Search
January 23, 2025

Posted on

NY Defers Action on Controversial Cap-and-invest

Development of a greenhouse gas emissions cap-and-invest system first proposed two years ago is getting pushed further down the road in New York.

Gov. Kathy Hochul (D) made no mention of the controversial concept in her State of the State address Jan. 14, and there is only limited mention of it in her printed version.

The program has been in development for well over a year but has bogged down amid concerns that the billions of dollars to be extracted from greenhouse gas-emitting industries could translate to higher prices, job losses or other negative impacts for New Yorkers.

Much of the governor’s address, in fact, was devoted to proposals that would reduce costs or increase financial benefits for low- and middle-income New Yorkers.

Energy and climate were the very last topics in both her speech and the accompanying playbook.

In that playbook, it sounds like New York is doing at least a partial reset on cap-and-invest planning: In the coming months, it says, the lead agencies will “take steps forward on developing the cap-and-invest program, proposing new reporting regulations to gather information on emissions sources, while creating more space and time for public transparency and a robust investment planning process.”

Hochul writes: “New York needs to get the transition right and keep our state affordable for families.”

Ostensibly, the staff at various agencies have been doing just that since mid-2023. But finding common ground apparently has been difficult. (See Opposing Sides Want to Speed, Slow NY Cap-and-invest.)

The State of the State is the governor’s public opening hand in the lengthy, intertwined process by which the coming year’s budget and many key policy issues will be decided.

This year, Hochul has no fewer than 201 proposals in her plan, but like the thousands of proposals submitted by legislators, many may be modified or killed during negotiations before the April 1 start of the next fiscal year, and some may not even reach the starting line.

Hochul has several other proposals in the energy and environmental sectors.

Climate Investment

Hochul seeks more than $1 billion for creating jobs, reducing pollution and slashing household energy bills in what she called the largest single climate investment in state history.

This will pay for retrofits of housing; incentives for heat pump installation; making public infrastructure serve as “hubs of sustainability,” such as by building thermal energy networks on state-run college campuses; expanding green transportation options; and supporting businesses of all sizes in decarbonization efforts.

Nuclear

It has been apparent for a while that New York officials increasingly are interested in advanced nuclear power, even as they framed the polarizing concept in carefully neutral tones.

Hochul calls for creation of a “Master Plan for Responsible Advanced Nuclear Development,” and the state on Jan. 14 issued a “Blueprint for Consideration of Advanced Nuclear Energy Technologies.”

Hochul said in a news release that New York will lead a multistate initiative on advanced nuclear energy expected to launch in February.

Also, she said the state will support Constellation Energy Corp. in its pursuit of federal grant funding to support exploration of adding one or more advanced reactors at its Nine Mile Point facility in northern New York.

Public Power

Hochul said she will direct state agencies to enter into contracts with the New York Power Authority in pursuit of a 100% renewable energy goal for state agencies by 2030. This will include at least 500 MW of generation.

This is separate from — but not unrelated to — another NYPA initiative.

NYPA has a tentative framework for 3.5 GW of renewable energy projects, the first tranche of proposals under its recently expanded authority as a developer of renewable energy alone or in partnership with the private sector.

NYPA itself acknowledges that even if all those proposals go forward, many can be expected to be lost to the normal industry attrition process.

Public power advocates call for NYPA to aim much higher — 15 GW instead of 3.5 GW — as President Biden is replaced by President Trump and leadership of the energy transition falls to states. They hoped to hear more in the State of the State.

Reactions

Hochul’s non-action Jan. 14 on cap-and-invest apparently caught some supporters of the system by surprise.

Two separate reports were issued Jan. 13 by Switchbox and Resources for the Future, each involving separate sets of climate advocates and each explaining in great detail the benefits that such a system would provide to communities and households through reduced emissions and financial assistance.

After the State of the State address, the Environmental Defense Fund’s Kate Courtin said in a news release:

“At a time when states with climate commitments should be stepping up to lead, New York is stepping back. By continuing to kick cap-and-invest down the road, Gov. Hochul is delaying the benefits that New Yorkers want — cleaner air, lower energy bills and more resilient communities. Meanwhile, the cost burdens from climate change-fueled disasters, like excessive flooding and severe storms, will continue to mount.”

Eric Walker at WE ACT for Environmental Justice had similar thoughts, and also criticized Hochul’s proposed $1 billion climate investment, which would be funded through tax dollars. He said via email:

“Today’s announcement is really a minimalist first step toward broader climate action. Instead of taking bold action, Gov. Hochul announced a plan that fails to meet the scale of the challenges we face. Worse, a billion-dollar state appropriation shifts the financial burden to struggling New Yorkers instead of holding the corporations responsible for pollution accountable. A robust cap-and-invest program is the long-term solution New Yorkers need to tackle pollution, improve air quality and deliver a just transition for our communities.”

Public power advocates also panned Hochul’s proposal, and they staged a protest outside the State of the State.

“The choice is clear, Gov. Hochul, New York can build 15 GW of public renewables or the state, like so much of the world, will continue to burn,” said Teddy Ogborn, an organizer with Planet Over Profit who was arrested during the demonstration. “With a climate denier as president, it’s more important than ever for New York to lead the way. New York can still meet its legally mandated climate targets, but Gov. Hochul must take action today.”

NYPA President Justin Driscoll, by contrast, was supportive. In a prepared statement, he said: “Gov. Hochul’s historic investment in climate mitigation is crucial for New York as we prepare for the ever more frequent 100-year storms and climate challenges. NYPA is proud to support this investment, work with organized labor and our partners in government to bring public power to public spaces and serve as a trusted advisor delivering innovative solutions to power New York into the future.”

Posted on

ISO-NE Introduces Proposed Resource Retirement Changes

ISO-NE plans to decouple resource retirements from the capacity auction process and adopt a two-year notification timeline for retiring generators, the RTO told stakeholders at the NEPOOL Markets Committee meeting Jan. 14.  

The proposal is one component of ISO-NE’s wide-ranging capacity auction reform project, which aims to transition the region to a “prompt” capacity market held just months before each capacity commitment period (CCP), instead of the current time frame of over three years. (See ISO-NE in 2025: Capacity Reforms, Tx Solicitation and FERC Orders.) 

While retiring resources currently are required to submit de-list bids through the forward capacity auction process over the four years prior to the relevant CCP, “the move to a prompt capacity auction necessitates a new mechanism to collect resource retirements,” said Kevin Coopey of ISO-NE. 

Coopey added that the new process “will be the mechanism to reduce or eliminate interconnection service” for both capacity interconnection rights and energy-only interconnection rights. ISO-NE plans to use the term “deactivation” for resources that are permanently exiting both the capacity and energy markets, and “capacity market deactivation” for resources strictly exiting the capacity market. 

Coopey said there are “natural tensions” between adopting a shorter versus a longer retirement notification timeline.  

“A shorter timeline allows participants to improve the efficiency of deactivation decisions by having better market information,” he said, while “a longer timeline allows the market, including entrants and the ISO, to better respond to deactivations.” 

ISO-NE also emphasized the importance of simplicity in the new retirement design to prevent confusion and allow participants “to access market information in a timely manner that enhances efficient decision-making.” 

Zeky Murra Anton of ISO-NE noted the RTO “evaluated timelines ranging from four years to six months” before landing on the two-year timeline. Relative to the current timeline, a two-year notification period would give generators more up-to-date information to enable more efficient retirement decisions while still providing time for the RTO and other participants to respond to issues created by retirements, he said.  

ISO-NE plans to review deactivation notifications for reliability and market power issues before publishing the information prior to each capacity auction.  

Murra Anton acknowledged that the shorter retirement notification timeline could present challenges if transmission issues are identified.  

“Experience with transmission construction shows the time from needs identification to completion is frequently longer than two years,” he said. 

If solutions are not feasible within the two-year time frame, ISO-NE’s tariff authorizes reliability must-run agreements to retain resources for local transmission reliability issues. 

ISO-NE will continue to work with stakeholders on the proposal at the MC in February. It plans to file with FERC the resource retirement and prompt auction reforms by the end of 2025, followed by a second filing in 2026 focused on resource accreditation and dividing CCPs into seasonal periods. The changes are intended to take effect for the 2028-29 CCP. 

Posted on

Calif. Lagging on Hydrogen Fueling Station Target, CARB Finds

Rather than expanding its network of light-duty hydrogen-fueling stations, California lost three stations last year, casting doubt on the state’s ability to meet a 200-station goal, a new report found. 

As of July 15, 2024, there were 62 light-duty hydrogen-fueling stations in California, down from 65 stations in 2023, according to the December 2024 report from the California Air Resources Board. Although four new stations opened during the year, seven stations owned by Shell closed, for a net loss of three stations. 

The number of hydrogen-fueling stations in CARB’s 2022 report was 60. 

CARB now projects 129 retail hydrogen-fueling stations in the state by 2030 — well short of the target of 200 stations by 2025 set by Gov. Jerry Brown in a 2018 executive order. 

The latest projections also have fallen behind those from CARB’s 2023 evaluation, in which 92 open stations were expected by the end of 2024, based on developer feedback. 

Link to FCEV Sales

CARB’s annual report on hydrogen-fueling station development tallies stations where drivers of light-duty fuel cell electric vehicles (FCEVs) can pull up, fuel and pay, like at a conventional gas station. Among the 62 retail stations counted in the 2024 report, seven were considered temporarily non-operational, but expected to reopen. 

The slow progress in station development also means projected sales of FCEVs have dropped. The report noted the close tie between automakers’ FCEV sales estimates and the rate of fueling station development, fuel supply cost and reliability, and range of FCEV models. 

“In multiple studies and surveys, consumers have repeatedly ranked charging and fueling infrastructure as a top concern for either purchasing a new ZEV or even using the ZEV they currently drive,” the report said. 

That sentiment could be key as California will require all new cars sold in the state to be zero-emission or plug-in hybrids by 2035. 

Through September 2024, 17,999 FCEVs had been sold in California, including 427 in the first nine months of last year, according to a California Energy Commission ZEV dashboard. 

In comparison, 293,747 battery-electric cars and 49,039 plug-in hybrids were sold in the state from January through September 2024. 

Shell Pull-out

Shell announced in February 2024 that it was permanently closing its seven light-duty hydrogen-fueling stations in California “due to hydrogen supply complications and other external market factors,” according to a notice from the company posted by the Hydrogen Fuel Cell Partnership. 

The announcement came after Shell asked the California Energy Commission to cancel grant funding the company had been awarded for 50 new hydrogen-fueling stations and one station upgrade. 

Reasons for canceling the grant included political and economic uncertainty, permitting hurdles, high construction costs and problems sourcing green hydrogen, according to a letter from a Shell official cited by CleanTechnica. 

Although slow progress on station development has been noted in CARB’s previous reports, reasons for the lag have shifted, the agency said. 

“Barriers identified in past analyses, including securing site access, permitting timelines, utility connection timelines and other site-specific issues, may still linger but are not the dominant issues today,” the report said. 

Instead, station developers have cited economic factors — including high inflation rates, low credit values from the Low-Carbon Fuel Standard program and the small size of the hydrogen refueling industry — along with trouble finding skilled, affordable contractors. 

Factors that could cause the pace to pick up are time limits on spending station-development grants, an expected resolution of hydrogen-supply bottlenecks in Southern California and efforts to address supply-chain issues, CARB said. 

CARB also suggested progress could be made in partnership with California’s hydrogen hub known as ARCHES, or Alliance for Renewable Clean Hydrogen Energy Systems. 

“The state should continue to support the production of clean hydrogen and lay the groundwork for ARCHES to scale up the market and drive down prices,” the report said.

Posted on

PJM PC/TEAC Briefs: Jan. 7, 2025

Planning Committee

Stakeholders Discuss Revised IRM and FPR Values for 3rd Incremental Auction

VALLEY FORGE, Pa. — PJM’s Andrew Gledhill presented a proposal to the Planning Committee to revise the installed reserve margin (IRM) and forecast pool requirement (FPR) for the third 2025/26 Incremental Auction (IA) to account for higher load growth identified in the preliminary 2025 load forecast. 

While the proposal initially was brought as a voting item, PJM told stakeholders it plans to conduct more analysis before publishing the forecast and will bring the proposal back for consideration after that point. No changes are anticipated to the IA planning parameters, which are scheduled to be published Jan. 26.

The rising load growth is expected to cause reliability risk to become more concentrated in the winter, increasing from 86.9 to 96.2% of expected unserved energy (EUE), causing effective load-carrying capability (ELCC) ratings for most resources to shift. Onshore and offshore wind, which tend to perform better in the winter, would see their ratings go up 7 and 11%, respectively, while all other resources would remain the same or see hits to their ratings. Storage particularly would see ratings fall by 10 to 15%, depending on resource duration, and demand response also would decline by 8%. All other resources would see declines of between zero and 3%. 

The IRM would increase from 17.8 to 18.5% under the proposal, and the FPR would fall from 0.9387 to 0.9263, both following a trend. Revisions approved in March 2024 increased the IRM by 0.1% to 17.8% and saw the FPR decrease to 0.9387 from 1.1165. (See “Revised Reserve Requirement Study Values Endorsed,” PJM MRC/MC Briefs: March 20, 2024.) 

Several stakeholders said the revisions would be a significant change in the planning parameters used to conduct the 2025/26 Base Residual Auction and IA, undermining investors’ ability to use auctions as a data points guiding decision-making and creating a possibility that units with diminished ratings could be forced to cover shortfalls in the obligations they received in the BRA. 

“How are investors supposed to make any decisions when you have such huge changes between the Base Residual Auction and Incremental Auctions?” asked Paul Sotkiewicz, president of E-Cubed Policy Associates, comparing the ELCC analysis to a “random number generator” into which stakeholders have no insight. 

Preliminary 2025 Load Forecast

PJM’s Molly Mooney presented preliminary figures for the 2025 load forecast, which estimates that load growth will escalate to about 2% annually in the summer and 2.4% in the winter.  

Last year’s forecast projected 1.6% of summer load growth and 1.8% in the winter.  

The complete 2025 forecast is set to be published in mid-January. (See “Preliminary Large Load Adjustment Requests for 2025 Load Forecast,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

The expected growth is sharpest in the first few years of the forecast through 2033, when it slows for the remainder of the 20-year lookahead. Compared to the 2024 forecast, the difference is starkest in the winter, with about 22.4 GW of new load expected in the first five years on top of that already projected last year; an additional 11.1 GW in additional load is forecast for the following nine years. 

Focusing on the 2030/31 delivery year, over 90% of the winter load growth above what already was forecast last year is expected to be from large load additions (LLAs), such as data centers and chip manufacturing facilities in several zones. Those additions increase the 2024 forecast by 11.8%, while electric vehicle load decreases by 0.8%. 

LLAs have been the focus of stakeholder attention over the past year, with a proposal endorsed in May to revise how capacity obligations to serve LLAs are assigned to load-serving entities. Some also seek more information on how PJM reviews LLA forecasts produced by utilities, arguing that forecasting practices could vary and one project could be brought to multiple utilities, raising concerns of double counting. (See “New Approach to Large Load Addition Capacity Assignments Endorsed,” PJM MRC Briefs: May 22, 2024.) 

Calpine’s David “Scarp” Scarpignato noted that the 2025 forecast is the first to use a 20-year window, which he said could undersell the scale of the load growth in the initial years of that period when just looking at the annualized growth rate. 

Monitor Proposes Interconnection Queue for Large Loads

The Independent Market Monitor proposed a new interconnection process for large loads that could pose significant impacts to PJM reliability, akin to how generators are studied before being brought online in terms of network upgrades, as well as how the new load would affect resource adequacy. 

If PJM determined that an LLA would jeopardize reliability, Monitor Joe Bowring said the RTO should have the authority to form a queue and impose delays to in-service dates until any necessary generation or transmission is brought online. He said planning by PJM needs to address not only transmission, but also generation and operations to ensure the system can reliably meet the loads. 

There are tensions, Bowring continued, between existing PJM consumers, traditional load growth and the LLAs that are driving ballooning forecasts and requiring market redesigns. Reconciling those must be done in a rational way that avoids inappropriately shifting any costs associated with serving new load onto existing customers. The status quo does not offer PJM a voice in how large loads come online, he said, arguing that private bilateral deals do not offer a satisfactory solution because they lack the transparency of a full planning process. 

“Of course all load should be served; the question is how to do it reliably” and at least cost, he said. 

Stakeholders were mute in opining on the merits of the proposal, though some transmission owners commented that they are limited in the conditions they can place on load interconnections. Some asked how a large load required to go through the study process would be distinguished from more traditional additions. 

Bowring told RTO Insider there are several components of the proposal that require more thinking through and consultation with stakeholders, including the definition of large loads. He noted that many data centers being planned in the footprint have requested to come online with a relatively small initial load but would scale up to as high as 1 GW over the course of several years, creating more challenges for classifying large loads. He said he plans to bring the discussion up again at the Members Committee webinar scheduled for Jan. 21. There also are jurisdictional questions that would have to be answered before the process could be implemented. 

“It clearly needs to happen, and those with the jurisdictional authority need to talk to one another,” he said. “I think it’s clearly something that needs to be considered carefully and acted on before reliability is affected.” 

Other Committee Business

PJM has launched a new Grid Optimization Solutions webpage, where it has published four technical reference guides and educational materials on the implementation of grid-enhancing technologies. It includes information on PJM’s deployment of advanced conductors, dynamic line ratings and topology optimization, as well as its analysis of advanced power flow controllers. 

Stakeholders also endorsed revisions to the TO/TOP Matrix that reflect NERC’s EOP-11-4 standards on emergency operations, as well as changes to indexing between the manuals and PJM’s Reliability Audit Program. PJM’s Gizella Mali said no new responsibilities are included for TOs. The committee also endorsed review of the matrix charter with no changes made to the document. 

Transmission Expansion Advisory Committee

Update on Recommended Tx Upgrades in 2024 RTEP Window 1

PJM presented an update on the package of transmission upgrades it plans to recommend to the Board of Managers for inclusion in the 2024 Regional Transmission Expansion Plan (RTEP), which includes about $4.6 billion in projects focused on meeting rising power flows from the west to east. 

Staff plan to bring the proposal to the board in the first quarter. (See “PJM Unveils Recommended Projects for 2024 RTEP Window 1,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

The initial $5.8 billion cost estimate aggregated from all the projects included has been optimized by PJM, reducing the cost by more than $1 billion. Changes include revising Dominion’s Kraken Loop project to consolidate two proposed 765/500-kV substations into one, named Yeat, where the loop would terminate, deferring some of the 230-kV upgrades associated with the loop, and excluding a rebuild of the 230-kV Carson-Clubhouse line in Dominion’s package of transmission reinforcements. 

Much of the need stems from rising data center growth in Northern Virginia, centered around “Data Center Alley,” near Washington Dulles International Airport, as well as electric vehicle and electrification trends.  

Prior to announcing the recommended projects, PJM said it had expanded its assessment to include the preliminary 2025 load forecast with the aim of ensuring that the upgrades could hold up to higher load growth. That raised objections among some TOs who argued that changing the factors PJM used to evaluate projects after they had been submitted was unfair and benefited incumbent utilities with more insight into expected LLAs. (See “PJM Presents Shortlist of Projects for 2024 RTEP Window 1,” PJM PC/TEAC Briefs: Nov. 6, 2024.) 

The proposal includes a new 765-kV line that would run from the John Amos substation in West Virginia, through the Welton Springs facility, and terminate at a new 765/500-kV Rocky Point substation in Virginia. That site also would be looped into 500-kV lines running between the Doubs, Goose Creek, Aspen and Woodside substations. Construction of the corridor from John Amos to Rocky Point would be assigned to FirstEnergy, with Transource doing upgrades in the AEP region. 

The $704 million Kraken Loop proposal would create a new 500-kV line running from North Anna, passing the Ladysmith substation to the east and turning north to a new Kraken substation. It would continue to the new Yeat substation in Fauquier County. Kraken also would be cut into the existing 500-kV Ladysmith-Possum Point line. 

Supplemental Projects

FirstEnergy presented a $15.8 million project to replace a 500/138-kV transformer and other equipment at its Pruntytown substation in the APS zone because of obsolescence and difficulty sourcing replacement parts. The project is in the conceptual phase with a possible in-service date of June 30, 2029. 

PPL presented a conceptual $242 million project to serve a new service request in New Buffalo, Pa., by building a new 500/138-kV substation, to be named for the town, along the 500-kV Juniata-Alburtis line. The 9.6-mile segment of existing line that would run from New Buffalo to Alburtis would be rebuilt as a double circuit as part of the project. The in-service date is May 30, 2028. The customer is expected to come online in 2027 with an initial load of 200 MW, growing to 1 GW in 2031. 

Exelon presented a $22 million project to install 12 new 230-kV breakers at its Mount Zion substation in the PEPCO zone to limit the number of taps on one line, addressing the potential for multiple networked elements to go offline simultaneously. The project also would replace 24 disconnect switches, install relays at each new breaker and end station, and new telecommunications equipment. The project is in the engineering phase with an estimated in-service date of June 1, 2030. 

Duke Energy presented a $63 million project to build a new 345-kV substation, named Turner, to serve a new service request near Mount Orab, Ohio, which is expected to ramp up to 2 GW of load in 2029. The line would be cut into the 345-kV Stuart-Hillcrest line, with additional lines of the same voltage being built to the Pierce and Don Marquis substations and a 1.2-mile loop connecting Turner to the existing 345-kV Pierce-Kyger Creek line. The work would be split between Duke; American Electric Power, which owns the Don Marquis site; and the Ohio Valley Electric Corp., which owns Kyger Creek and would split the Turner facility with Duke. The project is in the scoping phase with a projected in-service date of June 1, 2029.

Dominion presented four projects to construct adjacent substations in Henrico County, Va., to serve nearly 1 GW of data center load expected to come online in 2029. The network would be linked with $51 million of 230-kV lines cut into the existing transmission between the Chickahominy substation and White Oak and Portugee sites. 

The $20 million Gray Bark substation would be cut into the Portugee-Chickahominy line and be configured in a 230-kV six-breaker ring configuration serving an ultimate load of 300 MW. Gray Bark would be linked to the $20 million Saltwood substation with two lines into a six-breaker ring serving 300 MW. Both substations are set to come online in the third quarter of 2027. 

A $20 million Thicket substation would be built along the Chickahominy-White Oak line to serve 255 MW with a six-breaker ring. It would be linked to Saltwood by one line and another to a $15 million Bunker substation configured as a four-breaker ring to serve 104 MW. Both are estimated to come online in the fourth quarter of 2027, and the overall project is in the engineering phase. 

Posted on

Newsom Budget Lays out Cap-and-trade Extension, Climate Spending

California lawmakers may consider extending the state’s landmark cap-and-trade program, following a request from Gov. Gavin Newsom in his 2025/26 budget proposal released Jan. 10.

“Although the current cap-and-trade program does not expire until 2030, considering extension sooner could provide greater certainty and attract stable investment,” according to the Climate Change and Environment chapter of the 2025/26 budget summary.

Cap-and-trade is considered a key piece of the state’s greenhouse gas reduction strategy and will be needed beyond 2030 to reach the state’s goal of carbon neutrality in 2045, Newsom’s budget said.

And discussions of an extension must include how cap-and-trade proceeds will be spent. The proceeds must support programs “that deliver effective pollution reduction results, support clean transportation and communities, and help address energy affordability,” the governor’s budget summary stated.

California launched its cap‑and‑trade program in 2012 and reauthorized it in 2017. The program sets a cap on GHG emissions that decreases over time. Carbon allowances are sold through government auctions, and purchasers can use the allowances to cover their own emissions or trade them to others.

In the first 10 years of cap-and-trade in California, proceeds provided $28 billion in funding to more than half a million GHG reduction projects through the California Climate Investments program.

In 2014, the California program was linked to that of Quebec.

Last year, Washington Gov. Jay Inslee signed Senate Bill 6058, which allows the state’s cap-and-invest program to link with the California-and-Quebec carbon market. (See Bill to Link Wash. Cap-and-trade with Calif.-Quebec Passes Both Houses.)

Climate Bond Spending

Newsom’s 2025/26 budget also proposes spending $2.7 billion from Proposition 4, a $10 billion climate bond measure that California voters approved in November.

The proposal includes $325 million for wildfire mitigation and forest resilience in 2025/26, at a time when wildfires are ravaging the Los Angeles area.

The budget allocates another $228 million in climate bond proceeds to prepare ports for offshore wind. And $50 million is earmarked for load reduction and backup generation to enhance electric grid reliability during extreme weather events.

In a separate proposal, Newsom wants to spend $2.3 million from special funds for the California Air Resources Board to develop regulations authorizing the use of E15 — a gasoline blend that contains 15% ethanol rather than the 10% ethanol in commonly used E10 blends. Newsom’s budget said the strategy could potentially increase existing gasoline supplies and lower gas prices.

The governor’s $322.2 billion budget, which Newsom described as balanced, now heads to the state legislature for review. However, the impact on the budget of the Los Angeles wildfires is not yet known. On Jan. 13, Newsom proposed providing at least $2.5 billion in additional funding for emergency response and to “jumpstart” recovery efforts.

Cap-and-trade Amendments

In addition to a potential legislative extension of California’s cap-and-trade program, the state Air Resources Board is working on amendments to the regulation.

CARB held a series of informal stakeholder workshops on potential regulatory updates in 2023 and 2024. The agency expects to release a regulatory package for public comment early this year.

One goal of an update is to increase the program’s stringency, “supporting a long-term carbon price signal aligned with the state’s 2045 climate targets,” CARB said in a workshop presentation.

According to an Oct. 15 market notice, the amendments are expected to include the removal of at least 180 million allowances from 2026-2030 to align with GHG reduction goals. A one-time cost increase for cost-containment provisions is also expected, to better align with the federal assessment of the social cost of carbon.

Among other possible revisions, regulatory updates will also reflect CAISO’s Extended Day-Ahead Market (EDAM).

Posted on

PJM MIC Briefs: Jan. 8, 2025

1st Read on 2nd Phase of CIFP Manual Revisions

VALLEY FORGE, Pa. — PJM presented stakeholders with proposed manual revisions to implement a requirement that dual-fuel generators must offer schedules with both of their fuels into the energy market during the winter, as well as changes to the operational and seasonal testing for capacity resources.

The proposal is the second package of manual updates to conform with tariff revisions approved by FERC in January 2024 as part of PJM’s Critical Issue Fast Path (CIFP) capacity market rework (ER24-99). (See “Stakeholders Endorse Manual Revisions to Implement CIFP Changes to Capacity Market,” PJM MIC Briefs: May 1, 2024.)

The dual-fuel requirement would be added to Manual 11 and specify that combustion turbines and combined cycle committed as dual-fuel capacity resources offer their alternative fuel into the energy market during the winter or follow outage reporting requirements.

The summer/winter capability testing requirements in Manual 18 would be redefined to focus on whether a resource participating in the capacity market or a fixed resource requirement plan is able to output its daily installed capacity (ICAP) minus the 95th percentile hourly seasonal net output. A resource that has a daily ICAP value exceeding the tested capability during that season would be subject to shortfall charges until it is able to test to a greater capability.

Changes to Manuals 14, 18, and 28 would allow PJM to subject capacity resources to up to two operational tests in the summer and winter. Intermittent resources, including the variable component of a hybrid resource, would be exempt from both testing requirements.

The penalty rate for failing either of the tests also would be changed to be determined by multiplying the daily deficiency rate, ICAP shortfall and accredited unforced capacity (AUCAP) factor; the status quo uses the equivalent demand forced outage rate (EFORd) instead of the AUCAP factor.

The committee will vote on the changes at its meeting in February, with a vote by the Markets and Reliability Committee in April.

PJM Presents Changes to Black Start Compensation

PJM’s Glen Boyle presented a proposal to revise how generators providing black start service are compensated to remove the net cost of new entry (CONE) as an input.

The RTO would instead use a fixed rate derived from the average RTO-wide net CONE values over the past five years, coming out to $272.62/MW-day. That would be multiplied by the unit capacity and varying multipliers depending on resource classification to arrive at the black start service cost, which is one component of the base formula rate that determines compensation. The fixed rate would be reevaluated every five years as part of the holistic review of the service. Boyle said PJM is trying to break the tie between black start revenues and net CONE.

The proposal is set to be voted on by the MIC on Feb. 5, followed by the MRC on March 19.

The net CONE component has come under scrutiny after PJM presented planning parameters for the 2026/27 Base Residual Auction, scheduled for July, which saw net CONE values fall to zero in some zones. One of several pending filings PJM submitted to FERC in December would revert a change in the reference resource that net CONE is based on from a CC generator back to a CT unit. (See PJM MIC Briefs: Dec. 4, 2024.)

While using the status quo formula for the 2025/26 delivery year would result in decreasing black start revenues across all zones — an overall 22.73% decrease and exceeding 50% in one area — the proposal would result in compensation remaining nearly equal to the previous year’s.

Calpine’s David “Scarp” Scarpignato said he does not see a link between net CONE and black start service and added that he appreciates the straightforward nature of PJM’s approach.

Independent Market Monitor Joe Bowring said the proposal appears to be an arbitrary change that would perpetuate the use of what he called an irrelevant metric — net CONE — in compensating black start units. He proposed that black start resources be compensated for the cost of providing black start plus an incentive rather than net CONE. He questioned why net CONE should be subject to escalator given that it depends on net revenues, which vary from year to year.

Bowring also said the original rationale for the PJM proposal is no longer true as it based its proposal on the basis that net CONE would be zero in multiple locational deliverability areas (LDAs) because it was planning to use a CC as the reference unit.

“While the gross CONE of a CC is higher than that of a CT, the net CONE of a CT is higher than the net CONE of a CC. There are no LDAs with negative net CONE,” Bowring said.

Discussions Continue on Demand Response Availability Window

Stakeholders continued to weigh in on PJM’s proposal to eliminate the demand response availability window and instead model the resource class as being available in all hours, following arguments from curtailment service providers that there is unrecognized potential for consumers to reduce their load any time of day. (See “PJM Proposes Changes to Demand Response Availability Window,” PJM MIC Briefs: Oct. 9, 2024.)

The prospect of a wider availability window became especially significant for DR in the wake of PJM’s redesigned risk modeling paradigm, which FERC approved in January 2024. That shifted the focus to winter, when reliability risks are more dispersed across the day, from a few peak hours in the summer.

PJM’s Pat Bruno said the proposal would build a specific load profile for DR in light of analysis that found that program participants have a different average load profile from general load.

When determining the winter peak load (WPL) for the resource class, Bruno said adding up the peak load for each participant would overstate capability because consumers’ load could peak in different hours. Instead, the proposal would measure the WPL across five winter coincident peak (WCP) days at the 8 to 9 p.m. hour, as that is when overall class capability most coincides with system peak load. Because both profiles may change over time, this would be reevaluated regularly.

Aggregate average hourly DR load profiles also would be created across the five WCP days for use in the effective load-carrying capability (ELCC) analysis driving risk modeling and resource accreditation. The average would be at its lowest between 1 and 4 a.m., when DR would be modeled at 63% of its maximum reduction capability.

ELCC ratings for DR could increase by about 20%, with values also increasing for resources that perform better in the summer. Ratings for storage could increase between 8 and 10%, depending on the duration of the resource, and thermal and storage could see more modest boosts. Onshore and offshore wind values would fall by 2% and 4%, respectively. System reliability risk as a whole would shift toward the summer by about 4%.

Because individual consumer load profiles can vary, Bruno said there is less correlated outage risk, and the impact of changing the amount of DR that participates in the auction has less of a marginal impact than for other resources.

Bowring said that PJM’s asserted increase in the ELCC value for DR ignored the fact that DR had underperformed during the December 2022 winter storm.

Posted on

FHWA Awards $635M for EV Chargers, Hydrogen Fueling Stations

The city of Troy, Ala., soon could have 10 new electric vehicle charging stations located at five sites — the local hospital, museum, university, downtown center and sports complex — all funded with $724,192 in federal funds from the Infrastructure Investment and Jobs Act. 

The city of 17,836 is one of 49 recipients of a total of $635 million in IIJA money announced Jan. 10 by the U.S. Department of Transportation’s Federal Highway Administration. The aim is to put 11,500 chargers in underserved areas ― rural and urban ― and along major highways in 27 states and the District of Columbia, according to the DOT press release.  

The grants represent the second round of funding from the IIJA’s $2.5 billion Charging and Fueling Infrastructure (CFI) program, which is a competitive program. The second funding opportunity drew high interest, with the FHWA reporting it received 416 applications requesting a total of $4.05 billion, more than six times the amount available.  

The first round of CFI funding went out in two installments: $622.57 million to 47 projects in January 2024 and $521.19 million to 51 projects in August 2024. 

In addition to EV chargers, the grants also will support hydrogen fueling stations for heavy-duty vehicles. For example, a $24.8 million award to the Port Authority of Houston will be used to install and operate a publicly accessible hydrogen fueling station in Bayport, an industrial area in the port.  

The California Energy Commission won the largest award, $55.9 million, for EV fast chargers and a hydrogen fueling station for medium- and heavy-duty trucks traveling on major routes in and between California and Nevada.  

Some of the federal money will be used for “micromobility” charging for electric bikes and scooters, such as in San Bernardino, Calif., and Hollywood, Fla.  

Hailing the new grants in the press release, Transportation Secretary Pete Buttigieg said, they will help “support the EV transition and make sure it’s made in America. These investments will help states and communities build out a network of EV chargers in the coming years so that one day, finding a charge on a road trip will be as easy as filling up at a gas station.” 

“Americans deserve real choices in how they get around,” said Gabe Klein, executive director of the Joint Office of Energy and Transportation. “[These] investments supplement a combination of federal tax incentives, state and local funding and private investment to fill gaps in the nation’s rapidly growing alternative fueling network and ensure all communities — whether rural, urban, or suburban — have access to convenient, reliable and affordable zero-emission transportation options.” 

If fully funded, individual grants could put hundreds of fast and Level 2 chargers at public locations across the country, including: 

    • $15 million for D.C. to install 454 charging ports at 220 locations, including retail destinations, multifamily properties, car-sharing spaces, curbside spaces and public parking lots. 
    • $8 million to the Louisville-Jefferson County Metro Government in Kentucky to install an estimated 184 charging ports at 39 city-owned locations and one university campus. Also, an urban charging hub powered in part by a solar canopy would be created at a retired coal plant. 
    • $15 million grant for Minnesota’s Metropolitan Council to deploy 1,875 charging ports across the region, especially prioritizing rental housing, rural areas, low- and moderate-income neighborhoods and environmental justice communities.  

Depending on their speed of charging, direct current fast chargers can top up an EV battery in a half hour or less, while Level 2 chargers, often used for home charging, can take several hours.  

The Trump Effect

But whether Minnesota, Troy or any of the other Round 2 grant recipients will see the money or chargers remains uncertain. The awardees must negotiate final contracts with a DOT that likely will have different priorities under the second administration of President-elect Donald Trump, who has pledged to claw back all unspent dollars from the IIJA and Inflation Reduction Act. 

Trump and the Republican-controlled Congress are likely to target EV-related tax credits and other incentives in the IRA, which they have labeled as outgoing President Joe Biden’s “EV mandate.” 

Trump’s designated nominee to head the DOT is Sean Duffy, who served in the House of Representatives for Wisconsin from 2011 to 2019. Prior to running for office, he was on reality television and now is a Fox television commentator, with no apparent background in transportation. 

The Senate Committee on Commerce, Science and Transportation is scheduled to hold an advance confirmation hearing on Duffy’s nomination Jan. 15. 

A cutoff of federal incentives for EVs and EV charging might slow the transition to electric transportation but, as with other sectors of the U.S. clean energy transition, is unlikely to stop it. 

According to DOT, the U.S. now has more than 206,000 public chargers, including the 38,000 that came online in 2024, putting the country on track to reach Biden’s original goal of having 500,000 public chargers in operation by 2030, if not before. 

Year-end figures from Cox Automotive reported total U.S. EV sales of 1.3 million in 2024, a 7.3% increase from 2023, with a record 15.2% year-over-year increase in sales in the fourth quarter. 

The industry analyst anticipates that sales will continue to grow in 2025, as any rollback of incentives or other regulations will take time to implement. With 68 individual EV models now on the road, and 15 more coming, Cox predicts one in four U.S. car sales this year will “likely be electrified in some way ― a hybrid, plug-in hybrid or pure EV.”  

NEVI Update

The weakest link in Biden’s efforts to deploy more EV chargers has been the National Electric Vehicle Infrastructure (NEVI) program, which is distributing $5 billion in IIJA funds via state-level allocations set by formula. The five-year program requires states to submit annual plans for charger deployment before receiving their formula grants. 

Launched in February of 2022, NEVI was intended to build out a national network of DC fast chargers every 50 miles along state and interstate highways but has been slowed by a range of administrative, regulatory and technological roadblocks. 

For example, in some rural areas, the 150-kW fast chargers required for NEVI cannot be installed every 50 miles due to a lack of adequate distribution lines, and interconnection times for new stations can take as long as two years.  

As of the most recent NEVI update from the Joint Office of Energy and Transportation, at the end of November, 126 NEVI-funded public charging ports were in operation at 31 stations in nine states, and nine more states had awarded their first round of contracts for the installation of new NEVI stations. 

To help streamline and accelerate permitting of new chargers, the Pacific Northwest National Laboratory and Idaho National Laboratory released a report Jan. 6, with several recommendations, including: 

    • developing automated tools that can integrate the capacity of existing lines to accommodate new stations with analyses of new installation requests and EV adoption forecasts, while also improving transparency on the interconnection queue. 
    • improving interconnection processes and timing by creating fast-track options based on pre-screening, while also providing flexibility with phased-in approvals. 
    • sizing distribution system components to accurately reflect the demand requirements of new chargers and proactively investing in expanding grid infrastructure. 
    • improving grid reliability and resilience by using demand management and power control systems at EV charging stations and developing and implementing standards for communication between EV chargers and grid infrastructure. 
Posted on

PJM Stakeholders Mixed on Uplift Proposal

VALLEY FORGE, Pa. — PJM and its Independent Market Monitor presented a joint proposal to rework the balancing operating reserve (BOR) credit structure to address a scenario they say can result in generators receiving uplift payments despite not following dispatch orders. 

PJM Senior Director of Market Settlements Lisa Morelli said the current metrics determining BOR credits consider only the most recent five-minute interval, looking at what a unit was dispatched to do and how it responded.  The proposal would create a new Tracking Ramp Limited Desired (TRLD) metric used to determine uplift and deviation charges based on how a resource conformed to its dispatch signal over time. 

Morelli gave an example of a unit operating at 100 MW being dispatched down to 95 MW in accordance with its ramp rate. If that unit ignored the signal and stayed at 100 MW, it would not exceed the 10% margin that defines when a unit is deviating from dispatch. Additionally, since dispatch is limited by ramp rates in the next interval, PJM could only bring it down to 95 MW again. 

As the intervals pass by, a widening discrepancy can form between where the unit is and where it would be had it followed instructions from the start, but the difference between the unit output and dispatch signal would remain 5 MW. 

Joel Luna, a market analyst with the Monitor, said that between 2018 and 2023, PJM paid $17.9 million in uplift to units that did not operate as requested. 

Stakeholder Takes

Several stakeholders requested additional time to review the proposal before the MIC votes on endorsement, which is currently slated for its Feb. 5 meeting. 

Erik Heinle, of Vistra, questioned why PJM could not use a unit’s security constrained economic dispatch (SCED) instructions to determine uplift and deviation charges. 

“You’ve got SCED telling you one thing, and you’ve got this backcast after-the-fact telling you something else,” he said. 

PJM’s Brian Weathers said SCED is optimal for determining uplift only if a unit is responding to the signal, but because it is parameter-limited, it becomes useless if a unit is not following instructions. He said the proposal is not meant to reduce BOR credits, but rather to “right size uplift” to be paid to those who follow dispatch instructions. 

A PJM example demonstrates how an illustrative unit could continue to receive uplift payments while not following dispatch instructions. | PJM

Luna said the proposal would not change the dispatch signal, which must continue respecting resource parameters to avoid creating power imbalances. 

“We’re not saying the signal is wrong, and that will remain the same. PJM will have to operate the system as given,” he said. 

Tom Hyzinski, of the GT Power Group, said if a generator is late to follow a signal to change its output, it could continue to rack up deviation charges while attempting to catch up. If locational marginal prices increase while a unit is ramping down, following the price signal to reverse direction and increase output could move it further from its TRLD, increasing deviation charges. 

Weathers said LMP profits would outweigh the deviation charges when prices might be above the tracking limit, meaning generators would maximize their profits by following SCED rather than chasing the tracking metric. 

Brock Ondayko, of AEP Energy, questioned how a unit can know if it is following TRLD in real time, adding that there needs to be incremental transparency into how this works.  

Since the best financial outcome for the generation owner is to follow SCED rather than trying to maximize uplift that may not be available, PJM doesn’t see the value in having the tracking limit available in real time. 

Rory Sweeney, of the Northern Virginia Electric Cooperative, asked if a systemwide analysis has been conducted to evaluate how the change would affect generators. Luna and Morelli said that had not been done, with Luna adding the impact would be positive because it would lead to more accurate market signals. Sweeney said the same belief was held when the status quo rules were implemented in 2022. 

The proposal also would add lost opportunity costs (LOCs) to the revenues that offset BOR credits, which Weathers said would avoid possible double payments between the two. 

Eligibility for BOR credits would be expanded to begin when PJM commits a unit, even if it was not online at that time, and continue through the end of the resources’ day-ahead commitment or minimum run time. Weathers said this could increase uplift when PJM actions cause a resource to miss its commitments, such as dispatchers holding a unit online longer and causing its minimum downtime to overlap with the start of its day-ahead commitment. 

Given the scale of the changes, Morelli said PJM would include simulated settlement results showing how the changes would impact market participants in late 2025, with actual implementation around a year later. 

“You’ll have a good long time period to look at the tracking limit time period and become comfortable with it before we start using it,” she said. 

Posted on

PJM OC Briefs: Jan. 9, 2025

Stakeholders Endorse Quick Fix Solution to Establish Wildfire Procedures

VALLEY FORGE, Pa. — The PJM Operating Committee endorsed revisions to Manual 13: Emergency Operations to add protocols for the RTO and transmission owners to monitor and coordinate actions when wildfires may disrupt infrastructure.

PJM’s Kevin Hatch said the fires in California highlight the need to be prepared and added that the PJM region has seen an increasing number of fires as well.

The language would direct the RTO to run studies to identify transmission assets that may need to be taken offline due to active fires in real-time and in advance, coordinate with TOs regarding canceling scheduled outages and bringing offline lines back to service and consider whether conservative operations may need to be initiated.

Transmission owners would be asked to monitor wildfire red flag warnings and notify PJM of high risk conditions, evaluate outages to determine whether any need to be recalled or rescheduled, identify facilities that may need to be derated due to wildfire impacts, and notify PJM of any circuits that may need to be de-energized due to active fires or to prevent sparking one.

System Performing Well During Cold Weather Advisory

The generation performance and communication between operators and unit owners was strong during the second day of a cold weather alert that was issued for the western region of PJM between Jan. 8 and 10, Hatch told the committee. Units were started early to ensure they would be able to operate as requested and maintenance was rescheduled to ensure availability.

As the cold weather moved in, outages increased by 2 GW, which Hatch said was a strong improvement over the 7 GW increase seen during the January 2024 Winter Storm Gerri.

“That correlates with very good generation performance, so I think that’s something we really need to note. There’s been a lot of work with generators preparing … and that seems to be paying off,” he said.

He noted that more cold weather was on the horizon the following week and generation owners had been asked to move any maintenance scheduled for that period to the preceding weekend. A cold weather alert has been issued between Jan. 14 and 16 for the western region.

December Operating Metrics

PJM’s Marcus Smith said the RTO saw a 1.52% peak hour forecast error rate for December 2024 and an hourly forecast error rate of 1.63%. Five days exceeded the 3% benchmark staff target, with overforecasting on Dec. 12, 23, 25 and 30 and an underforecast on Dec. 31. Loads came in lower on days when temperatures came in warmer than expected or when holidays led to smaller than expected peaks. The forecast models had a large spread of load ranges on Dec. 30 and 31, which he said was due to the aftermath of an unseasonably warm weekend and the holidays.

December saw four shared reserve events, one spin event, one high system voltage action and 16 post contingency local load relief warnings (PCLLRWs). One shortage case was approved Dec. 6 at 5:40 p.m. due to high loads and interchange. The spin event was declared on Dec. 11 at 6:21 p.m. and lasted six minutes. The 1,872 MW of generation assigned had a 73% response rate, while the 643 MW demand response committed had a 112% response.

Winter Voltage Reduction Testing Scheduled for February

PJM plans to conduct an RTO-wide voltage reduction test Feb. 5, with Feb. 12 set as an alternate if there are cold weather alerts, storms expected or other concerns on the earlier date. Regular tests of the capability were one of the recommendations made following the December 2022 Winter Storm Elliott, during which Hatch said dispatchers were one unit trip away from potentially beginning the first voltage reduction action since the 2014 Polar Vortex.

The first test was conducted in two parts Aug. 14 for the mid-Atlantic region and the following day for the west and south. The manuals assume an average peak load reduction of 1.6% across the mid-Atlantic, amounting to 635 MW. However, a reduction of 0.7% or 280 MW was observed during the test.

In the west and south, a 2.2% reduction is expected, or 920 MW, and the test resulted in a 0.85% reduction or 360 MW. Hatch noted the test was not conducted on a peak day, but it revealed TO equipment may need modification to handle an emergency voltage reduction action. Transmission owners also reported to PJM that the test was beneficial for staff education and in identifying improvements that can be made.

Posted on

Fire Agencies Investigating SCE’s Role in LA Fire, Utility Says

Fire agencies are investigating whether Southern California Edison’s equipment ignited one of the fires currently ravaging Los Angeles, the utility said in a news release Jan. 12. 

SCE stated that it filed electric safety incident reports with the California Public Utilities Commission related to the Eaton and Hurst fires. Utilities are required to file reports for incidents that meet certain criteria, such as media attention or governmental investigation, according to the news release. 

The utility filed one such report Jan. 10 after learning that fire agencies are investigating whether SCE equipment ignited the Hurst Fire in Sylmar, a neighborhood in Los Angeles. 

The Hurst Fire started late on the evening of Jan. 7, hours after the Palisades and Eaton fires had erupted. The blaze covered almost 800 acres and was 95% contained as of Jan. 13, according to the California Department of Forestry and Fire Protection (Cal Fire). 

SCE said the fire was reported at approximately 10:10 p.m. and that a 220-kV circuit experienced a relay at 10:11 p.m. A downed power line was discovered at a tower associated with the circuit, and “SCE does not know whether the damage observed occurred before or after the start of the fire,” the utility added. 

Jeff Monford, a spokesperson for SCE, told RTO Insider that the utility is “cooperating with a fire agency investigation.” 

SCE also filed an incident report related to the Eaton Fire after receiving “significant media attention” and preservation notices from counsel representing insurance companies. 

“It’s important to note that no fire agency has suggested that SCE facilities were involved in the ignition of the [Eaton] fire, and they have not requested the removal and retention of any of our equipment,” Monford said. 

The Eaton Fire began around 6:18 p.m. Jan. 7 and has burned over 14,000 acres. The deadly fire has engulfed parts of the Altadena community, with thousands of structures either damaged or destroyed. The flames have claimed at least 11 lives and continue to threaten nearby communities, according to Cal Fire. 

A preliminary analysis of the four energized transmission lines going through the area showed that there were no interruptions or anomalies in the 12 hours prior to the fire’s reported start time until an hour after the fire started, SCE stated. 

As of Jan. 13, out of SCE’s approximately 5 million customers, almost 40,000 were still without power due to public safety power shutoffs, and more than 400,000 were being considered to have their power turned off. Meanwhile, about 500,000 customers had their power restored in the past few days, Monford said.