FERC on Wednesday settled a dispute between NextEra Energy (NYSE:NEE) and Avangrid (NYSE:AGR) over whether the former should be responsible for upgrading a circuit breaker at the Seabrook nuclear plant in New Hampshire (EL21-3, EL21-6).
The two have been going back and forth on the project, which ISO-NE says is necessary to help support Avangrid’s New England Clean Energy Connect transmission line, since 2020.
NextEra, which owns and operates Seabrook, initially asked FERC to find that the plant should not have to take a financial loss in order to upgrade the breaker. Avangrid then filed a complaint arguing that Seabrook has been “unlawfully attempting to delay and unreasonably increase the costs of the breaker replacement.”
FERC essentially found that Avangrid’s reasoning for why Seabrook should replace the breaker was faulty, but that the nuclear plant can’t refuse to replace it because the breaker is a component of the generating facility and upgrading it is required by “Good Utility Practice.”
The nuclear plant’s interconnection agreement “does not permit Seabrook to refuse to replace the breaker when replacement is needed for reliable operation of the Seabrook Station and given the concerns in the record related to the impact of any unreliable Station operation on the reliable operation of the system,” FERC wrote.
And the principles of Good Utility Practice require Seabrook to replace the breaker before NECEC interconnects because the breaker will be “overdutied” once it does, the commission said.
An ISO-NE system impact study found that the breaker is operating at 99.6% of its capability now, but it would be at 101.2% once NECEC is in service.
While FERC has been considering the complaint, the two parties have been hashing out an agreement: The filing says that the breaker replacement is now scheduled for a fall 2024 refueling outage, with the commercial operation date for NECEC being December 2024.
According to FERC, both agree that Avangrid should pay for the direct costs of the breaker placement, but they disagree over whether the company should pay opportunity and legal costs.
FERC sided with Avangrid, saying that Seabrook can’t recover those additional costs.
“The commission typically allows opportunity cost recovery so that the resource will be revenue-neutral and therefore indifferent towards the system operator’s decision as to which service the resource will provide,” FERC wrote. “That is not the case here.”
The Virginia House Commerce and Energy Committee voted to tighten regulation of electric utility rates as disparate interests lined up behind two bills.
Representatives of Gov. Glenn Youngkin (R), Attorney General Jason Miyares (R), Dominion Energy (NYSE:D), consumer groups, and environmentalists supported a pair of bills that the committee voted out unanimously. Democrats on the committee, environmentalists and clean energy advocates, however, opposed a third bill that they argued would stymie the goals of Virginia’s Clean Economy Act.
HB 1604, sponsored by Del. R. Lee Ware (R) would give the State Corporation Commission authority to reduce an investor-owned utility’s rates if it determines they would produce unreasonable revenue in excess of the utility’s authorized rate of return. Current law requires the SCC to set utility rates based on a group of investor-owned peers in the Southeast.
HB 1670, sponsored by Del. Daniel W. Marshall III (R), moves rate reviews for Dominion and Appalachian Power (NASDAQ:AEP) from every three years to every two years.
“This bill is part of three distinct pieces of energy legislation you’ll see today,” acting secretary of Natural and Historic Resources Travis Voyles said on behalf of the governor’s office. “These legislative efforts are central to the governor’s energy plan and the commonwealth’s ability to grow — grow population, grow jobs, grow businesses — by supporting a framework that makes certain the delivery of abundant, reliable, affordable, and increasingly clean energy.”
Democratic Del. Rip Sullivan also endorsed the two bills.
“This is one of those bills that a lot of people had a lot of opinions on; a lot of people got around literal and figurative and digital tables to talk it through,” said Sullivan. “The coalition of groups and entities that are supporting this bill, I don’t know if it’s unprecedented, but it is certainly, in my view, impressive.”
Rarely are Dominion Energy, Appalachian Voices, Virginia Poverty Law Center, Southern Environmental Law Center, Americans for Prosperity, and the governor’s office all supporting the same legislation, he added.
A third bill, HB 1770, requiring that the SCC approve the retirements of IOU electric generating plants, cleared the Republican-controlled committee on a 12-10 party-line vote. The requirement would not apply to any retirements identified in integrated resource plans filed with the SCC by July 1, 2023.
Sullivan and other members of the coalition backing the other two bills opposed the third, even though they all indicated it was better than it had been.
“The bill, in my view, is better than it was when it was first filed, better than it was two weeks ago, and better than it was yesterday,” said Sullivan.
While the legislation is on the right track and could be different by the end of the session when the House and Senate have to come together to pass any final legislation, Sullivan said he could not support HB 1770 as it stands now because it contains language that could be detrimental to the Clean Economy Act that he helped pass back in 2020, which sets Virginia on a path to decarbonization by mid-century.
The bill’s sponsor, Del. Terry Kilgore (R), said he was just trying to maintain reliability by requiring SCC approve generation retirements.
“This legislation brings important oversight to the SCC,” said Voyles, again speaking for Youngkin’s office. “This will directly improve the integrity of our grid and the reliability of power.”
Demand is growing in Virginia, and the legislation will ensure that no generation retires too quickly, preventing any gaps from occurring, he added.
Sullivan said that the Clean Economy Act already gives the SCC the authority to delay retirements as needed to maintain reliability.
The Clean Economy Act had clear language that laid out a plan to get to a clean energy future by mid-century, said Sierra Club Virginia Chapter Political and Legislative Director Connor Kish.
“Our concern with this language is it sort of cuts out the ability to have a set retirement date for these facilities that would help grow the industry as it continues to move towards a clean energy future,” he said.
Companion legislation for the three House bills voted out by the committee cleared the Senate Commerce and Labor Committee last week, but they have yet to receive a floor vote. (See Dominion-backed Bill Promises Savings, but Comes with Strings.)
FERC has decided to let stand SERC Reliability’s $75,000 penalty against Duke Energy Florida (NYSE:DUK) for violating NERC reliability standards (NP23-7), along with the regional entity’s settlement with the Tennessee Valley Authority for another set of violations, carrying no financial penalty (NP23-8).
The commission announced last week that it would not review the settlements, which NERC submitted Dec. 29; the ERO submitted its monthly spreadsheet Notice of Penalty on that day as well, detailing SERC’s settlements with Virginia Electric and Power Co. for its facility ratings issues. (See related story, SERC Hits Virginia Electric with $320K in Penalties.)
Also approved last week were several settlements for infringements of NERC’s Critical Infrastructure Protection (CIP) standards (NP23-4, et al.). For these settlements, identifying information — including the utilities and REs involved, and when and where they occurred — was omitted, in accordance with NERC and FERC’s policy on CIP violations.
Duke Neglects to Coordinate Protection Settings
Duke’s penalty stems from a violation of PRC-001-1 (System protection coordination) that SERC discovered during a compliance audit in 2019. While the standard was not in place at the time of the audit, the RE determined that the violation began in 2012 when it was in effect.
Requirement R3 of the standard states that transmission operators (TOPs) must coordinate new protective systems and changes to protective systems with neighboring TOPs and balancing authorities, but SERC claimed that Duke failed to do so in 2012 and 2013 when it was conducting maintenance on its transmission lines.
The utility decided to change protective settings on its 115-kV line between Atwater and Quincy, increasing the timing on the zone 2 and 3 time distance relays to 45 cycles. However, it did not communicate the changes to the neighboring TOP, whose zone 3 relays remained set at 42 cycles. The mismatch remained in place until 2017, when the uncoordinated relays caused the neighboring utility’s breaker to trip, leading to a 63-MW loss of load on its system.
SERC found that this incident also constituted a violation of Requirement R5 of the same standard, which states that TOPs must inform neighboring TOPs of changes in their transmission systems that could require changes to the neighbor’s system. The RE said that Duke’s “failure to notify its neighboring TOP prevented the neighboring TOP from receiving sufficient information to review its systems and led to the transmission systems being mis-coordinated.”
Duke and its neighbor agreed to coordinate the timing cycles after this incident, and the changes were completed by May 2021. Additional mitigation actions by Duke include implementing setting changes to improve relay coordination and updating process documents to mandate coordination with neighboring transmission and generation owners.
TVA Reports Voltage, Maintenance Issues
The TVA settlements involve infringements of VAR-002-4.1 (Generator operation for maintaining network voltage schedules) and PRC-005-2 (Protection system maintenance). TVA self-reported both issues, which according to SERC comprised “multiple instances of smaller risk issues which, when aggravated, increase the overall risk of both to moderate.”
According to SERC’s filing, the utility initially reported its problems with VAR-002-4.1 on July 2, 2019, describing three incidents in which, as a generator operator, it failed to maintain the generator voltage schedule provided by its TOP as mandated by Requirement R2 of the standard. All three incidents occurred in April 2019 at TVA’s Watts Bar Nuclear Plant, located in Rhea County, Tenn. TVA later amended the self-report to include incidents at other nuclear and non-nuclear facilities it operated between 2018 and 2022, for a total of 287 excursions.
Mitigating actions undertaken by TVA include clarifying voltage schedule excursion requirements for responsible staff and updating equipment at affected facilities. The utility reported its completion of the mitigation plan on Feb. 2, 2022.
TVA’s violation of PRC-005-6 involved Requirement R3, which provides the schedule by which transmission owners, generation owners and distribution providers must maintain their protection systems and other components. The utility reported to SERC in May 2021 that it had discovered multiple instances of noncompliance; it had first detected the issues a year prior, but SERC determined that the violations extended as far back as 2015 and concerned PRC-005-2, the version of the standard that was in place at the time.
Places where problems were found include both transmission and generation facilities, some of which were also uncovered in the VAR-002-4.1 violation, such as the Cumberland Fossil Plant and Sequoyah Nuclear Plant. SERC and TVA identified various causes, including lack of internal controls and ineffective or inadequate internal controls. The utility’s mitigation steps included revising procedures within its PRC-005 program and creating training modules, along with testing and updates of equipment at affected facilities; the work is expected to be completed by August.
Because TVA is a federal government entity, SERC could not issue any monetary sanctions.
OLYMPIA, Wash. — With its abundance of hydroelectric resources, Washington has long been a key exporter of power to other parts of the West.
But the state’s Department of Commerce now says Washington is poised to become a net importer of electricity by mid-century as it moves to decarbonize its economy — a development that has alarmed lawmakers.
In 2021, Washington sent more than 18% of its generation to its neighbors in the Western Interconnection. By 2050, the state will have to reverse that pattern and import more supply to reach its goal of weaning itself from fossil fuels, the agency has found.
One reason: a mandate that all new cars sold in Washington by 2035 must be electric vehicles. A lot of additional electricity will be needed to keep those cars running.
In fact, the state’s efforts to replace carbon-emitting fossil fuels translates into increased demand for electricity as a substitute, said Glenn Blackmon, manager of the Commerce Department’s Energy Policy Office.
“It’s replacing fossil fuels in every sector of our economy,” Blackmon said in an interview.
“Are we planning for the amount of electricity needed to recharge these [electric] automobiles?” Sen. Lisa Wellman (D) asked during a Jan. 13 hearing of the Senate’s Environment, Energy and Technology Committee.
According to data from the U.S. Energy Information Administration, in 2021 Washington generated almost 111 million MWh of electricity, imported slightly more than 5 million MWh, and consumed a bit more than 88 million MWh, translating into roughly 18 million MWh of net exports.
At the Jan. 13 hearing, Blackmon told the Senate committee that the state’s power needs will increase by 97% by 2050 — to almost 230 million MWh. That means Washington will have to import a huge amount of power by 2050, he said.
“That’s a big thing to say we will begin importing power instead of exporting it,” Sen. Shelly Short (R) said.
The Commerce Department predicts that by 2050 36% of Washington’s clean energy will likely come from wind farms in Montana and Wyoming.
“We need more capacity to site and permit clean energy projects in a timely manner, and we need to bolster our transmission infrastructure to reliably deliver clean energy throughout the state,” Jaime Smith, spokesman for Gov. Jay Inslee, wrote in an email to RTO Insider.
Greater Need for Connection
For almost a decade, Inslee has pushed aggressively to curtail fossil fuel use in Washington, finally achieving major policy victories in the last two legislative sessions. Those included the nation’s second cap-and-trade law and a low-carbon fuel standard that went into effect this year. The legislature also set a soft goal of 2030 for reducing sales of gas-powered vehicles, followed by Inslee’s mandate last year that no new internal combustion engine cars be sold in the state as of 2035.
Inslee’s goals build on a 2008 state law that sets carbon-reduction targets of 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050. A 2021 Commerce Department report put the state’s CO2 emissions at 99.57 million metric tons in 2018. The report shows that from 2016 to 2018, the transportation sector was the largest contributor, at nearly 45% of Washington’s emissions.
With the state planning to shift from gas-powered cars to EVs in the 2030s, Washington’s power needs will grow, along with a need for more transmission lines, Blackmon said.
An analysis published by the Seattle-based Sightline Institute last October put that issue into sharper focus.
“Cascadia, like the United States as a whole, suffers from a woefully underbuilt and aging electric grid,” wrote Emily Moore, Sightline’s director of climate and energy. “The grid is so inadequate that hundreds of proposed wind and solar projects are ending up at the back of waitlists where they may sit for years. … New transmission lines (the high-voltage lines that often stretch over mountain ranges and along rivers on tall, scaffolded towers) take a decade or more to construct, giving the problem increasing urgency with each passing year.”
Moore continued: “Unless Northwest policymakers develop a plan for building out the grid we need, and unless they start erecting it immediately — through the Bonneville Power Administration, state action, utility investment, or some combination of these means — the region’s ambitious decarbonization commitments will amount to so much hot air.… That’s right. We may fail the climate test because we’re missing some wires.”
While hard figures are not available, Commerce has determined that massive construction of new power lines between Washington and other states such as Montana, Wyoming and Oregon is needed by 2050.
The state’s utilities are legally required to identify and plan for future transmission needs. However, Nicolas Garcia, representing the Washington Public Utility Districts Associations, last month told state senators that many utilities don’t have the expertise for transmission planning.
It takes 10 to 20 years to build a power transmission line corridor between Washington and another state, while it takes two to three years to build a solar or wind farm, Kathleen Drew, chair of state’s Energy Facility Site Evaluation Council, told the Senate energy committee at a Jan. 18 hearing on a transmission planning bill. Ten years is not long enough to tackle the studies, leasing, permitting, coordinating and construction of a transmission line corridor, she said.
Sen. Joe Nguyen (D), chair of the Environment, Energy and Technology Committee, has introducedSenate Bill 5165 to require utilities to begin using a 20-year planning horizon — instead of the current 10 years — to identify transmission needs.
State agencies, environmental groups and some utilities support the bill. But Avista Utilities and the Association of Washington Business said more details are needed on the processes and targets within the bill.
“It needs clearer standards and deadlines for agency decisions,” Avista’s John Rothlin said.
Three new battery technologies now under intense development in the U.S. may be key to expanding production of electric vehicles with longer ranges and faster charging times while challenging Chinese dominance of the global market.
Michigan-based Our Next Energy (ONE) and two California-based companies, Lyten and Natron Energy, explained their technologies and growth plans at BloombergNEF’s annual summit Tuesday.
Lyten, a Silicon Valley chemical manufacturer, is developing a lithium-sulfur battery it expects to market in 2025 or 2026.
Natron has developed and is already manufacturing UL-listed sodium-ion batteries that, while slightly less energy-dense than lithium-ion batteries, are nonflammable and not prone to overheating.
Deeana Ahmed, vice president of ONE, said the company has developed a battery capable of powering an EV for 600 miles per charge. The company’s battery is anode-free and built on chemistry designed to use less nickel and cobalt and more manganese, which is more abundant.
From left: Deeana Ahmed, Our Next Energy; Steven Boyd, acting director for batteries at DOE; Celina Mikolajczak, Lyten; and Natron Energy CEO Colin Wessells discussed breakthrough battery technologies Tuesday in a panel discussion moderated by Yayoi Sekine, BloombergNEF. | BloombergNEF
“We’ve been focused on the development of a North American supply chain since the founding of the company in July of 2020,” Ahmed said. “I think the momentum that we’ve seen has made that all the more plausible and possible, because we believe that by localizing our supply chain, we can then begin to approach those prices that you’re talking about with the scale up. …
“We’re partnering with BMW to demonstrate the 600 miles of range of … the platform this year. What we’re looking at is how do we grow the capacity or manufacturing capacity and maintain a conservative margin and then pass down the savings,” she said.
ONE expects “to bring manufacturing capacity online by 2024,” she said, adding that the company has already announced it will build a “gigafactory” in Michigan in the future.
The battery will “will have a very high cell to pack volumetric efficiency that allows that LFP [lithium iron phosphate] chemistry battery pack to be market-leading in terms of systems of level energy density, even when compared to a nickel cobalt battery product.”
Celina Mikolajczak, the chief battery officer at Lyten, said the company is developing lithium-sulfur battery technology even though combining the two elements “is a very difficult chemistry.”
Noting that lithium-ion batteries, especially advanced versions with higher nickel cathodes and lithium metal anodes, “are engineering wonders,” she said their high production costs mean they don’t provide “electrification for all.”
“And the reason is that there is a limited amount of nickel. And when you look at lithium sulfur, you say, ‘well, there’s a lot of sulfur out in the world. And it is very, very cheap. OK, if I can make that cell work, I make electrification something that’s abundant.’”
To tame the combination of the two elements, the company developed a graphene nanostructure carbon system that effectively controls the sulfur, she said. “The graphene helps us hold on to that sulfur, control it and make a practical battery.
“It gives us a lot of manufacturing opportunities and allows us to leverage a lot of the existing manufacturing technology. … It’s a wickedly hard chemistry, but the opportunity with it is rather incredible. It really means that we move away from petroleum as our transportation source that we allow electrification of literally everything.”
Colin Wessells, co-founder and CEO of Natron, said the company will begin mass manufacturing its sodium-ion battery in a new Michigan plant beginning this summer.
“We’ve really focused on the sodium-ion system, because it allows you to extract extraordinarily high power for energy stored,” Wessells said. “In some of our markets, some of our customers are data centers and microgrids; we have customers that are running at a 50-to-1 power-to-energy ratio.”
FOLSOM, Calif. — The CAISO Board of Governors and the Western Energy Imbalance Market Governing Body on Wednesday approved a plan to incorporate a day-ahead market into the Western EIM, calling it a milestone in regional grid integration.
“Today holds the promise for a new West, an opportunity for a new beginning in expanded markets and increased regional coordination,” WEIM Governing Body Chair Robert Kondziolka said in opening remarks. “The decision items at today’s meeting, if approved, are groundbreaking and profound.”
The extended day-ahead market (EDAM) proposal passed with unanimous votes from both governing bodies, which met in-person together for the first time since the pandemic began three years ago to exercise their joint authority over the WEIM.
After years of planning and stakeholder meetings, the EDAM promises to greatly expand the amount of electricity traded in the sprawling WEIM, which will cover nearly 80% of load in the Western Interconnection once three new members join this year. The market now deals only with real-time transactions, yet it has generated $3.4 billion in benefits for its members since it went live in late 2014.
Real-time trades are only a small part of the electricity market. Day-ahead transactions represent a far larger share. Transactions in both timeframes limit curtailment of renewable resources, such as California’s abundant midday solar power, and allow for purchases of less expensive electricity during times of tight supply.
A study prepared for CAISO by Energy Strategies found that the EDAM could generate $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection.
The West, with its 39 balancing authorities in states divided by geographic and political differences, is pursuing several major regionalization efforts, any of which could eventually establish the first Western RTO. In addition to EDAM, the Western Power Pool is awaiting FERC approval to launch its Western Resource Adequacy Program, and SPP is planning its own day-ahead market and a Western version of its Eastern RTO.
CAISO must also win FERC approval for the EDAM, which it hopes to start operating in 2024 or 2025.
‘Important New Step’
PacifiCorp, a founding member of the WEIM, became the first entity to commit to join the EDAM in December. Others are expected to follow. The WEIM now has 19 members in all Western states, except for Colorado, and stretches from the Mexican border into British Columbia.
Key provisions of the EDAM design include a resource sufficiency evaluation intended to ensure participants can meet their internal demand for electricity before engaging in the day-ahead market — a means of preventing members from “leaning” on the market for supply. The final EDAM plan includes a tiered structure of financial penalties for failing to meet the test.
“The day-ahead RSE evaluates, across the next day 24-hour horizon, whether each balancing area’s supply offered into the day-ahead market is sufficient to meet its next day forecasted load, imbalance reserve obligation, and self-provisioned ancillary service obligations,” a CAISO staff memo to the boards said. “This includes functionality to allow each balancing authority to evaluate on an advisory basis its progress toward meeting the final RSE so they may take steps to cure any anticipated insufficiencies prior to the execution of the day-ahead market.”
It also includes a provision that market participants make their internal transmission available for EDAM transfers.
“The availability of transmission, both internal to the system and across interfaces between balancing areas in EDAM, is foundational to optimizing unit commitment in the day-ahead market and to identifying robust energy transfers across the EDAM footprint,” the memo says.
Balancing authorities in the EDAM will retain control of their resource and transmission planning.
A separate decision on EDAM governance approved a plan developed by the WEIM’s Governance Review Committee that adopts the WEIM’s joint authority model for the EDAM while broadening the scope of that authority as well as the WEIM Governing Body’s solo authority over certain matters.
The governance plan was developed during many hours of stakeholder meetings and was broadly supported.
A third decision related to the WEIM and EDAM refined the ISO’s controversial wheel-through limits, which it enacted in 2021 as a temporary measure to promote in-state reliability during summer heat waves. A number of out-of-state WEIM members opposed the limits. (See FERC OKs CAISO Wheel-through Restrictions.)
Under its new plan, the ISO will calculate available transfer capability (ATC) to determine how much it needs and how much it can make available to others.
“In calculating the ATC, the ISO would set aside transmission capacity for forecasted or estimated native load needs, including load growth, and establish a transmission reliability margin (TRM) to account for different elements of uncertainty,” a staff memo said. “Management further proposes a process through which wheel through customers can request and access limited ATC that may be available on the intertie. The process requires them to demonstrate they have a firm power supply contract to serve external load or a contract conditioned on their ability to obtain ATC.”
Some stakeholders continued to take issue with the plan, saying it undermines open-access transmission principles, the memo noted. CAISO staff said the “proposed design provides a reasonable bridge between the Open Access Transmission Tariff (OATT) framework and the current ISO market structure.”
Regarding EDAM, stakeholder comments were broadly supportive, though some came with caveats about details to be worked out later.
Stakeholder comments were broadly supportive, though some came with caveats about details to be worked out later.
A coalition of 26 entities from across the West — including major utilities, environmental groups and trade organizations — expressed written support for the plan while acknowledging there is more to do.
“The undersigned entities support Board and Governing Body approval of the EDAM Final Proposal,” the joint letter said. “To be sure, all the work is not yet done, and some entities will still need to conduct their own assessments of whether and when they might expect to join the EDAM, and seek regulatory approvals if applicable.
“There will be significant implementation and market mechanics to be worked through, and the potential EDAM entities will also have to reflect the new market in their own Open Access Transmission Tariffs under which they provide service to their transmission customers,” it said. “But the basics on governance, resource sufficiency, transmission access and revenue attribution, and greenhouse gas rules enable the start of an important new step in regional market evolution.”
New York Gov. Kathy Hochul is proposing a significant expansion of the role of the nation’s largest state-owned utility.
In her budget presentation Wednesday, Hochul called for legislative authorization for the New York Power Authority to develop, own and operate renewable energy projects, and to provide bill credits from those projects to residents of disadvantaged communities.
The governor’s proposal would also require NYPA to propose a plan to phase out its small-scale gas-fired peaker plants by 2035, except when needed to support emergency services or reliability. And NYPA would also be able to fund training programs for prospective workers in the renewable energy field.
The proposal would not, however, compel NYPA to plan, design, develop, finance, construct, own, operate, maintain or improve renewable generation. It would merely allow NYPA to do so, alone or in partnership.
The concept Hochul is proposing is not new: A similar measure, the New York State Build Public Renewables Act (BPRA), was approved by the New York State Senate in 2022 but never advanced to a vote in the State Assembly.
Initial reaction to her proposal was underwhelming Wednesday, with some dubbing it “BPRA Lite.”
Public Power NY criticized it for omitting some of the more progressive aspects of the BPRA, such as its provisions for union labor and a just transition, and for pushing back the 2030 peaker retirement it stipulated.
“Furthermore, the governor’s proposal omits nearly all of the democratization elements found in BPRA,” Public Power NY said in a news release. “NYPA’s resources must be used to build as much renewable energy as it takes to protect our climate and safeguard our future, especially for disadvantaged communities on the frontlines of pollution and the climate crisis. This means ensuring a true mandate for NYPA to actually build renewables when the state is falling behind, not just reviewing our lack of progress.”
Gavin Donohue, president of the Independent Power Producers of New York, said he needs to further analyze the proposal, but on its face, it seems unnecessary.
The private sector is capable and willing to develop renewable power in New York, he said. “NYPA is not in a position to be more effective in building these projects.”
The Alliance for Clean Energy New York, which advocates for rapid adoption of renewables and represents companies in that sector, said it is opposed to the plan for several reasons, most of them boiling down to its focus. Executive Director Anne Reynolds said would do nothing to address the transmission constraints, onerous permitting process, non-standardized taxation and slow, expensive interconnection process that slow down renewable energy construction in New York.
“A better approach,” she said, “would be to harness NYPA’s resources and expertise to invest in the transmission system to unbottle opportunities to site wind and solar energy projects and open up new areas for projects, in addition to making other improvements to the investment landscape in New York.”
But as Public Power NY noted in its news release, Hochul’s proposal may be only an initial draft.
The executive budget proposed early in the year by the governor is one of the opening moves in New York’s budget process. Private negotiations between the governor and top legislative leaders; backroom lobbying by stakeholders; and campaigns to public popular support for (or opposition to) various provisions follow.
At the end of closed-door negotiations, near the April 1 start of the state’s fiscal year, the budget that emerges is different from the governor’s executive proposal, sometimes significantly. It is rushed through a vote in the two houses by the two leaders who negotiated it with the governor. Policy matters and other non-spending measures are sometimes wrapped into the budget measure to ensure quick passage.
In her memorandum of support for the NYPA proposal, Hochul said it is a necessary part of her budget plan because it will assist the state in meeting its goals under the Climate Leadership and Community Protection Act, the roadmap for the state’s clean energy transition.
Also in Hochul’s executive budget is an extension of NYPA’s authority to procure and sell power. It would extend the sunset date of Public Authorities Law from June 30, 2024, to June 30, 2044. Again, she writes, doing this will help the state meet its climate goals.
With 16 generating facilities and more than 1,400 circuit miles of transmission lines, NYPA calls itself the nation’s largest state power organization. The American Public Power Association ranks NYPA as the nation’s largest public power system by net generation as of 2020, narrowly higher than Arizona’s Salt River Project, and second-highest behind SRP by megawatt-hour sales.
General Motors plans to invest $650 million in Lithium Americas’ proposed lithium mine in northern Nevada — funding that depends on the resolution of a lawsuit environmentalists filed against the project.
GM and Lithium Americas announced the deal on Tuesday, calling it the largest-ever investment by an automaker to produce raw materials for batteries.
Thacker Pass, in Humboldt County, Nevada, is thought to be the largest lithium resource in the U.S. Lithium from the mine could be enough to produce up to 1 million electric vehicles per year, Lithium Americas said.
“It’s a landmark transaction, and it certainly won’t be the last major supply chain announcement for GM,” CEO Mary Barra said during an earnings call Tuesday.
But environmental groups are challenging the Thacker Pass project in court, saying the Bureau of Land Management broke federal law in approving an operations plan for the mine in January 2021. Plaintiffs include Western Watersheds Project, Wildlands Defense, Great Basin Resource Watch, and Basin and Range Watch, as well as tribes and a Thacker Pass area rancher.
The environmental groups said in a statement that environmental review of the project was fast-tracked under the Trump Administration “despite the enormous environmental impact to the nearly 18,000 acres of public land that would be affected by the operation.”
“The reckless permitting of the Thacker Pass lithium mine sets a bad precedent for the energy transition,” said John Hadder, director of Great Basin Resource Watch.
BLM has denied the suit’s allegations. Lithium Americas said the project has been designed to avoid environmentally sensitive terrain.
The parties presented oral arguments in U.S. District Court in Nevada on Jan. 5. They’re now awaiting a decision from Judge Miranda Du.
Two Funding Phases
Under GM’s agreement with Lithium Americas, funding from the automaker will be split into two phases. An initial $320 million investment is conditioned on a federal court ruling that does not overturn the BLM’s record of decision approving the plan. GM expects to release the first phase of funding by the end of this year.
In a second funding phase, GM will provide $330 million after Lithium Americas splits its U.S. and Argentine businesses into separate companies.
Through the agreement, GM would become a Lithium Americas shareholder and have exclusive access to Phase 1 lithium production at Thacker Pass.
Construction at Thacker Pass is scheduled to start later this year, with lithium production expected in the second half of 2026.
Other Lithium Sources
GM said it would use lithium carbonate from Thacker Pass in its Ultium battery cells. The automaker is launching a broad portfolio of vehicles using the Ultium platform, including the GMC Hummer EV pickup and SUV, Cadillac Lyriq and Chevrolet Silverado EV.
But General Motors isn’t focusing solely on Thacker Pass for a domestic lithium supply.
The automaker is also a strategic investor in Controlled Thermal Resources, a company working on extracting lithium from geothermal brine near the Salton Sea in Southern California. In 2021, GM announced a multi-million investment in CTR that will give the automaker first rights to lithium from the first stage of CTR’s Hell’s Kitchen lithium and power project. (See GM Invests Big in Calif. ‘Near Zero’ Lithium Project.)
Last year, GM and CTR expanded their collaboration to extend delivery of lithium hydroxide beyond 10 years. CTR is now recovering lithium from its Hell’s Kitchen optimization plant, the company announced last month.
Other lithium projects are making progress in Nevada.
Last month, the Department of Energy announced a $700 million conditional loan offer to Ioneer for the company’s proposed Rhyolite Ridge lithium-boron project in Esmeralda County. Funding would be through DOE’s Advanced Technology Vehicles Manufacturing (ATVM) loan program. (See Nev. Lithium Project Close to Securing $700M DOE Loan.)
The Rhyolite Ridge project is still in the permitting process; lithium production is expected to start in 2026.
Lithium Americas has applied to DOE for funding under the ATVM program for its Thacker Pass project. The loan would provide “a significant portion” of initial capital costs for the first phase of Thacker Pass, the company said.
The energy policy hive is having a healthy discussion of late taking up a question we raised 18 months ago. (See Is Decarbonization an ‘Existential’ Challenge for RTOs?) Can the single marginal price construct in ISO markets continue to work effectively given important changes to generation technologies?
ISOs and proponents of the status quo have risen to defend the single locational marginal price (LMP), at least when applied in energy and related ancillary service markets. They assure that reform and expansion of the construct is possible to meet new challenges, and they quickly dismiss any notion of a fundamental rethinking. Their arguments extolling LMP are not wrong; they’re misplaced.
And they’re the same arguments raised since LMP was introduced. Indeed, a recent report, prepared by Professors William Hogan and Scott Harvey for the NYISO, walks step by step through more than 30 years of LMP history to conclude that:
economic theory and extensive practical experience demonstrate why the real-time locational marginal price is the only real-time pricing system that supports an efficient wholesale electricity market.
Vince Duane | PJM
In comments this month to FERC and in reply to our prior writings, PJM’s market monitor endorses Hogan and Harvey’s recent paper. Much of the paper and comments in support simply recite (once again) the benefits that LMP offers as an efficient mechanism to dispatch, balance and schedule generation resources, price transmission congestion and reveal locational incentives and signals. We don’t disagree.
LMP is great — let’s get that out of the way. Our criticism is not with LMP in theory. Instead, we’re seeking a dispassionate assessment of how LMP is actually performing today and its prospects for success in the future. Since its inception, the single marginal price market for energy has delivered on much of its promise, although only a zealot would deny its limitations, as evidenced by what our initial paper calls those “compensating fixes” (typically complex, imperfect and contentious) that tinker with or supplement LMP prices depending on circumstance. But can this delicate construct effectively manage a transforming grid?
Our writings pose several questions, most ignored in rebuttal, suggesting why past performance might not be indicative of future results. But on one point we seem to be talking past each other.
Electricity today is physically injected onto the grid by an array of generating and storage technologies having disparate operating attributes. These injections vary in character from one another (not to mention they’re poles apart from “virtual injections” offered by financial traders and demand response providers). Although these various injections each present a different profile to the system operator charged with keeping the lights on, from a market settlement perspective all are regarded as equal and paid the same. As the physical and virtual supply stack further evolves, can we continue to treat these injections as sufficiently homogenous in character to justify a single market, with a single clearing price paid to all? As we have said previously, the only thing fungible (or in the parlance of economists, “perfectly substitutable”) when it comes to electricity is the electron itself. But no buyer, including particularly the system operator, is buying mere electrons. The megawatt-hour is in fact a highly bundled product with varying operational attributes such as its constancy (or variability) over time, its ramping and load following attributes, its stability and inertia properties, its on-demand availability/dispatchability, etc. All these properties, in the right balance, are critically important to the operator in maintaining system reliability.
Some dismiss the question of megawatt-hour fungibility or substitutability as an empty formalism. And if we insisted on perfect fungibility, we’d agree with the characterization. Although treating electricity in LMP markets as fungible has always been a problematic exercise in applying “compensating fixes,” it’s been workable enough to unlock much of the benefit summarized by Hogan, Harvey and others. But make no mistake, the very basis underpinning the law of single price is a presumption of commoditization.
Here lies the problem. The debate isn’t about the merits of LMP. It’s about whether the penetration of new and transforming supply-side technologies (and demand response resources) permits us to continue to hold to a necessary predicate underlying LMP.
The following statement to RTO Insider from Professor Severin Borenstein, board member at CAISO, illustrates the communication gap:
The idea that everybody gets paid a uniform price is how commodity markets work, not just for electricity — for natural gas, for gold, for oats, for everything. There’s a market price, and people will get paid that market price because they’re selling a homogeneous good.
Similarly, Hogan and Harvey’s paper includes the oft-repeated admonition about the 1970s-era misadventure in pricing “new” and “old” oil differently. These responses miss the point. Of course, commodities should transact at a uniform price — assuming they are commodities, which is to say essentially homogenous like oil, gold, oats or anything else meeting the definition of a commodity. But equally, a market that pays the same price for different things has a problem.
Presuming we can treat equally all injected megawatt-hours regardless of the unique operational attributes associated with these injections deserves scrutiny considering changing technologies. Comments filed recently with FERC in Docket No. AD21-10 by Professor Leigh Tesfatsion offer the same, but expanded, explanation for why electricity is not like oil, gold and oats and thus why:
all attempts to justify the (day-ahead/real-time market) two-settlement system (based on LMP pricing) by means of the efficiency and optimality properties of competitive commodity spot markets (based on competitive marginal cost = marginal benefit pricing) are conceptually unsupportable.
As the legion of rulemakings pending before FERC attest, there’s no shortage of argument and opinion about the type of institutions/structures, electricity market design and transmission policy we need to facilitate grid transformation. Which is why it’s puzzling to see the intellectual architects and master builders of the current ISO structure avoid engaging on this question of electricity as a commodity. Yes, the consequences that follow from finding that a bedrock presumption no longer holds will be profound and provoke a wholesale rethinking. Here again we say read Professor Tesfatsion’s comments where she explains — ironically given how economists largely populate the field of electricity market design — that we might be ignoring the dictum of “sunk costs as sunk.” Her comments introduce the “Ptolemaic Epicycle Conundrum,” drawing on history’s long and difficult road in accepting a Copernican sun-centric solar system by thinkers (and institutions) invested in Ptolemy’s earth-centric system. This conundrum arises once we’ve all invested heavily in a certain model and layered on fix after fix as problems present, only to arrive at a sad place where “the correction of the fundamental conceptual inconsistencies in the core design principles is persistently deemed to be too costly to correct.”
So, let’s challenge the leading lights of energy economics and academia to prove that single clearing price LMP energy markets have not become “too big to fail.” Let’s examine the many ways electricity is being injected onto the grid today and the different operational attributes attendant to these injections, to ask whether a bedrock principle that directs us to pay all injections the same marginal price (varying potentially only by location) continues to hold. Answering this question is what we’re looking for from these folks — rather than a rote repetition of LMP benefits.
Former FERC commissioner Tony Clark, a senior adviser at Wilkinson Barker Knauer, has represented several vertically integrated utilities in matters regarding utility deregulation and has authored several papers critiquing retail restructuring of the electric utility industry.
Vincent Duane, the former SVP for law, compliance and external relations for PJM, is principal of Copper Monarch, which provides advice on electricity market design, governance and strategy for system operators and companies that work with them. He also is a senior adviser to Market Reform, an international consultancy.
PJM members’ vote last week to limit resources’ capacity interconnection rights is not likely to end the dispute over how the RTO accredits intermittent resources.
Economist Roy Shanker, who filed a FERCcomplaint on Nov. 30, said Monday that members’ vote to change the rules was insufficient (EL23-13).
Shanker’s complaint alleged that PJM has been improperly permitting energy above renewable resources’ capacity interconnection rights (CIRs) to be entered into the Reliability Pricing Model (RPM) auctions as capacity, a practice he says is in violation of the RTO’s Reliability Assurance Agreement (RAA) and the interconnection service agreement (ISA) for each generator.
The result of the alleged over-accreditation, Shanker said, is diminished reliability, load overpaying for “phantom capacity” that does not meet reliability standards, artificial reduction of capacity prices for other resources; and inefficient economic decisions from market participants acting on potentially inaccurate information.
In response, PJM on Jan. 17 argued that the complaint stems from a mischaracterization of its standard ISA, which states that “to the extent that any portion of the customer facility described in section 1.0 is not a capacity resource with capacity interconnection rights, such portion of the customer facility shall be an energy resource.”
PJM said Shanker attempted to link this language to its accreditation of unforced capacity (UCAP), where no connection exists. Instead, it says the section is “a simple acknowledgement that a device is physically capable of providing energy above its CIR value, up to its maximum facility output level.”
Pointing to FERC’s 2021 approval of its effective load-carrying capability (ELCC) construct, PJM argued that the protest constitutes a “collateral attack” on the commission’s past ruling and called it to be rejected as an “attempt to revive arguments rejected in prior proceedings.” (See FERC Accepts PJM ELCC Tariff Revisions.)
PJM also said Shanker did not demonstrate that the complaint is in response to an injury and that, as such, he lacks standing.
Shanker argued that FERC’s order accepting the ELCC methodology was partly based on testimony in which PJM presented “incomplete and misleading” information about ISA provisions, as well as the difference between test conditions and normal transmission relating to accreditation. He also said FERC’s approval of the accreditation methodology was never codified into PJM’s governing documents.
He noted that in its order accepting the ELCC construct, FERC wrote that PJM had stated that it will account for “historically binding transmission constraints by considering each variable resource’s historic performance, including instances of curtailment due to transmission constraints.” This has not been the case, he argued, writing that when defining CIR levels and deliverability requirements, PJM does not look at dispatch, system operation and the relative price of resources.
“PJM previously presented incomplete information to the commission in terms of the underlying facts related to this issue in material ways. When this is recognized, the entire prior conclusions of the commission become ‘flipped,’ and it becomes clear that output from an energy resource (defined as effectively ‘not capacity’) should be excluded in accreditation of variable resources with respect to the amount of AUCAP [accredited UCAP] they can sell (or should even be considered in any ELCC calculations),” Shanker wrote.
In comments defending PJM’s practice, a group of environmentalist and clean energy organizations jointly argued that Shanker’s complaint is based on a misreading of PJM’s tariff that each megawatt of capacity must equal 1 MW of deliverable power. With this interpretation, they write that FERC’s findings in the 2021 ELCC filing were well-informed and correct.
“The commission was not misinformed, but instead reached a well considered decision that it agreed with PJM on a disputed issue — a determination for which Dr. Shanker’s client in that matter did not seek rehearing,” said the Sierra Club, Natural Resources Defense Council, American Clean Power Association and Solar Energy Industries Association.
They also argued that the current practice does not introduce any reliability risks, as repeat PJM analysis has not identified any transmission upgrades required for existing intermittent resources. Citing information from PJM’s Data Miner portal, they also noted that wind resources delivered energy 350% times their CIR level during the December winter storm.
Stakeholders’ Accreditation Proposal may not Address all Issues
The Markets and Reliability and Members Committee endorsed a proposal last week addressing some of the same issues in Shanker’s complaint, including language that would cap the hourly output of resources to their CIR rating when using the ELCC analysis to set their accreditation. Shanker told RTO Insider Jan. 30 that the proposal would not, however, resolve the issue of hourly input above CIRs being entered into the accreditation for resource classes, leading to resource types being allocated inflated capacity payments to be divvied between generators in that category.
The proposal would limit the slice of the pie that an individual generator can receive but would continue to allow intermittent resources to have an overly large portion reserved for them, Shanker said. He also noted that the endorsed language remains a proposal and still requires the approval of the PJM Board of Managers and FERC.
“It never goes away once it gets into the database,” Shanker said of energy output above CIRs being included in resource class accreditation. “The pie increases, and it will always get allocated to someone.”
The complaint also asks that FERC order PJM to change its accreditation methodology immediately and potentially provide a form of retroactive relief. This would effectively eliminate the transition methodology included in the endorsed proposal, which would create a system for generation owners to submit uprate requests and seek access to available headroom on the transmission system until PJM processes their request for higher CIRs in the interconnection queue. Without the formal execution of an ISA recognizing the higher CIRs, Shanker argued that PJM does not have the power to grant a resource a claim on any available transmission headroom.
In comments on the complaint, the Independent Market Monitor agreed that PJM’s tariff dictates that the ELCC methodology must cap the hourly output for a generator at its CIRs when determining accreditation for both individual units and resource classes. The impact of PJM’s current practice has been overstated intermittent capacity suppressing the final clearing price in recent Base Residual Auctions (BRAs).
“PJM has, to date, based on a mistaken interpretation of the market rules, based on an initial oversight, included energy deliveries above the level of CIRs obtained for intermittent resources in defining the ELCC values for those resources, affecting both the capacity value of individual resources and the capacity value of the total ELCC resources and therefore capacity auction clearing prices,” the Monitor wrote.
Had the correct accreditation been used for solar resources in the 2022/23 BRA, the IMM estimated the resource class average derated MW would have been 20% lower, while for wind resources it would have been 48.9% lower. Ultimately the IMM estimates that generator revenue would have been 4.4% higher with the proper ratings.
The Monitor called on FERC to require that PJM correct its definition of the capacity available from intermittent resources for the 2025/26 BRA and to not permit that auction to go forward until the issue has been resolved. The auction is currently scheduled for June 14, 2023.
