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.
MADISON, Wis. — MISO executives again emphasized that this year’s capacity auction results aren’t indicative of the resource adequacy risks the system is going to confront in coming years or even within a few weeks.
Executive Director of Market Operations J.T. Smith said members’ reaction to last year’s high prices and MISO’s new seasonal design helped MISO achieve capacity sufficiency in the 2023/24 planning year that began June 1. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)
But he issued a warning that the results shouldn’t leave MISO complacent.
Smith said from last year to this year, members cut back on their load forecasts, deferred baseload generation retirements, and some units left PJM for the MISO capacity construct.
“The $10/MWh summer number does not say all is well,” Smith warned the MISO Board of Directors at a June 13 Markets Committee meeting. “We’re not fixed. We still have a lot more to do in making sure this market sends the right price signals.”
Senior Vice President of Markets Todd Ramey said the approximate 5-GW supply improvement over last year in the auction comes down to factors that are not “repeatable or sustainable.”
Smith said MISO has more to do to value capacity in accordance with its reliability contribution and incent new generation. He said adding the seasonal component this year was an important step.
“As an operations person, I’m interested in how the seasonal construct lowered summer pricing. That’s a surprising outcome. I feel much more confident in where we’re moving versus where we’ve been,” he said.
But Smith said over the summer, MISO “may have to lean on non-firm imports all the way to load management” on the chance that the nation experiences a prolonged, widespread heatwave that drives up load. He said if MISO’s previous forecasts for heat concentrated in June and a cooler July and August pan out, “it should be an easy summer as it was an easy spring.” (See MISO: Little Firm Capacity to Spare This Summer.)
MISO Independent Market Monitor David Patton said under more realistic summertime modeling using historic generator availability, he foresees the potential for negative reserve margins this summer; however, he said MISO’s vast import capability means the RTO likely will be resource adequate in a heatwave.
“With the seasonal capacity market, I believe we’re creating stronger incentives for resources not to schedule outages in the summer,” Patton said.
However, he said MISO might be undercounting de-rates in high temperatures because some thermal resources must cut output to avoid discharging warm water into rivers at certain times. He also said MISO’s long-lead resources aren’t realistically available to respond in time when needed.
“These aren’t the greatest scenarios to be under,” he said.
Otherwise, MISO oversaw an operationally straightforward spring, with an average 69-GW load. Smith said real-time prices were down from an average $57/MWh in 2022 to $26/MWh mostly due to a stabilized gas market.
“You can see the energy prices dropped by half because gas prices dropped by two-thirds,” Patton said.
Patton said the nation’s gas storage is 20% higher than usual because the mild winter allowed production to continue while fuel demand dipped. He also said the lower gas prices in spring mean that MISO’s coal resources were back to earning very little profit, “somewhere in the neighborhood of $5/MWh.” Over 2022, coal generation was unusually profitable because natural gas prices shot upward.
MADISON, Wis. — MISO membership and executives last week discussed how to hasten the construction of more than 40 GW of generation projects that have permission to connect to the grid but haven’t been built.
At MISO Board Week June 13-15, MISO leadership repeatedly mentioned that the system is sitting on 42 GW of unbuilt resources that have cleared the interconnection queue and would shore up deteriorating reserves.
During a resource adequacy roundtable at the June 14 Advisory Committee meeting, MISO Director Todd Raba asked how MISO might spur construction on those projects with signed agreements.
Sustainable FERC Project’s Natalie McIntire said supply chain issues are part of the equation, but she said many projects are waiting on future regional transmission projects.
“These generators don’t have a highway to market, so they’re not being built. So, we have a variety of issues that are coming to play here,” she said.
Sierra Club attorney Greg Wannier agreed new transmission is key to easing resource adequacy concerns.
Travis Stewart, representing the Coalition of Midwest Power Producers, said many of those paused generation projects were proposed three to five years ago in a pre-COVID world and have since been subject to macroeconomic challenges. He said the projects are emerging from “COVID limbo,” with developers now figuring out how they can be adjusted to be profitable.
Wisconsin Public Service Commissioner Tyler Huebner said the faster MISO can get generation projects through the queue and connected, the sooner the footprint’s resource adequacy concerns can be downgraded.
During the June 15 board meeting, Senior Vice President of Markets Todd Ramey said MISO is surveying the developers behind the interconnection projects. In some cases, the projects have languished with generator interconnection agreements that are now two years old.
“Bringing new resources online is an important part of the reliability imperative,” Ramey said. He added that MISO is ready to support the developers to lessen “bottlenecks” to building.
In a public comment session, John Norris, former chair of the Iowa Utilities Board and former FERC commissioner, chastised MISO for not getting a jump on major planning sooner to bring new resources online.
He said MISO is wasting its time proposing new restrictions on which generation projects can enter its interconnection queue when new transmission routes would allow generation projects to proceed.
Norris said when even his teenage son is aware that a “gazillion” gigawatts of renewable energy are stalled in interconnection queues because the grid is insufficient, it’s a good indication that the public is increasingly aware that new transmission is foundational to the clean energy transition.
Norris said it’s appalling that there’s now going to be at least a “quarter century” of lag time between Entergy and other southern entities forming MISO South and MISO overseeing an expanded transfer built between MISO Midwest and South. Norris was relying on an average decadelong planning and construction phase for major transmission for the 25-year estimate. MISO’s center-of-the-country position means it has a distinct duty to ensure that transmission is being built sooner, he argued.
In the long run, MISO is still banking on a flock of new renewable sources — and a host of new requirements to govern them.
Executive Director of Resource Planning Scott Wright said the 466 GW of nameplate capacity MISO envisions having in 20 years is going to be “a different animal” and introduce new market complexities. (See related story, MISO Modeling Line Options for 2nd LRTP Portfolio.)
“We’re going to have 400 GW, four times the load, because of the attributes we desire,” he told MISO’s Advisory Committee.
MISO said in the future it will likely measure hourly energy adequacy, use AI to manage uncertainty and target certain amounts of reliability attributes from generation.
“We feel we’re sitting in an untenable position not making these reforms, maybe sitting in an unsafe position not making these reforms,” Wright said.
WEC Energy Group’s Chris Plante said, “Maybe MISO should consider clearing an amount of resources with certain [reliability] attributes.” MISO has said six generating attributes are necessary to its system operations: availability, delivering long-duration energy at a high output, rapid startup times, providing voltage stability, ramp-up capability and fuel assurance. (See MISO to Evaluate System Attributes Through Year’s End.)
Plante said capacity auction prices bouncing from “next to nothing” to the cost of new entry is evidence that other states and load-serving entities might not be carefully planning how to furnish those attributes.
“We plan on bringing our fair share to the table. Others should do the same,” he said.
MISO Director Mark Johnson asked if some entities have possibly “lost sight of their obligation to serve” because they have belonged to the larger MISO resource pool for so long. Members pushed back and insisted their individual load obligations are top of mind amid the fleet transition.
McIntire said MISO’s Planning Resource Auction “isn’t necessarily giving us a signal about the future” because it measures capacity for only one year. She asked that MISO put together a “new, more formalized” resource adequacy forecast that predicts accredited capacity on five-, 10- and 15-year horizons.
MISO CEO John Bear said MISO has much to do to address emerging reliability risks. He said the ongoing discussion on how to encourage generation that can provide certain system attributes is crucial.
“How do we find these controllable, long-duration resources that can cover our risk during a wind or sun drought? We’ve got to work on that. We’ve got to get to that,” Bear said at MISO’s board meeting.
The U.S. Department of Interior on Thursday announced a plan to make solar and wind energy development on public lands in Western states faster, easier and less expensive.
DOI said its proposed Renewable Energy Rule would reduce fees for such projects by about 80% and offer greater certainty to private-sector developers. It would codify reductions made by guidance last year and would expand them.
Publication of the proposed rule in the Federal Register on Friday kicked off a 60-day public comment period.
Under the proposal, the Bureau of Land Management would retain authority to hold competitive auctions but would gain expanded ability to accept non-competitive leasing applications it deemed to be in the public interest.
The Federal Land Policy and Management Act generally requires holders of rights of way to pay in advance the fair market value for use of public lands.
But the Energy Act of 2020 empowered BLM to make an exception to that rule — to reduce both acreage rents and capacity fees for existing and new solar and wind projects — if it makes certain findings, such as that the rates impose economic hardships or limit commercial interest in a competitive lease sale or ROW grant, or that the reduced cost is necessary to promote the greatest use of wind and solar energy resources.
BLM proposes to base the capacity fee on actual energy production of the installed equipment, rather than its nameplate capacity.
BLM also proposes to calculate the acreage rent for an ROW based on the per-acre value for pastureland calculated in the National Agricultural Statistics Service Cash Rents Survey, and to collect that acreage rent whether or not energy is generated on the land that year.
The five-year median per-acre value is currently $6.62 in the western states.
The capacity fee would be collected only if it exceeds the acreage rent; if a capacity fee is collected, no acreage rent would be due for the year.
One component of the capacity fee, the MWh rate — which is based on wholesale prices for the major trading hubs serving 11 Western states or on prices received by the ROW holder under a power purchase agreement — would be reduced by 80% until 2036 under the proposed rule.
In 2036, that would drop to a 20% reduction, but only for new ROWs and for existing ROWs up for renewal.
BLM expects that these reductions would particularly benefit smaller-scale projects or projects on the cusp of profitability.
BLM also is proposing capacity fee reductions tied to an ROW holder’s use of U.S.-made components, stimulating the domestic manufacturing sector by reducing the net cost differential between U.S.-made and foreign materials.
The Energy Act of 2020 established a minimum goal of authorizing production of not less than 25 GW of geothermal, solar and wind projects on public land not later than 2025. As of mid-2023, BLM has authorized more than 13 GW.
Members of Congress went to Moore County, N.C., on Friday to hold a field hearing on the substation attacks there in early December that knocked out power to 45,000 customers, and which remain unsolved.
Rep. Jeff Duncan, R-S.C., chair of the House Energy & Commerce Subcommittee on Energy, Climate and Grid Security said the hearing was part of an effort to gather information for possible changes in law to better protect the grid.
“There have been several grid security incidents that have occurred recently, that we’re examining as part of our oversight responsibilities,” Duncan said. “Within the last year, we’ve seen electrical transmission substations attacked in Tacoma, Washington, and right here in Moore County. Both of these attacks resulted in blackouts that affected tens of thousands of people for multiple days.”
The Colonial Pipeline was hit by a ransomware attack in May 2021, and the subcommittee is looking into all three attacks for lessons learned to see if critical infrastructure protections would benefit from new laws, he added.
William Ray, North Carolina Department of Public Safety’s Director of Emergency Management, said information-sharing laws could be updated so the government can better coordinate with private owners of critical infrastructure.
“The percentage of the Department of Homeland Security defined critical infrastructure sectors owned by the private sector is significant,” Ray said. “We must evolve and recognize that public or private, we need the members of those 16 sectors at the table and partnerships in which they can be fully transparent.”
The information-sharing protections in place now do not adequately support open, honest and transparent dialogue between the public and private sectors, he added. Both private sector and public information need protections, while also sharing between relevant parties.
“Current federal and state information sharing, and intelligence protections do not fully address the need for open dialogue, while protecting the parties engaged as well as limiting information sharing due to classification requirements,” Ray said.
While electric infrastructure has always been targeted by copper thieves, the industry has seen an uptick in incidents that can only be described as sabotage, said Tim Ponseti, SERC vice president of operations.
“Fortunately, the bulk power system has built into it extraordinary levels of redundancy, which enhances reliability increased resilience,” Ponseti said. “It takes widespread system damage, like from a hurricane or tornadoes or ice storms, or target attack, like what happened in Moore County, to leave a large number of people in the dark for an extended period of time.”
Critical Infrastructure Protection (CIP) Standard 14 was put in place after the Metcalf Substation attack in Northern California a decade ago and it requires the industry to ramp up physical security around the most important substations that have the biggest impact on reliable operations of the grid.
Since the Moore County attack, Duke Energy, which owned the substations attacked, has been working to ensure that any substation that would lead outages if knocked out also gets heightened protection, said Mark Aysta, Duke’s managing director of enterprise security.
“We’re shifting from a tiered ranking system, focused largely on an asset’s impact to the bulk electric system, to a tiered approach with a greater focus on potential impact to customers,” Aysta said. “It’s through this lens, we’ve identified opportunities to increase security and surveillance and we’re developing implementation schedules for this work.”
While some substations can go down and grid operators can just reroute the power to avoid any significant customer impact, that is not possible at other substations and Duke is increasing security around the latter, he added.
Duke has also identified electrical components that might have long lead times to manufacture and is working to make sure it has backups on hand to bounce back after any future incidents, said Aysta.
“But we understand that even with a robust strategy of deterrence and monitoring, no utility can completely eliminate the risk of an attack,” Aysta said. “That’s the reality of operating an electrical system that extends across nearly 100,000 square miles, and includes thousands of substations, and millions of components. It is why we firmly believe grid resiliency must be a part of the conversation.”
The same technology that can detect outages from storms, isolate problems and reroute power to restore service to customers can be used to mitigate the impact of an attack on the grid. Resiliency investments are a major part of the $75 billion Duke is spending on grid improvements for its electric utilities over the next decade, Aysta said.
