Search
`
November 4, 2024

Posted on

Big Savings for Tx Competition Claimed as FERC Considers a New ROFR

The Electricity Transmission Competition Coalition released a report Nov. 29 arguing that getting rid of competitive forces in transmission development would cost consumers hundreds of billions of dollars on the grid buildout. 

“Without competition, consumers are going to be faced with decades of high electricity inflation,” ETCC Chair Paul Cicio said in an interview. “We all know that transmission is very capital intensive, and even with competition, consumers’ electricity bills are going to go up. But with competition, we can avoid up to on average 40% of the cost of new transmission.” 

That 40% figure would involve more transmission competition than has happened so far. While FERC ended the federal right of first refusal with Order 1000 more than a decade ago, since then just 3 to 8% of all transmission lines have been subject to competition, ETCC said. 

Getting a third of all transmission development subject to competition would save $277 billion on the $2.1 trillion in transmission expansion that Princeton University forecast in its often cited “Net-Zero America” study. If all new transmission projects were open to competitive bidding at an average cost savings of 40%, it would save $840 billion on that buildout. 

Transmission lines can get returns on equity of 10 to 12% for periods lasting 40 years, but competitive bidding can push that ROE down, ETCC said. 

“Competitors can say, ‘Well, instead of accepting a 12% return on equity, our bid on this project is 10%,’” Cicio said. “That automatically is a lower cost to consumers, so competition drives down costs.” 

In its Notice of Proposed Rulemaking on transmission planning, FERC went the other way, finding that total elimination of a federal ROFR for incumbent utilities on transmission lines running through their territories led to “flawed incentives” that might prevent the most efficient transmission from being developed. The NOPR would allow a ROFR to be reinstated as long as utilities work with another party on any lines (RM21-17). (See Battle Lines Drawn on FERC Tx Planning NOPR.) 

“The real concern here is that competition, when you put it in the context of transmission, is a much more complicated issue than it would be, say, in the generation side,” WIRES Group Executive Director Larry Gasteiger said in an interview. “And what we’re seeing in reality is that things are taking longer, because the processes are much more involved.” 

The two largest RTO markets offer different experiences in building out regional transmission lately, with Gasteiger noting that MISO, with its high share of state ROFR laws, is often touted as successful with its Multi-Value Project portfolio. 

“So, in my mind, that kind of calls into question this argument that you need to have competition in order to get transmission done, and to get it the cheapest possible way,” Gasteiger said. 

PJM has a much different process, leaving policy-based lines up to the states driving those needs. Its utilities’ spending on local transmission has often been criticized, including in a complaint by the Ohio Consumers’ Counsel (EL23-105). The OCC alleged that Ohio utilities had unjustly spent $6 billion on local supplemental projects since 2017, pushing up electricity rates. 

Ohio’s utilities have responded that the OCC failed to show any evidence that they are overspending on such projects, and that it should be left to the state to oversee them. Both sides of the broader transmission-competition debate have weighed in on the complaint as well, with WIRES attaching a Charles River Associates report on the benefits of local transmission planning to its comments. 

“Notwithstanding the challenges that there may be with getting regional, and even more so interregional, transmission [built], that doesn’t mean we don’t need a lot of local transmission developed too,” Gasteiger said. “So, the fact that we’re actually just getting something done at the local level doesn’t necessarily mean that is bad, or that it is wrong. What it means is that it’s needed, and it’s actually getting accomplished.” 

ETCC did not weigh in on the complaint, but many of its members did. Cicio noted that it highlights another part of ensuring costs are low for customers as the grid expands. 

“There’s the oversight to make sure that we need the project,” Cicio said. “The second part, if we need the project, it needs to be competitively bid, so that it reduces costs. It’s a two-step process.” 

ETCC’s report, titled “FERC’s $277 Billion Electricity Price Hike,” focuses on consumer costs, reporting that the price of electricity has outstripped inflation in recent months, despite declines in the cost of other energy commodities including gasoline and fuel oil. One in five U.S. households have struggled to make a utility payment in the past year, and 26% of homes have experienced energy insecurity, it says, citing data on energy affordability from the U.S. Census Bureau. 

“Even the Federal Trade Commission and the Department of Justice of this Biden administration weighed in, in writing, to FERC saying: ‘FERC, do not back away from competition,’” Cicio said. “And, so, we hope that they will do the right thing and strengthen Order 1000 and require all projects that are 100 kV or larger to be competitively bid.” 

Gasteiger did not push back against the census data, but he did question whether transmission competition would really save hundreds of billions of dollars in future investments. 

“Their savings projections are just that: They’re projections,” he said. “They’re hotly contested. And the track record shows that they’re often not reliable.” 

Ultimately, these questions will be answered by FERC whenever it issues its final rule, he said. 

WIRES does not want to see competition for transmission expanded, arguing that would delay transmission that is successfully getting built under the current regulatory model. Competitive transmission might work for the very-hard-to-build lines that stretch across multiple states to ship renewable power long-distance, or in similar transmission projects that help meet public policies, Gasteiger said. 

“See if you can get it to work, and then build on that,” Gasteiger said. “But if not, don’t just automatically start expanding into areas where we’re actually getting transmission built and jeopardize the ability to get that transmission built as well.” 

Posted on

FERC Approves Agreement Resolving Versant Audit Issues

FERC approved an agreement among Versant Power, the Maine Public Utilities Commission (PUC) and Maine Office of the Public Advocate (OPA) related to improperly classified expenses that resulted in the overbilling of wholesale transmission customers (ER23-1598).

The issues were first identified in a 2021 audit report issued by the Commission’s Office of Enforcement, which found that Versant improperly capitalized about $18 million in overhead costs, causing the company to overcharge transmission customers.

The company issued refunds in May 2022 and filed in April 2023 to recover some of the overhead costs over an extended period.

The Maine PUC protested this filing, expressing concern about its lack of refunds for retail customers, the potential double-charging of retail customers during the recovery process, and the potential for the proposal to “improperly result in wholesale and retail customers paying Versant a rate-of-return on improperly collected costs.”

In September, Versant submitted an agreement signed by the company, the PUC and OPA to resolve the issues raised by the PUC and establish a process for the company to recover the overhead costs.

The parties agreed to amortize about $15.6 million over eight years, intended to account for the difference between the overhead costs and the refunds owed to retail customers.

On Nov. 28, FERC ruled the agreement “appears to be fair and reasonable and in the public interest and we therefore approve it.”

A spokesperson for Versant told RTO Insider the settlement is fair and “beneficial to both the company and our customers.”

Posted on

CARB to Consider Transferable ZEV Truck Credits

The California Air Resources Board is exploring whether zero-emission truck credits that manufacturers earn under the Advanced Clean Trucks regulation should be transferable among states.  

Truck manufacturers say they need the flexibility of credit transfers — also known as credit pooling — to comply with the regulation, particularly in its early years. Advanced Clean Trucks (ACT) requires medium- and heavy-duty truck manufacturers to sell an increasing percentage of zero-emission vehicles each year in states that have adopted the rule.  

In addition to California, eight states have adopted ACT: Massachusetts, New Jersey, New York, Oregon, Washington, Vermont, Colorado and New Mexico.  

But officials in ACT states say that if the required zero-emission trucks go to other states, they’ll lose out on air quality and climate benefits of the vehicles.  

The debate played out during a CARB workshop on Tuesday regarding ACT credit transfers.  

“All pathways to achieving our greenhouse gas reduction targets require switching from fossil fuel vehicles to zero-emission vehicles,” said Rachel Sakata, transportation strategies section manager in the Oregon Department of Environmental Quality. “And given the urgency of the climate crisis, it is crucial that this transformation accelerates to scale as soon as possible.”  

But Tim French of the Truck and Engine Manufacturers Association said that without credit pooling, manufacturers might have to resort to reducing sales of all trucks in a particular state so they can meet the percentage sales requirement.  

“Without credit pooling — and not to be alarmist — there is an increased risk of product shortages in the opt-in states,” French said during the workshop.  

James Clyne with the New York State Department of Environmental Conservation said ACT already gives manufacturers flexibility through measures including credits for early ZEV sales, credit banking and trading, and some credit for near-zero-emission vehicles.  

“The underlying concern in [ACT] states is that pooling could water down ACT sales requirements,” Clyne said. “Flexibility already exists. It is imperative as a first step to determine whether pooling is warranted at all.”  

Clean Truck Partnership

The discussion of pooled credits results from an agreement announced in July between CARB and leading truck manufacturers. (See CARB, Manufacturers Partner to Support Clean Truck Rules.)  

Under the deal, known as the Clean Truck Partnership, truck makers agreed to sell as many zero-emission trucks as reasonably possible in every state that has adopted ACT, even if there are legal challenges to the regulation.  

In exchange, CARB promised to provide more compliance flexibility in ACT. That includes giving manufacturers three years, rather than one year, to make up deficits in meeting ZEV requirements. CARB also committed to holding a workshop this year to discuss ZEV credit pooling.  

CARB released draft text this month for potential ACT amendments, including the increase to three years for making up deficits. CARB staff said their goal is to finalize the rulemaking in 2025.  

Light-Duty Rules

Credit pooling is part of CARB’s zero-emission rules for light-duty vehicles, Advanced Clean Cars II. Manufacturers can use excess ZEV or plug-in hybrid credits to meet a portion of compliance requirements in another state. Credits can be transferred only to fill a deficit.  

In its 2012 version of Advanced Clean Cars, CARB established east and west regions for credit pooling, with California excluded. Manufacturers faced a 30% premium for transfer between the two regions, according to CARB staff.  

But pooling was not included in ACT when CARB adopted it in 2020.  

ACT will take effect in California starting with model year 2024 trucks. The effective date varies in other states but starts as soon as model year 2025 in Massachusetts, New Jersey, New York, Oregon and Washington.  

CARB announced last month that about 8,900 zero-emission trucks from model years 2021 and 2022 have been sold in California or are expected to be sold based on uptake of incentives. That’s about 60% more than the 5,500 ZEVs that CARB estimates will be needed to meet the model year 2024 quota. (See California Far Outpacing Clean Truck Targets.)  

Posted on

NYISO Management Committee Briefs: Nov. 29, 2023

Internal Controllable Lines

NYISO’s Management Committee voted Nov. 29 to approve tariff revisions establishing market rules for “internal controllable lines” (ICLs), recommending they be approved by the Board of Directors.

The ISO’s Business Issues Committee previously approved the provisions, which set energy market, capacity market and market mitigation rules for ICLs. Clean Path New York, a 175-mile, 1,300-MW HVDC line selected as a Tier 4 project to deliver renewable power from upstate to New York City, will soon become the state’s first ICL. (See “Internal Controllable Lines,” NYISO Stakeholders Advance Rules on Ambient Ratings, Internal Controllable Lines.)

The changes seek to optimize ICL flows through economic dispatch and prohibit bilateral energy market transactions using ICLs as their source or sink. Additionally, ICLs will have defined operating ranges, bid curves and ramp limits to ensure system stability.

If approved by the board, the rules are expected to be filed with FERC in the first quarter of 2024.

Ambient-adjusted Ratings

The MC also moved to approve and recommend the board approve tariff revisions aligning day-ahead market (DAM) congestion settlement procedures with ambient-adjusted ratings (AARs).

FERC Order 881 requires transmission providers to evaluate transmission capacity based on real-time environmental conditions and mandates the use of AARs for short-term transmission requests, and seasonal ratings for long-term requests (RM20-16).

The ISO’s proposed revisions address discrepancies between AAR rating limits in the DAMs and those used in transmission congestion contract (TCC) auctions. The changes revise calculations for the congestion rent impacts of uprates and derates and create a new category of qualifying events, which emerge from differences between the DAM ratings required by Order 881 and those assumed in TCC auctions.

The BIC also previously approved these revisions. (See NYISO Stakeholders Advance Rules on Ambient Ratings, Internal Controllable Lines.)

If approved by the board, the ISO plans to implement these revisions alongside compliance proposals already accepted by FERC.

Posted on

NJ Launches 2nd Solicitation Under Solar Incentive Program

New Jersey’s Board of Public Utilities (BPU) on Nov. 27 launched its second attempt to solicit solar projects at a price the agency considers acceptable to ratepayers, driven by the hope that the high costs that derailed a similar solicitation earlier this year have subsided.

The three-month-long solicitation, which will close on Feb. 29, seeks bids under the Competitive Solar Incentive (CSI) program for “grid supply” solar installations and nonresidential net-metered solar installations with a capacity greater than 5 MW. Also eligible under the program are grid-supply solar projects combined with energy storage.

The solicitation, which could award projects totaling up to 300 MW of capacity, follows a similar process to the last one, for which bidding closed March 31; the BPU terminated it in July by rejecting all the bids because they were too high. The BPU did not say at the time how many bids were submitted but said they were all above confidential price caps it had developed. (See NJ Rejects Solar Bids as Too Expensive.)

In response, the board made changes to the solicitation rules and evaluated the process by which the price caps were determined.

The order launching the new solicitation, approved Nov. 17, said the board anticipates that “competition amongst solar development projects will arise organically.” It expressed the belief that the prices of the solar renewable energy credits submitted by bidders would “provide the amount needed to enable development, without over-incentivization.”

“The board anticipates that certain factors that may have pushed bid prices to a high level, including expectations around component costs and inflation, as well as regulatory uncertainty at the federal level, have abated, creating a more favorable competitive environment,” the order said.

The solicitation presents a test for the board’s CSI program, in part to see whether bidders will come forward after the board rejected all the last bids and whether there is sufficient interest in the program as a whole to help the state achieve its ambitious solar goals. BPU officials have cited the program as a key element in the state’s effort to install 12.2 GW of solar by 2030 and 17.2 GW by 2035. The latest BPU figures, as of Oct. 31, show the state has a total installed capacity of 4.655 GW, about 40% of the 2030 target and slightly more than one-quarter of the 2035 goal.

Setting Correct Price Caps

The CSI is part of a two-pronged effort to stimulate solar development with incentives under the Successor Solar Incentive (SuSI) program, which was enacted in July 2021 to replace predecessor programs that critics said were too generous.

The BPU sets the incentive levels in the first part of the program, known as the Administratively Determined Incentive (ADI) program, which caters to net-metered residential projects, net-metered nonresidential solar projects of 5 MW or less, and community solar programs. Incentive levels in the CSI, which covers projects of 5 MW or more, are set through a competitive solicitation.

The CSI program awards incentives in four market tranches: basic grid-supply projects; grid-supply projects sited on the built environment; grid-supply projects sited on contaminated sites and landfills; and net-metered nonresidential projects greater than 5 MW. Project developers submit bids on the level of incentive they would need to complete their projects. In a separate part of the CSI program, projects that incorporate a storage element first submit a bid solely for the solar project and then submit a price for the storage.

The BPU order said that after the first solicitation produced excessively high bids, staff and consultant Daymark Energy Advisors analyzed the outcome and concluded that a “spike in energy prices in the fall of 2022 resulted in an estimate of energy revenues for solar projects used for modeling that was likely higher than the estimates used by developers in the spring of 2023.”

In addition, the analysis showed that there were “uncertainties in the energy and capacity markets” and that “interest rate spikes beginning in 2022 and carrying on into 2023 likely drove developer cost projections higher than those reflected in the initial solar price cap analysis.”

“In a competitive solicitation, incentive values should reflect current market conditions and provide a long-term, guaranteed incentive structure for developer investment,” the order said. “Price caps serve as a protective mechanism against noncompetitive bids and would generally be set at a level that exceeds expected competitive bids.”

In response, BPU staff recommended that the board again use confidential price caps in the second solicitation. However, the order also said the caps should vary for different types of projects. Thus, the caps on grid-supply projects on a built environment and those on contaminated sites and landfills in the solicitation are 15% and 32%, respectively, higher than the cap on basic grid supply submissions. The cap on net metered nonresidential projects above 5 MW is $20 higher than the cap on basic projects.

The board also agreed to award bids that are up to 10% higher than the price cap if the project warrants it.

To encourage repeat bids, the board this time has waived the fee for developers who submit a project that is largely similar to one for which they put in a bid in the first solicitation.

Posted on

As COP28 Begins, Experts Say Paris Agreement Targets Are Out of Reach

DUBAI — Hydrocarbons are not going away anytime soon despite growing climate financing and escalating renewables deployment, leaving little chance of reaching the Paris Agreement target of limiting global warming to 1.5 C, said industry analysts at an S&P Global Commodity Insights event held the day before COP28 officially opens in Dubai. 

This year’s Conference of Parties (COP) climate negotiations will illuminate the gap between ambition and action as countries report on how they’re progressing against stated targets in emissions reductions.  

“There will be a stock take around where we said the world would be and where the world actually is,” said Saugata Saha, president of S&P Global Commodity Insights. “Our sense is that the stock take is going to show that emissions currently are roughly two times what it needs to be or what it should be to get us to a 1.5-degree scenario by 2100.” 

While S&P Global’s analysts were able to force two scenarios that would limit climate change to a 1.5 C rise, no one saw those scenarios as likely to unfold given the massive scope of the change needed and the pace of change to date.  

“Fossil fuels have never represented less than 80% of global total primary energy demand since the 1990s, and probably going back many years before that,” said Paul McConnell, executive director of climate and sustainability at S&P Global Commodity Insights.  

The event coincided with the release of a discussion document, “Energy Transition: Strategic Choices Demonstrating Progress.” S&P Global’s analysis included several scenarios, and its “Base Case” scenario reflects a faster-than-expected decline in demand for fossil fuels as well as an acceleration of renewables deployment. But even with that better-than-expected transition, that scenario still results in 60% of the global primary energy mix coming from fossil fuels by 2050 and a 2.4 C temperature rise by 2100.  

“Energy is not the enemy. Emissions are the enemy, and that’s what we need to be thinking about,” Saha said.  

S&P Global’s base case view expects faster declines in demand for fossil fuels and emissions of GHGs, and accelerated growth for renewables | S&P Global

Saha suggested paying close attention to how the future of fossil fuels is discussed at COP28. “We anticipate there will be a lot of conversation around ‘phase out’ versus ‘phase down’ and abated versus unabated use of fossil fuels,” he said. “Those will have a meaningful impact on what the next few years look like.” 

The phaseout — or lack thereof — of fossil fuels has gained additional attention after the Centre for Climate Reporting and BBC revealed that the president of COP28, Sultan Al Jaber, an oil industry executive, planned to use the climate talks to do oil deals, confirming the fears of climate activists who questioned both the location of COP28 and the industry ties of the talks’ president. 

When looking at energy from hydrocarbons, it’s important to distinguish those energy sources based on carbon intensity, he said, citing the sixth edition of Platt’s “Periodic Table of Oil” which maps carbon intensity of the many distillates derived from various grades of crude oil.

Saha noted the wide variances in the carbon intensity of various grades of crude oil, and that “even within a particular grade of crude oil, there can be further significant variances of carbon intensity based on the field of production, the producer, the assets, etc. This is one example where we made a start to assess carbon intensity, provide transparency to the markets and make sure that we are creating the framework for people to make good decisions.” 

Beyond the Energy Transition: The Trilemma

Saha said the conversation has changed over the past few years from being focused on the energy transition to looking at solving what he calls the energy trilemma: sustainability, security and affordability.  “Balancing these three is no mean feat.” 

While energy sustainability is self-explanatory, security — making sure there’s access to energy as and when needed — has taken on new importance. 

“Some of the recent geopolitical events over the last three years or so, and some of the supply chain shocks which continue to do this day, amplify the need for energy security as a part of the equation that needs to be solved,” Saha said. 

“Energy affordability is equally important. We shouldn’t lose sight of the fact that there are a few billion people who are counting on affordable sources of energy as a means [of] alleviating poverty or getting a few hundred million people onto a path to prosperity,” he said. 

Financing the Energy Transition: Some, But Not Enough, Good News

An uptick in energy-transition-related financing indicates the business case is getting more attractive, Saha said.  

“Financing is important because A, it makes things happen, and B, it is a very good leading indicator which shows how capital is being deployed to solve problems of tomorrow,” he said. “We know that energy transition-related financing is approaching a $2-trillion-a-year number globally with about half a trillion of that coming from the U.S., and that’s the good news. Part of the bad news is this is a fraction of what is required.” 

Posted on

Ameren Files to Recoup Rush Island Closure Costs from Customers

Ameren Missouri appears to be making good on a two-year-old announcement to close its Rush Island coal plant, which has racked up multiple Clean Air Act violations over the years.

Last week, Ameren Missouri filed for permission with the Missouri Public Service Commission to use securitization to finance the closure of the plant through ratepayers (EF-2024-0021). The utility said it wants to wind down operations by mid-October next year to avoid installing sulfur dioxide scrubbers per a court order.

The financing option Ameren seeks is possible through a two-year-old Missouri law that allows utilities to securitize outstanding debt on their facilities to further the energy transition. If approved, Ameren would be free of Rush Island debt and free to invest in other generation, while investors paying the bonds would be guaranteed a return of 2% to 4%. The securitization would result in a new line item on monthly bills of $1.71 for the average residential customer for the next 15 years.

Ameren estimates it has more than $475 million of undepreciated investment in Rush Island today.

Despite the request for ratepayer-backed bonds to recoup plant investment, Ameren pledged customer bills would decrease with the earlier-than-anticipated retirement. It estimated customers would save $120 million over 15 years.

In its filing, Ameren said “costs of securitization are lower than traditional ratemaking” and concluded that “retirement of Rush Island instead of retrofitting the plant with expensive pollution control equipment is clearly in customers’ best interest.”

In testimony to the Missouri PSC, Ameren Missouri President Mark Birk said by the time the order from the U.S. District Court for the Eastern District of Missouri to scrub Rush Island became final, “circumstances had made the continued operation of coal-fired plants extremely challenging.”

He said EPA’s proposal to limit carbon emissions from existing coal plants poses “serious risks to the continued viability of these assets,” so installing hundreds of millions of dollars’ worth of scrubber equipment is unwise.

“Faced with these realities, the only prudent option was to shut down Rush Island instead of adding scrubbers,” Birk said.

For resource planning purposes, Ameren long assumed the 1.2-GW plant would retire sometime in 2039.

The embattled coal plant has been at the center of a yearslong legal battle over its emissions. In 2007 and again in 2010, Ameren replaced boiler components at Rush Island that upped output without completing a new source review as required under the Clean Air Act, triggering a lawsuit from the Sierra Club and an eventual court order to install pollution controls or shut down.

Birk said the securitization of the cost of retirement for Rush Island is appropriate because Ameren made “prudent decisions” when making investments in the plant. He argued that at the time, the boiler upgrades were viewed as routine and completed by other utilities without a new source review.

The District Court in late September approved Ameren’s decision to retire the plant in October 2024. It previously said the plant should cease operations in March.

Whether Rush Island can retire by October is unclear. Ameren itself cautioned in its filing the new retirement date could change.

The plant has been operating for more than a year under a MISO-designated system support resource (SSR) agreement, used to keep generation operating past planned retirement dates for the sake of system reliability.

MISO last year deferred Ameren Missouri’s planned retirement of Rush Island to keep the grid reliable. The utility pulls in a FERC-approved $8.3 million monthly payment to keep the two-unit Rush Island Energy Center operating (ER22-2721). (See FERC Approves Lower MISO Reliability Payments to Ameren Coal Plant.)

In early summer, MISO said it likely will require the assistance of Rush Island for nearly two more years to avert voltage violations until members complete transmission upgrades and bring wind, solar and battery storage projects proposed in Illinois and Missouri online. The RTO previously said it plans to renew the SSR once more in 2024. (See MISO Poised to Extend Missouri Coal Plant’s Life.)

However, MISO spokesperson Brandon Morris said MISO’s tariff cannot override a federal court order; “therefore, Rush Island must cease operation on this date.”

“MISO will follow its tariff in determining if the existing SSR contract can be extended or if a new SSR contract can be issued for the period between Sept. 1, 2024, when the existing SSR contract expires, and this Oct. 15, 2024, date,” Morris said.

MISO declined to comment on whether it sees a need to request an extension of the SSR and didn’t elaborate on whether it expects enough new generation and system upgrades in place by the third quarter of 2024 to take the two coal units’ place.

The Missouri Public Service Commission has set a Dec. 15 deadline for those wishing to intervene in the case.

Posted on

Lamont Withdraws Connecticut’s 2035 EV Mandate

In a setback for Connecticut’s electric vehicle goals, Gov. Ned Lamont (D) has withdrawn regulations that would have required all new vehicles sold in the state to be non-emitting by 2035, in line with California’s emissions standards. 

The regulations were facing rejection from the legislature’s Regulation Review Committee, with members of the committee expressing concern about affordability and the development of adequate charging infrastructure. 

In a press conference following the withdrawal of the regulations, Democratic leaders expressed their disappointment with the “speed bump” while vowing to work to find a workable solution that would satisfy concerns about cost and infrastructure while maintaining strong electric vehicle goals. 

“We do not want to be left behind as a state,” said Sen. Christine Cohen (D), co-chair of the joint Transportation Committee. She added that there is “no plan to do away with the ban altogether.” 

Lamont stressed the importance of the regulations and said he will work with members of the legislature to address their concerns. 

“Is Connecticut going to be the first state to renege on a commitment we made on a strongly bipartisan basis just two years ago, and on a unanimous basis back about 20 years ago?” Lamont said. The state first aligned its emissions regulations with California in 2004. 

Lamont added that predictable regulations combined with incentives and economies of scale will continue to bring down the costs associated with EVs. 

“This is how you make it affordable,” Lamont said. “Changing our minds will take us in the wrong direction.” 

Katie Dykes, commissioner of the Department of Energy and Environmental Protection, highlighted the air quality benefits of rapidly reducing vehicle emissions. 

“Connecticut has some of the worst air quality in the country,” Dykes said. “Our kids and our vulnerable communities — especially environmental justice communities living near highways and industrial zones — are disproportionately experiencing asthma and respiratory illness, disrupted lives and high medical bills because of it.” 

Dykes noted that the majority of the air pollution generated in the state comes from vehicles, along with 40% of the state’s carbon pollution. 

“It will be nearly impossible for us to meet the state’s Global Warming Solutions Act targets of reducing greenhouse gas emissions 45% by 2030 without vehicle emissions standards in place,” Dykes said. EVs now make up about 10% of vehicle sales in the state, while charging port availability has increased by 30% over the past year, she said. “A pause in this momentum will make it harder to purchase an EV in Connecticut.” 

The move comes after a concerted lobbying campaign by the state’s oil industry to push legislators on the Review Committee to kill the regulations. At a press conference earlier in November, Chris Herb of the Connecticut Energy Marketers Association called the regulations “too much, too soon.” 

“These regulations will increase the cost of gasoline, diesel, electricity and virtually every product and service across the state,” Herb said. 

Looking forward, legislative leaders said they are hoping to work quickly with lawmakers to come to an agreement on new legislation setting strong vehicle emissions mandates. 

Lamont said the legislature could give itself more oversight and the ability to review and change the regulations in the future if the state proves to be unable to support the transition to EVs under the proposed timeline. 

“I think that may get us over the finish line,” Lamont said. 

Senate President Martin Looney (D) spoke in favor of “a review process every few years” to account for the pace of technology improvement and the development of EV infrastructure. 

“We will be having caucuses and move forward with what we hope will be a consensus bill that can pass both chambers and that the governor will sign,” Looney said. 

Beyond the emissions mandates, Looney said the state needs to take significant steps to address affordability and infrastructure concerns. He said the state will need to allocate more funding for chargers and tax breaks for vehicle purchases. 

“That has to be factored into our revenue structure,” Looney said. He added that the state will need “additional revenue in order to do that, as well as to meet all of the other existing needs. … This becomes part of an overall discussion on overall policy.” 

Posted on

PJM Restructuring Executive Team

PJM is restructuring its executive team, the RTO announced Nov. 28, promoting Stu Bresler to executive vice president of market services and strategy and creating two new positions.

“Over the years, Stu has helped build many of PJM’s markets and has made sure all of PJM’s markets are supporting the mission of reliability at the least cost for consumers,” CEO Manu Asthana said in a statement. “PJM and its stakeholders have come to rely on his expertise, diligence [and] leadership and his willingness to listen to all viewpoints that can help PJM ensure a reliable energy transition.”

Bresler started at PJM as a professional engineer in 1994 and was subsequently responsible for implementing its demand response program. He now oversees the operations of all PJM markets.

“I have seen the power of competitive markets to reinforce grid reliability while controlling costs for consumers and attracting investment in cleaner and more cost-effective generation technologies,” Bresler said in the statement. “It is a real honor and privilege to be able to help PJM ensure the reliable delivery of electricity through the current transition as our region moves toward a lower-emitting generation fleet.”

PJM has also established a new chief security officer position, which Steve McElwee, a 15-year PJM veteran who currently serves as chief information security officer, will fill Jan. 10. Along with his current responsibilities for cybersecurity, McElwee will have oversight of business continuity, facility services, physical security, and identity and access management.

PJM Chief Information Security Officer Steve McElwee | © RTO Insider LLC

“Steve’s cyber experience in his current role, coupled with his experience supporting business continuity and recovery, physical security tactics and NERC [Critical Infrastructure Protection standards] compliance, will add tremendous value to the PJM security program,” Asthana said. “He has put his stamp on the industry for his ability to heighten awareness and educate employees and stakeholders on security risks and practices.”

“The landscape of threats aimed at the electrical grid continues to increase exponentially, and I’m committed, along with PJM, to meeting this challenge with the resources necessary to keep power flowing for the 65 million people we serve,” McElwee said.

McElwee will report to another new position, the RTO said: the executive vice president of operations, planning and security. The hiring process will be handled by Preng & Associates, with the goal of having the position filled by the second quarter of next year. Until then, McElwee will continue to report to Chief Information Officer Thomas O’Brien.

“This important role will continue to focus on reliability, planning for the grid of the future and operational excellence. In addition, it combines physical security, cybersecurity, enterprise information security, IT compliance, business continuity, and security engineering and architecture in a new division,” PJM said.

The changes are the latest in a series to PJM leadership. This month, the RTO named Paul McGlynn to replace Ken Seiler as vice president of planning following Seiler’s retirement April 1, 2024. McGlynn will report to Seiler until then. Seiler will remain with PJM through the end of next year in a consulting role “to transition his duties in a seamless manner,” the RTO said.

Posted on

Salton Sea Could Supply Lithium Needs for Decades, Study Finds

The Salton Sea region of Southern California could produce enough lithium for more than 375 million electric vehicle batteries, potentially releasing the U.S. from its dependence on foreign sources of the key mineral, according to a new report. 

In fact, the region, which has been dubbed Lithium Valley, may have enough lithium to allow the U.S. “to meet or exceed global lithium demand for decades,” according to the Department of Energy, which funded the study. 

The analysis was led by researchers from Lawrence Berkeley National Laboratory. DOE called it the most comprehensive assessment so far of the area’s lithium potential. 

“This report confirms the once-in-a-generation opportunity to build a domestic lithium industry at home while also expanding clean, flexible electricity generation,” Jeff Marootian, DOE’s principal deputy assistant secretary for energy efficiency and renewable energy, said in a statement. 

Imperial County, Calif., is the site of the Salton Sea Known Geothermal Resource Area (KGRA). Geothermal brines that are a byproduct of geothermal electricity generation in the area have been found to be rich sources of lithium. 

Lithium is a key component of EV batteries and is also used in battery energy storage systems, which are playing an increasingly important role in decarbonizing electricity production. But currently, the U.S. must import nearly all the lithium it needs. 

The 11 geothermal power plants now within the KGRA have a combined capacity of about 400 MW. That’s just a fraction of the estimated 2,950 MW in potential geothermal capacity in the area, “leaving extensive room to increase geothermal electricity generation while accessing more of the region’s available lithium resources,” according to DOE. 

The Berkeley Lab researchers projected that the geothermal brines in the area could yield 3,400 kilotons of lithium — enough for 375 million EV batteries, which is more than the number of vehicles now on U.S. roads. 

Those findings assume the entire Salton Sea geothermal reservoir could be accessed for electricity production and that lithium could be fully extracted from the resulting geothermal brines. 

Three companies that are building or operating power plants in the area — Berkshire Hathaway Energy Renewables, EnergySource and Controlled Thermal Resources — are planning to use direct lithium extraction technology to recover lithium from the geothermal brine, the report said. 

The Berkeley Lab analysis also looked at potential impacts of geothermal power plants and lithium extraction on air quality, water resources and seismic activity. 

“The analysis illustrates that if these things are done properly, lithium development is not likely to create significant negative environmental impacts,” the researchers said. According to DOE, direct lithium extraction from brine requires 99% less water per ton of lithium than current mining procedures and emits almost no CO2. 

But the researchers acknowledged that the impacts of lithium extraction on waste production “will require attention moving forward.” 

For example, they said, the role of battery recycling in a potential battery supply hub is a topic that could be further evaluated. 

“Recycling these batteries could complement and perhaps ultimately replace raw material extraction as a source of lithium, making the industry more sustainable in the longer term,” the report said. 

The Berkeley Lab analysis comes after the California Energy Commission convened a panel known as the Lithium Valley Commission, which met during 2021 and 2022 to consider issues related to lithium extraction in the state. Assembly Bill 1657 of 2020 called for formation of the commission. 

The commission made several recommendations in a final report released in December 2022. Those included increased state funding for research and development, support for start-up companies and public-private partnerships to promote development of a circular lithium economy in California. 

Another recommendation was to accelerate investment and upgrades in transmission for geothermal power plants in Imperial Valley to be online starting in 2024.