weathering increasingly severe and frequent climate events,” he said, adding that the PSC, which oversees the state’s utilities, “works tirelessly to identify the pathways to address the state’s future energy needs and ensure an equitable access to energy.”
“We recognize that our actions have impact on lives and livelihoods, and that our actions mean the difference between our security and calamity, and the ripple effects can extend far beyond our state borders,” he added.
Christian said that for New York to “remain ahead of the curve,” the PSC remains committed to adapting to looming challenges, including electrification, modern technologies like AI and climate change, since the commission must provide New York and its utilities with the capacity to successfully adapt.
He detailed how the PSC has sought to help New York achieve the CLCPA’s mandates by opening a new proceeding to investigate modern resources or technologies, engaging state utilities to coordinate their grid planning processes, approving bulk and local transmission system investments, and creating competitive procurement processes to address the state energy system’s changing needs.
“We in New York, and across the U.S., must be prepared to capture these prospective benefits and provide the power needed to harness this new form of magic,” he said, “and what’s clear to me, is that [New York’s] competitive markets will likely play a role in each.”
New York is walking a fine line between its lofty aspirations and realities on the ground, but as was similarly expressed at last year’s IPPNY conference, industry stakeholders are keen to take advantage of the new opportunities that will come from the state’s pursuit of a decarbonized economy and cleaner grid. (See IPPNY Panelists Urge Collaboration, Coordination in Transition; Overheard at IPPNY 2023 Spring Conference.)
This delicate balance was summarized by Donohue in his closing remarks.
While he attributed the success of New York’s decarbonization efforts to advantages gained from the transition to a deregulated market, he pointed out that, despite those accomplishments, “there’s a lot of work left to be done in New York, since we still have to come up with an awful lot of zero-emission resources.”
VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee rejected four proposals to revise how the RTO determines how much capacity energy efficiency programs can enter into the capacity market. (See “PJM MIC Briefs: March 6, 2024.)
The proposals were built off the package PJM brought to the MRC in February, which sought to delineate the boundary between the two baselines against which EE providers can measure the savings from more efficient equipment and tighten qualifications for the baseline load, which tends to yield higher calculated savings than the standard baseline.
The PJM proposal received 51% sector-weighted support, short of the two-thirds threshold required. A proposal from Vistra Energy received 66.5% support, an alternative from CPower carried 38% support and another from Affirmed Energy had 31.5% support.
The PJM proposal would have required, among other changes, that EE providers have a contract with each individual end user, demonstrate that certain more efficient equipment would not otherwise have been installed, and account for any “leakage” of EE products purchased in one region but installed in another.
Affirmed Energy and CPower both brought alternate proposals they argued would not significantly impact EE participation in the capacity auction while still meeting PJM’s goal of enhancing measurement and verification of that capacity.
The Affirmed proposal focused on the impact to mid- and upstream EE programs, which seek to encourage retailers and manufacturers to offer more efficient products and share those products’ capacity market savings. Capturing savings at the retail level allows for small purchases to add up to the 100-kW threshold for EE participation in the wholesale market, a scale small residential consumers are unlikely to meet, Affirmed’s Luke Fishback said.
Fishback said PJM’s data collection requirements would require EE providers to receive consumer data for each retail EE product customer and enter a contract with each to obtain sole rights to enter those savings into the capacity market, which he argued would not be feasible and would eliminate much of that market’s aggregation.
The CPower proposal targeted PJM’s causation requirement for EE to qualify for the baseline load, which would have required that customers install equipment specifically to receive capacity market revenues. Senior Vice President Kenneth Schisler argued this would disqualify projects with multiple consumer benefits, such as home renovations improving insulation that may also be damaged by humidity.
The CPower proposal would have replaced PJM’s language stipulating that a project “would not have occurred absent participation in the wholesale market” with the need for “a direct connection to participation in the wholesale market.”
Both alternatives also took issue with PJM’s proposal that state technical reference manuals used to measure EE savings under the baseline load must be less than three years old. The Affirmed proposal would shift that to six years, and the CPower proposal to five.
Fishback said most TRMs issued by PJM states would have been invalidated under PJM’s proposal, requiring EE providers to instead study meter data, which he said would take too long to complete for the 2025/26 Base Residual Auction (BRA).
After the committee rejected the three proposals, Vistra offered a fourth revising PJM’s proposal to include a transitional period for the TRM limitations. Manuals less than five years old would be permitted for the 2025/26 BRA, four years for the following, and three years for 2027/28 and onwards.
Revised Reserve Requirement Study Values Endorsed
Stakeholders endorsed revised installed reserve margin (IRM) and forecast pool requirement (FPR) values accounting for inputs that changed following FERC’s approval of PJM’s critical issue fast path (CIFP) filing reworking its approach to risk modeling and accreditation. The new values were endorsed with 88% support at the MRC and passed by acclamation at the MC on March 20. (See FERC Approves 1st PJM Proposal out of CIFP.)
PJM’s Patricio Rocha Garrido said the need to recalculate was driven by several analytical developments since figures were approved by the committee in October and by fine-tuning made in recent months, as well as by parameters updated to better reflect resource pool changes. (See “Stakeholders Endorse Revised RRS Values,” PJM PC/TEAC Briefs: Feb. 6, 2024.)
The revised figures raise the IRM to 17.8%, an increase from 17.7% in the 2023 Reserve Requirement Study (RRS) results endorsed in October. The FPR would decrease to 0.9387, down from 1.1165 in the October values.
The Planning Committee voted in February to reset the two values, moving the figures in a similar direction to that endorsed by the MRC last week. The PC endorsed an IRM of 17.7% and an FPR of 0.9440.
Several resources that had submitted a notice of intent to offer into the capacity market were removed from the resource mix after PJM determined they are unlikely to come online prior to the start of the delivery year. Deactivations that were recently announced or not included in the original analysis were also removed from the expected available generation.
PJM and its Independent Market Monitor found that the characteristics of some resources had changed enough to warrant reclassifying their effective load carrying capability (ELCC) class. One of the prime reasons for this was a generator being reconfigured to run on a different fuel.
Some resources were also identified as having incorrect installed capacity (ICAP) values, particularly pseudo-tied generation, and some that had ambient derate tickets with variable megawatt reductions did not have the variability captured in their data.
MRC Amends Large Load Adjustment Forecast Issue Charge
The committee voted to revise an issue charge framing ongoing stakeholder discussion of how capacity assignments from forecasted large load additions are assigned to market participants in the same transmission zone. The proposal expands the scope of the discussion to consider load-serving entities (LSEs) able to control large load addition (LLAs) forecasts in their region. (See “1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions,” PJM MIC Briefs: March 6, 2024.)
Mike Cocco of the Old Dominion Electric Cooperative (ODEC) said the unrevised language could grant sole control over the ability to submit forecasts to electric distribution companies (EDCs), including for any LSEs within their footprint. He argued that allowing a market participant to affect another participant’s load forecast is contrary to PJM’s basic market principles.
Joshua Burkholder of American Electric Power (AEP) said he supported the amendment as a minor clarification and improvement to the issue charge, noting that AEP was one of the document’s co-sponsors.
Dominion’s Jim Davis, the other co-sponsor, said the proposal being considered by the Market Implementation Committee will reflect some of the clarifications in the issue charge.
The proposal would exclude LLAs from the calculation of base zonal scaling factors and apply that load to the obligation peak load of the zone it is projected to be added to. LLAs are determined by PJM using information from LSEs about expected load growth and are detailed in the RTO’s annual load forecast reports under Table B-9.
Calpine Proposes Changes to Dual Fuel Classification
Calpine’s David “Scarp” Scarpignato presented a quick-fix proposal expanding the definition of dual-fuel resources to include units that start using their primary fuel and operate on secondary fuel. He said some gas-fired resources can start multiple times on the fuel present in the portion of pipeline leading to the generator, even if the pipeline feeding into that segment is offline or the generation owner has not entered a fuel contract. The quick-fix process allows for a problem statement and issue charge to be brought concurrent with a proposed solution.
The proposal would revise the Manual 34 definitions of dual-fuel combined-cycle and combustion turbine resources to require that they be capable of starting independently using “behind-the-fuel meter source” and then operate on the secondary fuel.
First Read on PJM Regional Planning Proposal
PJM’s Michael Herman presented a first read of the RTO’s proposal to create new long-term regional planning scenarios informing the development of the Regional Transmission Expansion Plan and state initiatives through the State Agreement Approach (SAA). (See “Stakeholders Long-term Regional Transmission Planning Proposal,” PJM PC/TEAC Briefs: March 5, 2024.)
The proposal would add five new scenarios: two base cases focused on reliability needs eight and 15 years out; two policy scenarios looking at new entry backed by state legislation eight to 15 years in advance; and an additional policy scenario including higher generation entry not backed by signed legislation. The two-year planning cycle would be extended to three years because of the increased number of scenarios. PJM’s current 10-year voltage analysis would be performed on the eight-year base scenario and include thermal analysis.
Herman said the scenarios are designed to capture evolutions the grid is expected to undergo over the next 15 years, namely 44 GW of load growth, 30 GW of generation deactivations and increased renewable energy penetration.
Ryann Reagan, of the New Jersey Board of Public Utilities (NJ BPU), said the new paradigm would provide the PJM planning team with a valuable new tool and that could aid other states follow NJ’s lead with using the SAA to pursue clean energy objectives.
Governing Documents Revisions Endorsed Through GDECS Process
Several changes to PJM’s governing documents were endorsed by the committee in line with the recommendations made by the Governing Document Enhancement and Clarification Subcommittee (GDECS). The revisions were approved by acclamation with no objections and several abstentions. (See “Other MRC Business,”PJM MRC/MC Briefs: Feb. 22, 2024.)
PJM’s Michele Greening said terms being added to the documents’ definition sections are already defined in the existing language, but that language has not been duplicated in the definition section.
On March 20 and during the first read of the changes at the Feb. 22 MRC meeting, several stakeholders questioned if some of the package’s recommendations exceed the inconsequential nature of revisions typically drafted through the GDECS.
PJM also presented a first read on another set of revisions recommended by the GDECS, including a change to lowercase several references to “end-use customer” in the tariff around load management participation in the capacity market.
PJM’s Daniel Vinnik argued the terms were capitalized through a scrivener’s error and were not meant to suggest that consumers participating in demand response programs must be PJM members.
The second set of GDECS revisions are set to be voted on by the MRC on April 25 and the MC on May 6.
Other Committee Business:
Consideration of a quick-fix proposal to expand the winter availability window for demand response resources was spiked to the April 25 MRC meeting to give more time for sponsors to consider continuing pursuing changes through the expedited stakeholder process. Bruce Campbell, of Campbell Energy Advisors, said the sponsors may only seek endorsement of the issue charge next month, which would open a standard stakeholder process to explore if changes to the load participating in demand response programs and market changes made through the CIFP process warrant changes to the availability window.
PJM’s David Hauske presented a first read on a proposal revising the Operating Agreement, Tariff and manuals to add definitions of three synchronous condenser parameters — condense startup costs, condense-to-generate costs and condense energy use. He said the parameters are in use and there would be no change to PJM practices.
Members Committee
Advocates Concerned About Transparency over Filing Rights Changes
Greg Poulos, executive director of the Consumer Advocates of PJM States presented consumer advocates’ concerns over the openness of discussions between PJM and transmission owners on revising the consolidated Transmission Owners Agreement (CTOA) to shift Federal Power Act Section 205 filing rights from PJM members to the RTO.
Exelon Director of RTO Relations Alex Stern laid out the proposed changes to the Members Committee during its Feb. 22 meeting, where several transmission representatives noted that changes to the CTOA are made through negotiations between the Transmission Owners Agreement-Administrative Committee (TOA-AC) and the PJM Board of Managers. (See “TOs Considering Handing PJM Transmission Planning Filing Rights,” PJM MRC/MC Briefs: Feb. 22, 2024.)
While advocates have been pushing for PJM to plan more proactively, Poulos said negotiations to expand its filing rights and other associated changes to the balance between stakeholder and RTO authority should be public. He said that transmission owners speaking during the February MC meeting argued that the changes could have benefits to consumers; however, those consumers’ representatives do not have a voice at the table where those changes are being considered.
The company’s System Energy Resources Inc. (SERI) sells energy and capacity from the 1,443-MW nuclear plant in Port Gibson, Miss., to Entergy Arkansas and the utility’s three other operating companies under a cost-based formula rate.
Grand Gulf’s Unit Power Sales Agreement has been the subject of complaints of overcharging by regulators in Arkansas, Louisiana, Mississippi and New Orleans since 2017.
In addition to the payment to Entergy Arkansas, the new settlement specifies that SERI will use a return on common equity of 9.65% in its monthly billings to the utility effective November 2023 and that no settling party can propose a change to the rate until at least June 30, 2026.
SERI also agreed to use a capital structure with an equity ratio not to exceed 52%.
The commission said the settlement was in the public interest because it was uncontested and appears to be fair and reasonable.
SPP’s Board of Directors approved the initial tariff for its Markets+ service offering in the Western Interconnection March 25, clearing the way for its filing at FERC.
Board Chair John Cupparo called the action an important step, but not the last, in continuing SPP’s development of the day-ahead market. Markets+ is just one of several western expansion initiatives, which include SPP RTO West and an imbalance market.
“We don’t know exactly what the outcome is going to be [as] SPP continues to prudently pursue this western expansion, given the long-term potential of this expansion,” he said. “Another way to say that is five, 10, 15 years from now, I wouldn’t want to be in the position of answering the question, ‘Why didn’t you pursue this?’”
“Based on experience in the West, it is always a challenge to completely get our arms around what entities in the West will do and what they’ll ultimately decide,” said Cupparo, a Colorado resident with western utility experience. “We’re still entering that phase right now. There are many variables and diverse perspectives that will influence these decisions.”
The tariff’s filing will complete the first phase of the Markets+ development. SPP lists 38 western entities as having participated in drafting the tariff and its protocols.
The grid operator hopes to receive FERC approval by year’s end. In the meantime, SPP and interested participants will develop and negotiate funding agreements for the second phase. SPP will file at FERC a financing approach, projected to be about $140 million plus financing costs.
Once FERC has approved the tariff, SPP will begin acquiring and modifying the necessary software, hardware and related processes. Phase 2 work will begin next year after the financing approach is approved.
“I think we’re probably several years away from parties participating in Markets+ and deciding that they’ve gotten comfortable with the regionalization to the level where they’re now interested in pursuing an RTO,” said Antoine Lucas, SPP’s vice president of markets.
The motion to approve the tariff cleared the Members Committee’s advisory vote, 15-1, with four abstentions. The Natural Resources Defense Council’s Christy Walsh cast the lone dissenting vote over concerns the tariff isn’t complete.
Markets+ stakeholders and SPP staff have been working together since last year putting together the tariff’s various pieces. The Markets+ Participants Executive Committee has held 86 votes on tariff language since August, with an average approval rating of 97.72%. Several identified tariff elements were postponed because of the time necessary to resolve them.
Lucas reminded members the tariff they were voting on does not include the second phase. That will include contractual obligations that set cost recovery and financial obligations associated with the market’s implementation.
“This being a standalone service, the funding for that service will be taken care of by the participants in the process itself,” he said.
CFO Sterzing Resigns
SPP CEO Barbara Sugg announced during a break in the call that Deborah Sterzing submitted her resignation March 22 as the grid operator’s chief financial officer.
“We hate to see her go. We certainly wish her well in her continued career within our industry,” Sugg said.
David Kelley, vice president of engineering, has been appointed interim chief financial officer. He is already involved in several financial activities for SPP, Sugg said.
Sterzing joined SPP in February 2023. She replaced longtime CFO Tom Dunn, who retired in 2022 after 21 years at the financial helm.
As intermittent renewables proliferate in New England, the region must do a better job incentivizing reliable, dispatchable resources that can support the grid as it decarbonizes, speakers at Raab Associates’ New England Electricity Restructuring Roundtable emphasized March 22.
“We cannot remove conventional generation before we stand up its replacement,” said Charles Dickerson, CEO of the Northeast Power Coordinating Council, adding the region will face shortfalls if it fails to heed this warning.
“The more renewables we have, the more I get prickly around adequacy,” Dickerson added. “It’s not how much is there; it’s how much is there when you need it.”
Gordon van Welie, CEO of ISO-NE, said the RTO’s ongoing efforts to reform its capacity market should help New England more efficiently ensure resource adequacy, but added that more changes likely are needed to align the region’s wholesale electricity markets with the clean energy transition. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.)
“I can’t miss the opportunity to make a pitch about carbon prices,” said van Welie, who has long expressed support for the concept but has indicated ISO-NE would need support from all New England states to proceed. (See ISO-NE: States Must Lead on Carbon Pricing.)
Van Welie said the RTO anticipates increasing renewable energy will reduce revenues from the energy market, requiring more money to come from the capacity market and state-led power purchasing agreements. A carbon price could help prevent an over-reliance on the capacity market and PPAs, van Welie said.
“You’d tax the carbon emissions at source, put that into the offer price, but then you would rebate the money that you’re collecting from those carbon emissions directly back to load at the wholesale level, so you’d mitigate the price impact,” van Welie added. He called the mechanism “an elegant way of trying to balance the consumer impact with the incentives needed to drive the thing you want, which is to reduce carbon emissions.”
Dickerson noted that inverter-based resources also bring new challenges related to ride-through capabilities and cybersecurity threats, and that standardization is needed to ensure resources meet the technical requirements needed for grid reliability.
“We’ve had no less than five or six episodes across the country where an inverter-based resource may have tripped offline because of what we can call a normal blip,” Dickerson said. “Not only did that particular inverter-based resource come offline, it took all the inverter-based resources offline that were connected to it. That’s unsustainable.”
While Dickerson stressed that the risks associated with inverter-based resources have already arrived, van Welie said the Eastern Interconnection likely is “fine for the next five years,” with problems likely emerging “around 10 years out.”
Batteries can use synthetic inertia to help mitigate the loss of spinning thermal resources, “but the inverters need to be designed to do it,” van Welie said, adding this will likely require some type of regulation.
Commissioner Katie Dykes of the Connecticut Department of Energy and Environmental Protection acknowledged the need to ensure grid reliability as the resource mix changes but said the region must continue to accelerate the deployment of clean energy.
“We really have to scale up all our efforts in regards to clean energy if we’re going to achieve our goals,” Dykes said.
Dykes said carbon pricing is “an important tool,” but added it’s “just one tool, and we need a number of different tools in order to see the new entry coming in that can maintain reliability at a rate that ratepayers can afford.”
Dykes added that future procurements could extend to developing generation technologies like advanced nuclear, geothermal and hydrogen fuel cells. She said she’s heard from developers that investing in advanced nuclear projects makes little sense in restructured markets compared to vertically integrated markets.
“We can’t afford to take those types of things off the table,” Dykes said. “We have to figure out how to accommodate them.”
The commissioner highlighted the efforts of Connecticut, Massachusetts and Rhode Island to coordinate offshore wind procurements — bids are due for all three states March 27, with the winning bids to be selected in August. (See New England States Delay Offshore Wind Solicitations.)
Dykes called the coordinated procurement “a template for multistate coordination,” while advocating “predictable, regular auctions” going forward.
“We’re in a moment of extraordinary collaboration,” Dykes said. “That’s what gives me encouragement.”
Liz Anderson, chief of the Energy and Ratepayer Advocacy Division at the Massachusetts Attorney General’s Office, stressed the need to keep ratepayer interests front and center. Anderson said the region should consider the cumulative impacts of programs and investments on electricity costs when designing programs, noting that skyrocketing costs will hinder the clean energy transition.
“A lot of conversations are happening in silos,” Anderson said. “We need to start thinking more holistically about all these costs together.”
