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December 27, 2024

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NERC Issues Level 2 Alert on IBR Issues

NERC is calling on owners of Bulk Electric System-connected solar generation assets to step up and take action aimed at preventing “systemic performance issues” that can cause disturbances to electric service.

The organization provided a series of recommendations for generator owners (GOs) of BES solar facilities in its latest Level 2 alert, released on Tuesday. NERC tied the alert to “multiple large-scale disturbances … involving widespread loss of inverter-based resources (IBRs).”

The document cited the disturbances that happened near Odessa, Texas, in 2021 and 2022. (See NERC Repeats IBR Warnings After Second Odessa Event.)

During the 2021 event, the Texas interconnection lost 1,340 MW of solar and synchronous generation near the town of Odessa; just over a year later, a similar incident caused the loss of 2,555 MW. In a December report, NERC and the Texas Reliability Entity noted the similarities between the two events — including the fact that many facilities involved in the 2021 disturbance responded abnormally in 2022 as well — and called for “immediate industry action” to ensure that IBRs do not pose a threat to grid reliability.

Echoing the December report, the alert said that “as the penetration of [grid]-connected IBRs continues to rapidly increase, it is paramount that any performance deficiencies with existing (and future) generation resources be addressed in an effective and efficient manner.”

Tuesday’s alert was distributed only to GOs of BES-connected solar resources — meaning those that are subject to NERC’s reliability standards — but the authors said owners of solar resources connected to the grid but not under the ERO’s jurisdiction should still review its recommendations and implement them where appropriate. They said the recommendations may also be applicable to grid-connected battery energy storage systems, though not to wind resources, which also use inverters, because “the observed performance issues are different.”

Utilities Urged to Coordinate with Manufacturers

The measures provided in the alert are not mandatory; instead, NERC “strongly encouraged” GOs to adopt them. However, recipients are required to acknowledge receipt of the alert by March 21 and respond to a series of questions about their BPS-connected solar facilities (if any) by June 30.

NERC’s first recommendation is that GOs coordinate with manufacturers of inverters on their systems on inverter-protection settings. These should be set according to certain principles, including:

  • expanding AC voltage protection settings as widely as possible to minimize the use of inverter instantaneous AC voltage tripping;
  • setting frequency protection to operate on a filtered frequency measurement over a time window identified by the manufacturer; and
  • documenting all inverter AC and DC protections.

Similarly, the second recommendation provides the principles for setting collector system and substation protection settings. These include:

  • basing protection settings on the ratings of the equipment they are meant to protect;
  • coordinating protection settings with inverter- and plant-level controller protection and controls; and
  • generally disabling protection settings in the power plant controller.

Recommendation 3 suggests that GOs “coordinate with inverter manufacturers to document and mitigate known causes of inadvertent protection system operation during normally cleared [grid] faults.” Inverters from manufacturers whose equipment has a history of inadvertent operations of protection systems should undergo appropriate hardware or firmware updates, and these upgrades should be communicated to the transmission planner and planning coordinator beforehand for authorization.

The fourth recommendation sets the principles for coordinating facility control mods, fault ride-through modes and parameters, and protections, such as ensuring maximum ride-through capability and maximizing active current delivery during fault and post-fault periods. NERC also said protection settings should be set to maximize ride-through performance while preventing damage or degradation of equipment.

Recommendation 5 suggests GOs coordinate with inverter manufacturers on corrective actions for ride-through faults, while recommendation 6 suggests that GOs work with inverter and controller manufacturers to “not artificially limit dynamic reactive power capability delivered to the point of interconnection during normal operations and [grid] disturbances.”

Finally, the last item recommends that GOs provide their findings from the alert with their respective transmission owners and planners, planning coordinators, transmission operators, reliability coordinators and balancing authorities.

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LCFS Bill Emerges in New Mexico House as Session Nears Close

A bill that would establish a low-carbon fuel standard in New Mexico was awaiting a House vote on Tuesday, as the state legislature races toward the end of the 2023 session.

House Bill 426, sponsored by Rep. Kristina Ortez (D), cleared two committees and was sent to the House floor for a vote. The bill still needs approval from both the House and Senate before the session ends at noon on March 18.

The bill would direct the Environmental Improvement Board to establish a standard to reduce the carbon intensity of transportation fuels used in the state by at least 20% below 2018 levels by 2030 and by at least 30% by 2040.

The rule would include a system for trading credits. Low-carbon fuels might include ethanol, biomass-based diesel, natural gas, low-carbon hydrogen and electricity.

1st in the Southwest

California was the first state to adopt a low-carbon fuel standard (LCFS), followed by Oregon and Washington. Proponents say HB 426 would make New Mexico the first state in the Southwest with a clean fuel standard. The bill is backed by Gov. Michelle Lujan Grisham’s administration.

But this is at least the third try for the legislature to pass a LCFS bill. Last year’s version of the bill, Senate Bill 14, died on the final day of the 2022 session with a tie vote in the House. The 2021 version of the bill, SB 11, stalled on the House floor.

HB 426 initially seemed to have momentum. The House Energy, Environment and Natural Resources Committee passed the bill by a 7-4 vote on Feb. 23. The House Government, Elections and Indian Affairs Committee voted 5-3 on March 4 to approve it. Republican lawmakers voted against the bill in both hearings.

Ortez said during the second committee hearing that HB 426 would reduce greenhouse gas emissions and attract clean-fuel businesses to the state. Producers of fuels with a carbon intensity lower than the state standard would earn credits that could be sold to producers of fuels that exceed the standard. The standard would become more stringent over time.

Ortez said that while the bill is one tool to reduce emissions, “it’s not the end-all, be-all climate change bill.”

And what the bill doesn’t do, she said, is “turn New Mexico into California.” She said California’s high gas prices are due to excise taxes, which New Mexico doesn’t have. A fact sheet from the state’s Climate Change Bureau says the clean fuel standard would lead to “almost no increase of prices at the pump.”

Price Impacts Debated

Rep. Martin Zamora (R), who voted against HB 426, said the bill would do nothing to reduce pollution because producers of high-polluting fuels could simply buy credits. And because those producers must buy credits, gas prices will go up, he said.

“The customer, the poorest of the poor in our state, will wind up paying a higher cost for fuel,” Zamora said.

Farmers would face higher fuel costs because of the bill, Zamora said, leading in turn to higher prices for food and clothing.

During the Feb. 23 hearing, Climate Change Bureau Chief Claudia Borchert pointed to an April 2022 report from consulting group Bates White, which looked at the impact of California’s LCFS on fuel prices in the state. The study was commissioned by the Low Carbon Fuels Coalition.

The cost of crude oil is the main determinant of fuel prices, the study said. Taxes and cap-and-trade costs are other factors, and when combined with crude oil costs, explain 90% of gasoline pricing. The remaining “unexplained” component of fuel costs was not linked to the low carbon fuels program, the study found.

Under pricing in place at the time of the study, consumers could save money by buying low-carbon fuel alternatives, the report said.

HB 426 directs the Environment Department to convene an advisory committee to collect stakeholder feedback before issuing a draft rule.

The bill says the department should look at clean fuel standards in other states when drafting the rule and work with other jurisdictions on regional reductions in greenhouse gas emissions.

Under the legislation, investor-owned utilities would be required to use revenue they receive from clean fuel credits for transportation electrification, with at least half the proceeds benefiting disproportionately impacted communities.

HB 426 also calls for finding ways to limit costs to consumers from the clean fuel program.

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Nev. Regulators OK Controversial Gas-fired Peaker

State regulators approved NV Energy’s controversial proposal to build a 400-MW gas-fired peaker plant in Southern Nevada, a facility the company says is needed to reliably serve load as weather has become more extreme and resources more variable.

The Public Utilities Commission of Nevada (PUCN) voted 3-0 on Tuesday to approve the project.

The $333 million peaker will be built at the site of the Silverhawk Generating Station, a 520-MW natural gas-fired plant about 30 miles north of Las Vegas. NV Energy plans to spend another $20 million on associated transmission infrastructure.

The new plant is expected to be in operation in 2024.

The peaker plant is one piece of the fourth proposed amendment to NV Energy’s 2021 integrated resource plan. The remainder of the amendment is still awaiting commission approval.

In addition to the peaker, the proposal includes the addition of geothermal resources and battery storage, as well as the postponed retirement of several gas-fired units in the state. NV Energy said its plan is intended to “advance Nevada’s energy independence.” (See NV Energy IRP Looks to Reduce Reliance on Open Market.)

Nevada has faced energy supply issues for three years in a row, the company said in a PUCN filing.

“Nevada’s historic reliance on the energy market to meet peak period demand is no longer viable and has introduced significant risk of energy shortfalls and associated rolling blackouts in recent years,” the filing said.

NV Energy asked PUCN for an expedited decision on the Silverhawk peaking facility, with an approval by March 10 to keep the project on track to start operations in July 2024.

Even though its plan includes fossil-fuel energy, NV Energy said it will exceed the requirements of the state’s renewable portfolio standard and meet Nevada’s 2050 zero-carbon goal. The goal aims for zero-carbon generation to match the amount of electricity sales by 2050.

The company has proposed limiting operation of the peaking units to 700 hours a year.

PUCN staff called the peaker plant “a reasonable plan to pursue to obtain needed energy and generation capacity.” Staff pointed to a long-term reliability assessment that NERC published in December, which said resource adequacy issues are expected for the foreseeable future.

Following the commission’s vote on Tuesday, Advanced Energy United, a national business association, expressed disappointment in the peaker approval, which it called at odds with the state’s clean energy transition.

“We are disappointed that the utility did not fully consider other, cleaner solutions, such as energy demand reduction, distributed energy and storage that could meet the same need or even improve reliability and resilience at lower cost,” Advanced Energy United director Sarah Steinberg said in a statement.

Other critics of the proposal, including Western Resource Advocates and Google, had called for further analysis of the plan before a decision was made. Google said NV Energy should have modeled the impact of joining a day-ahead market or an RTO in determining the need for the plant.

Google also asked for more vetting of the potential use of hydrogen at the Silverhawk plant. NV Energy said in its filing that the facility would be able to run on a 15% hydrogen fuel mix, with a potential for 100% hydrogen operation in the future.

But the commission rejected the requests for further analysis.

“Given the evidence presented regarding the unpredictability of the regional energy markets, the volatile weather patterns, and the supply chain disruptions in recent years, the commission finds a delay to conduct additional analysis an unacceptable risk to reliability at this time,” the commission said in an order approving the project.

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DC Circuit Focuses on Filing Deadline in Appeal of SEEM Approval

Oral arguments on the appeal of FERC’s approval by operation of law of the Southeast Energy Exchange Market (SEEM) held Wednesday at the D.C. Circuit Court of Appeals focused on the issue of deadlines.

FERC deadlocked 2-2 in October 2021 over the lawfulness of the market, which makes available unused transmission capacity from its member utilities in the Southeast for additional trades among its members. Under the Federal Power Act, the tie meant that the commission approved the market, even though it did not issue an order on it.

The automatic approval drew rehearing requests, but FERC unanimously ruled that they were filed too late, coming 30 days after commissioners filed statements on their positions — instead of a few days earlier, when the SEEM agreement actually went into effect. (See FERC Rejects SEEM Opponents’ Rehearing Requests.)

The commission also later approved rules for SEEM in a separate order. (See FERC Accepts Key Tariff Revisions to SEEM.)

The case was appealed by environmental groups and renewable energy advocates, with Earthjustice attorney Danielle Fidler arguing that FERC was wrong to deny the rehearing requests because of lateness and had to come up with a justification for its action under the Federal Power Act.

Judge David Tatel asked whether the court would have to rule on the SEEM tariff itself if it rejected the agreement in the first place.

“If the SEEM agreement were invalidated, then that would make it more difficult to have the tariff go into effect,” Fidler said. “But as they are separate orders, those orders have to be addressed.”

Judge Neomi Rao asked whether it would make sense to remand the case to FERC if the court agrees that it miscalculated its rehearing deadlines and have the commission address the merits of the case. FERC issued its first order on the case before Commissioner Willie Phillips, now acting chair, joined. It is now back down to four members after Richard Glick left at the beginning of the year.

Fidler said that because FERC based its approval of the SEEM rules on questionable claims, both orders needed to be remanded to the commission. Among those is that the SEEM market is “bilateral” when it crosses 10 states and matches up available transmission capacity with power sales based on an algorithm, she argued.

“The petitioners argue that that that decision is also arbitrary and capricious, and that information needs to be provided to the commission as it considers both the agreement and the tariff,” Fidler said.

The Federal Power Act was amended in 2018 to add Section 205g after FERC split on approving the results of ISO-NE’s Forward Capacity Auction 8. The new section stipulates that, in the case of a deadlock, the commissioners must explain their positions and that the courts are allowed to review such cases.

Rao admitted that the legislative history indicated Congress wanted the court to review cases such as SEEM, but she said the text of section meant it did not apply.

“The only thing that’s judicially reviewable under ‘g’ is if there is a deadlocked rehearing order; that becomes judicially reviewable,” Rao said. “But we don’t have a deadlocked rehearing order here. Here we have a rehearing order focused on timeliness.”

Petitioners have asked the court to review whether FERC was right on the timing of their rehearing requests, Fidler said. If they win that argument, she argued, then it would fall back to the automatic approval. The court would also be within its rights to provide guidance to FERC on remand, she added.

FERC Senior Attorney Robert M. Kennedy defended the commission’s rehearing order, saying that it correctly interpreted the notice period under 205g as the D.C. Circuit directed it to do in another case.

Rao asked how that decision fits in with in FERC’s own rules on deadlines, which go back decades.

“The commission has consistently taken the position that while that rule can be applied to deadlines for filers, it cannot be applied to the commission’s implicit statutory period to act on rate filings because that would impermissibly extend the burden, the waiting period, imposed on utilities by Congress,” Kennedy said.

In some emergency situations, FERC can take more time to rule on rates, but generally it tries to get orders out before the 60-day deadline and will issue orders earlier if the deadline falls on a holiday or weekend.

Section 205g holds that the failure to act constitutes an order. When FERC issued a notice on Oct. 13, 2021, about the case, it indicated that its failure to act happened on Oct. 11; that date set the rehearing deadline, Kennedy said. The petitioners misread the statute, and FERC was clear that its failure to act occurred on Oct. 11, he argued.

Rao asked Kennedy whether it would make sense for the court to just remand the case, requiring the commission to deal with its arguments.

That would be the standard procedure, Kennedy replied.

“What makes this case different, among many other things, is the fact that you have before you majority-voted orders from the commission that deal with many of the same issues that were raised with respect to the agreement,” Kennedy said.

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Healey Admin Takes 1st Steps to Reshape Mass. DPU

Massachusetts Energy and Environmental Affairs Secretary Rebecca Tepper named two new commissioners to the Department of Public Utilities on Wednesday, the first step in what Gov. Maura Healey has promised will be a “transformation” of the department.

The new appointees are Jamie Van Nostrand and Staci Rubin. Cecile Fraser, appointed by previous Secretary Kathleen Theoharides under Gov. Charlie Baker, will stay on as a commissioner as well.

Unlike utility regulatory commissions in other states, appointments to the Massachusetts DPU are not subject to confirmation by the state’s legislature, and they are formally made by the EEA secretary, not the governor.

Fraser has served as the department’s acting chair since January, working alongside current Commissioner Robert Hayden, who will step down on April 8 after having served for eight years. Fraser will continue in that role until Van Nostrand, whom Tepper named chair, joins May 1.

Van Nostrand is a professor at the West Virginia University College of Law and has worked in the energy industry for more than 30 years. He was previously executive director of the Pace Energy and Climate Center in New York and an energy lawyer at two major law firms.

Rubin is vice president of environmental justice at the Conservation Law Foundation and a previous DPU official: She was a senior counsel and hearing officer from 2015 to 2018. She will join the department again as a commissioner April 10.

“We know how critical it is that the DPU leadership understands that the transition to a clean energy economy is a pocketbook issue and will be thoughtful in how we evolve our grid and economy for the future,” Healey said in a statement. “I have full faith in Jamie Van Nostrand, Staci Rubin and Cecile Fraser to uphold those values.”

During her campaign for governor, Healey promised to increase funding for the DPU, as well as to direct it to create new offices for public participation and grid modernization.

In a press release, she said that the new commissioners will work toward making the department a partner in achieving climate goals and better at engaging with communities, in addition to integrating equity into its decision-making and building agency expertise.

Rubin in particular has experience pushing the DPU to be a better ally to the state government in fighting the climate crisis.

“For many years, I’ve advocated for a more inclusive, transparent DPU that considers climate justice, and I’m grateful for the opportunity to bring that vision to life,” she said in a statement. “Together, we will work to ensure that environmental justice populations have seats at the table in shaping our clean energy future.”

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DOT Opens New Round of IIJA Funding for EV Chargers

The U.S. Department of Transportation on Tuesday announced a new round of funding aimed at putting electric vehicle chargers in “urban and rural communities, downtown areas and local neighborhoods, particularly in underserved and disadvantaged communities.”

The Infrastructure Investment and Jobs Act (IIJA) authorized the $2.5 billion for the Charging and Fueling Infrastructure (CFI) Discretionary Grant Program, to be used over five years for competitive grants that will help put chargers in communities, as opposed to the state and interstate highway chargers being funded by the law’s National Electric Vehicle Infrastructure (NEVI) program.

“By helping bring EV charging to communities across the country, [CFI] is modernizing our infrastructure and creating good jobs in the process,” Transportation Secretary Pete Buttigieg said in a DOT press release. “With today’s announcement, we are taking another big step forward in creating an EV future that is convenient, affordable, reliable and accessible to all Americans.”

Transportation accounts for the largest share of U.S. greenhouse gas emissions — 38% — according to figures from the Congressional Budget Office. EV sales are growing, having hit close to 6% of all new car sales in 2022, but lack of publicly available chargers and range anxiety still remain significant barriers to adoption, according to a recent analysis from the World Economic Forum.

The U.S. currently has about 130,000 publicly available EV chargers, according to figures from the White House, but President Biden has committed to increasing that number to 500,000 by 2030.

With $5 billion from the IIJA, NEVI has provided formula-based funding to all 50 states, Puerto Rico and D.C. to help build out a national network of EV chargers.

The NEVI guidelines call for federally funded chargers to be installed every 50 miles along major highways, no more than one mile off an exit. The Federal Highway Administration approved the initial state plans for the funding, as required under the IIJA, in September. The agency also recently finalized the technical standards that all federally funded chargers will have to meet, including any installed under the CFI program.

CFI is meant to build on NEVI, which is focused on “enabling long-distance trips along the national highway system,” according to Monday’s funding announcement.

Beyond reducing greenhouse gas emissions and accelerating the adoption of EVs, CFI’s specific goals include supplementing — but not supplanting — private sector investment, promoting “broad public access to a national charging and alternative fuel infrastructure network,” and implementing environmental justice objectives.

The CFI funds are divided into two programs, each receiving $1.25 billion, according to the DOT. The Community Program will “strategically deploy publicly accessible EV charging infrastructure, and hydrogen, propane or natural gas fueling infrastructure in communities,” The focus here will be on installing chargers in public locations such as public or privately owned parking facilities, public buildings, public schools and public parks.

Awards for this program will range from $500,000 to $15 million and may be used to contract with a private, third-party entity. Projects will be “expected to reduce greenhouse gas emissions and to expand or fill gaps in access to publicly accessible infrastructure.”

The Corridor Program will put chargers along “designated alternative fuel corridors.” Minimum awards here will be $1 million, with no maximum amount, and the funds must be used to contract with a private third party.

The first round of funding, covering 2022 and 2023, will provide $700 million for CFI, divided equally between the Community and Corridor programs. Applications are due May 30, and organizations can submit applications for and receive funds from both programs.

NEVI vs. CFI

The FHWA, which will oversee both CFI programs, will prioritize projects “that address environmental justice, particularly for communities such as rural and low- and moderate-income neighborhoods that may disproportionately experience the consequences of climate change and other pollutants,” the press release said.

Both programs will also require projects to be accessible to and usable by individuals with disabilities, according to the funding announcement.

“FHWA is committed to helping towns and cities, large and small, build modern, sustainable infrastructure that promotes equity and opportunity for their local economies and net-zero emissions for the nation by 2050,” Administrator Shailen Bhatt said. “By encouraging the adoption and expansion of EV charging and alternative fuels, CFI Program investments have the potential to significantly address the transportation sector’s outsized contributions to climate change.”

Launched in February 2022, NEVI was “initially focused on enabling long distance trips along the National Highway System,” according to the CFI funding announcement. But the state plans submitted to FHWA for the first round of funding also pointed to challenges in implementing the program.

For example, many states reported that charging stations could not be installed every 50 miles in certain remote regions without adequate electric distribution systems. Other regions, where distribution systems were already constrained, would need significant upgrades to handle the 150-kW DC fast chargers required under federal standards.

CFI is intended to build on NEVI, with several specific goals, including supplementing but not supplanting private sector investment, improving broad public access to “a national charging and alternative fuel infrastructure network,” and advancing environmental justice goals.

Technical standards for both programs include requirements for each charging station to include at least four DC fast-charging ports or Level 2 (L2) charging ports. DC fast chargers are required for charging stations on AFCs and must have industry-standard connectors (plugs) that allow them to charge any EV.

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PJM MIC Briefs: March 8, 2023

Merged IMM-PJM Issue Charge on Multi-schedule Modeling Endorsed

VALLEY FORGE, Pa. — The PJM Market Implementation Committee on Wednesday endorsed a problem statement and issue charge to explore multi-schedule modeling of combined cycle generators in the market clearing engine (MCE).

According to the problem statement, combined cycle generators have a larger number of configurations that can be modeled in the MCE, which raises performance impact challenges. The engine is currently designed to look at each schedule that a generator offers into the energy market as a separate logical resource. While most resources offer only one or two, it’s possible for the number to be much higher for combined cycle units, potentially leading to an exponential increase in solution times.

The statement says that a typical 2×1 combined cycle unit would have at least six configurations, meaning that if it offers two schedules into the market, it would be represented by 12 logical resources. (See “Feedback on Issue Charge, Problem Statement for Combined Cycle Modeling,” PJM MIC Briefs: Dec. 7, 2022.)

Both PJM and the Independent Market Monitor had offered proposals that left stakeholders divided over the best way to frame the discussion and whether to go forward at all. After stakeholders deferred voting on the proposal during the January MIC meeting, the Monitor suggested amendments to PJM’s issue charge, and the two were able to merge their proposals. (See “Stakeholders Disagree on Approach to Combined Cycle Modeling,” PJM MIC Briefs: Jan. 11, 2023.)

The issue charge was revised to add education on the current schedule selection process as a key work area and expanding the out-of-scope section to include topics under the Cost Development Subcommittee’s purview, unit-specific parameter review, cost-based start-up and no-load load cost rules, and the requirement that parameters be mitigated during emergencies and hot/cold weather alerts.

Deputy Monitor Catherine Tyler said the changes will allow for the discussion to cover the issues identified in PJM’s white paper without affecting existing market power provisions.

Paul Sotkiewicz, of E-Cubed Policy Associates, said the calculation constraints should have been identified and brought before stakeholders far sooner, as it leaves little time for stakeholder deliberation before General Electric — which provides the MCE software — completes its collection of design preferences and begins building its Next Generation Markets Systems (nGEM), including any multi-schedule modeling components.

The committee will begin holding special sessions on the issue later this month.

Proposals on Rules for Generation with Co-located Load Presented

Stakeholders discussed proposals to create rules for generation with co-located load, addressing whether they are subject to ancillary service charges, FERC– or state-jurisdictional, and able to retain their capacity interconnection rights (CIRs).

A proposal from the Monitor and a joint Constellation Energy-Brookfield Renewable Partners package had been considered by the MIC last year, but they were dropped after a poll found little support for either in November. The central question in the previous discussions was whether generators with co-located load not directly connected to the PJM grid should be able to retain the CIRs for the portion of their output supplied to load. (See “Limited Support for Co-located Load Proposals,” PJM MIC Briefs: Dec. 7, 2022.)

Constellation made the case that when highly interruptible loads are paired with generators, allowing those generators to maintain their capacity ratings would create a dispatchable capacity with rapid ramping capabilities. It also would have defined the load as not being FERC-jurisdictional and not subject to ancillary service charges. The Monitor’s proposal would have codified the existing practice of requiring generators in such a configuration to relinquish a share of their CIRs based on the output serving the co-located load. Both those proposals continue to stand in the proposal matrix.

The Advanced Energy Management Alliance (AEMA) presented a proposal that would treat all co-located load as receiving service from the grid, arguing that the energy produced by the generator is FERC-jurisdictional and must be supplied to a wholesale customer. The load would be treated as receiving wholesale energy by firm point-to-point transmission and served to the grid at the LMP level. The generator would retain its full capacity rights and be levied the PTP costs. Presenting the package, Bruce Campbell, of Campbell Energy Advisors, said it carries the bonus outcome of designating load meters as wholesale rather than retail, which he believes PJM lacks the authority to require.

PJM presented its own package during last month’s MIC meeting that would allow generators to retain their CIRs but make them subject to ancillary service charges, such as black start, regulation and reserves, effectively on load’s behalf. (See “First Read of PJM Proposal on Co-located Load,” PJM MIC Briefs: Feb. 8, 2023.)

Discussion on Local Considerations for Net CONE

Stakeholders continued laying the groundwork for proposals to address how local factors such as regulations and legislation could impact the net cost of new entry (CONE), with much of the discourse centering on whether new CONE areas could be created to reflect such considerations. (See “Local Considerations for Net CONE,” PJM MIC Briefs: Feb. 8, 2023.)

The options matrix was revised to include feedback from the meeting to include the calculation of gross CONE, the creation of new CONE areas for regions with restrictions that may impact asset lifespan and the relationship between gross CONE for price-separated locational deliverability areas (LDAs).

Sotkiewicz defended the addition of a design component item for new gross CONE areas, stating that he believes PJM has previously held that the number and sizing of CONE areas cannot change. He pointed to Illinois and New Jersey as regions with legislation that could impact generators’ lifespan or operations to the extent that it may be necessary to break them out as their own CONE areas.

“PJM has indicated that it is not open to change in the Quadrennial Review filing,” he said.

PJM Senior Counsel Chen Lu said the issue was raised in the Quadrennial Review at the “11th hour” and the RTO told FERC that it felt it was better to address the topic through the stakeholder process. Sotkiewicz responded that he felt that was inaccurately characterizing the filings in the review and that PJM made it clear in its responses that it was not appropriate to even look at localized net CONE (ER22-2984).

“We just didn’t think it was appropriate to consider this in the Quadrennial Review at the 11th hour … so we never foreclosed raising this issue with the broader stakeholder group,” Lu said.

Other MIC Actions

Stakeholders endorsed new default gross CONE and avoidable-cost rate figures updated through the Quadrennial Review. The new parameters will be used for the 2026/27 delivery year. All resource types, expect storage, will see their gross CONE figures increase largely because of changes in tax credits and new reference resources used for combined cycle and onshore wind resources. (See “Stakeholders Consider Recognition of Local Impacts to Net CONE,” PJM MIC Briefs: Feb. 8, 2023.)

The committee also partially endorsed revisions to Manual 11, with a portion of the changes removed for further discussion.

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Maryland to Adopt California’s Advanced Clean Cars II Rule

Maryland is set to fast-track adoption of California’s Advanced Clean Cars II (ACC II) rule, requiring that 100% of all new passenger cars, SUVs and pickup trucks sold in the state be zero-emission vehicles by 2035.

The Maryland Department of the Environment proposed the regulation to the Monday morning meeting of the state’s Air Quality Advisory Board, which quickly voted out a recommendation for the department to move ahead with enacting the standard, according to a press release from the Governor’s Office.

Announcing the proposed adoption later in the day in Baltimore, Gov. Wes Moore (D) said the new rule would be part of a “major transformation that is going to define this administration — and that’s how we turn Maryland from a state powered by oil and gas to a state powered by clean energy.”

With the passage of the Climate Solutions Now Act (SB 528) last year, Maryland now has nation-leading goals for greenhouse gas emission reductions: 60% below 2006 levels by 2031 and net-zero by 2045. ACC II “will be one of the state’s most important emission reduction measures,” the press release said.

As originally adopted in California last August, ACC II requires car manufacturers in a state to provide an increasing percentage of zero-emission vehicles (ZEVs) for sale each year. It defines zero-emission as including battery-electric, hydrogen fuel cell electric and plug-in hybrid vehicles.

MD EV Sales (CARB) Content.jpg

Under the Advanced Clean Car II regulations, EVs will have to represent a growing percentage of vehicle sales in Maryland, beginning in 2026, and reach 100% by 2035.

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CARB

The regulation starts with a 35% ZEV sales requirement for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

ACC II also includes increasingly stringent low-emission vehicle standards aimed at reducing tailpipe emissions of gasoline-powered cars and heavier passenger trucks sold in a state.

According to an analysis from the Maryland Department of the Environment, the rule would reduce the number of gas-powered cars sold in the state by 383,000 by 2030 and by 1.68 million by 2035. In addition, between 2026 and 2040, the rule would cut nitrogen oxide emissions by 6,000 tons and carbon dioxide emissions by 82 million metric tons.

The analysis also estimated that such emission reductions could cut respiratory and cardiovascular illness in the state, along with lost workdays, providing in-state health benefits of close to $40 million per year by 2040. Figures from Baltimore Gas and Electric also show that EVs are cheaper to operate than gas-powered cars, potentially saving consumers hundreds of dollars per year.

Environment Secretary Serena McIlwain called the proposed regulation “a big step toward cleaner air and a more aggressive response to the threats posed by climate change.”

‘A Proven Policy’

The announcement also drew statements of support from both industry and environmental groups.

“As a business at the forefront of mobility solutions, we know that technology and market demand are both ready to support the transition to clean vehicles,” said Ryan Dalton, head of external affairs and policy for Siemens. “Strong state standards that reflect the escalating consumer demand and set clear expectations for market growth over the coming years are key to managing the transition.”

ACC II “is the best way to attract investment and provide predictability for manufacturers, companies, workforces and consumers alike,” Dalton said.

Kim Coble, executive director of the Maryland League of Conservation Voters, praised Moore and McIlwain for “acting so immediately to advance zero-emission vehicles and reduce harmful emissions. … The Advanced Clean Cars II rule is a proven policy for reducing greenhouse gases from transportation.”

California has been able to enact its strict clean car standards under a waiver, allowed by the Clean Air Act, which allows the state to enforce emission reduction standards that exceed the federal levels set by the EPA. Once such standards are adopted in California, other states may also adopt them.

California first enacted regulations aimed at cutting emissions from cars in the state in the 1990s, and the third iteration of the rules, passed in 2012 have since been adopted by 17 states. As of January, New York, Oregon, Vermont and Washington have adopted ACC II, and Massachusetts, Delaware and Colorado are considering it.

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PJM Stakeholders Debate Capacity Auction Delays

VALLEY FORGE, Pa. — PJM stakeholders appeared split last week over proposals to delay the RTO’s capacity auctions to incorporate market rule changes being considered by the Board of Managers.

On Feb. 24, PJM issued a letter invoking the critical issue fast path (CIFP) process to consider market rule changes to address concerns that plant retirements are occurring faster than PJM can connect new resources. The board also directed PJM staff to consider delaying upcoming auctions so that any changes could be implemented before the Base Residual Auction for 2027/28. (See PJM Board Initiates Fast-track Process to Address Reliability.)

PJM staff outlined two options at the March 8 Market Implementation Committee meeting. The more aggressive schedule would push the 2025/26 BRA, currently scheduled for this June, to May 2024. The following three auctions would each be pushed back six months, returning to the normal schedule with the 2029/30 BRA to be held in May 2026.

The less impactful change would leave the 2025/26 BRA timeline untouched and push the 2026/27 and 2027/28 auctions back six months to May 2024 and November 2024, respectively.

Peter Langbein 2023-03-08 (RTO Insider LLC) FI.jpg PJM’s Peter Langbein | © RTO Insider LLC

Either alternative could require the cancellation of the first or second incremental auctions (IAs), though PJM’s Peter Langbein said the third IA would still be held for each delivery year.

Many of the steps PJM goes through prior to an auction are chained together and dependent upon the completion of the stage before them, limiting how close together PJM can hold BRAs.

In 2021, FERC agreed to delay the BRAs for delivery years 2023/24 through 2026/27 in response to an order revising the market seller offer cap (MSOC). Without any additional delays, the schedule would return to the three-year lead time with the 2027/28 auction in May 2024. (See FERC Accepts PJM BRA Delays.)

Those in support of delaying the June BRA argued that auctions shouldn’t be held when problems have been identified and market changes are being considered. They said revised auction rules could result in more accurate prices and address the reliability concerns outlined in a whitepaper the RTO issued last month along with the board’s letter.

Erik Heinle, of Vistra, said PJM should adopt the more aggressive delay. He noted that market participants have been talking about postponing the 2025/26 auction since December, when PJM delayed posting the results of the 2024/25 BRA because of problems in the DPL South locational deliverability area. (See Capacity Auction ‘Mismatch’ Roils PJM Stakeholders.)

Alternative auction schedules (PJM) Content.jpgPJM displays potential alternative auction schedules during a stakeholder discussion on delaying future Base Residual Auctions during the March 8 Market Implementation Committee meeting. | PJM

“We have expressed concerns about the 2025/26 auction in June for a couple months now,” he said.

Jeff Whitehead, of the GT Power Group, said the current market rules allow PJM and the Independent Market Monitor to usurp sellers’ assessments of their risk with their own beliefs, which he said could lead to unjust and unreasonable results considering the risk presented by the Dec. 23 winter storm.

“It would be pretty irresponsible for PJM and market participants to move forward with any auctions until we can address some of those issues,” he said.

Market Monitor Joe Bowring said there is no substance to Whitehead’s assertions and that the market sellers’ preferred offer cap was in place for Winter Storm Elliott.

“Participants have no reason to assert that their own views of risk were not included in their offers,” he said in an email to RTO Insider. “Some participants are attempting to create a narrative in which Elliott did not represent a failure of the Capacity Performance market design and that it did not represent a failure on the part of many generators to respond and that somehow the only solutions are to weaken market power mitigation and arbitrarily increase capacity market prices. Those are not the answer.”

Supporters of a more limited schedule change said it would be disruptive to delay the 2025/26 auction because many pre-auction activities — including planning parameters, must-offer exception requests and unit specific market seller offer caps — are in process or already complete. They also argued that if PJM does not receive a quick approval from FERC, the rule changes may not be ready to implement for the 2025/26 BRA, undermining the rationale for delaying the auction.

Bowring said any auction schedule should avoid disrupting the 2025/26 auction, given that it has already begun.

“The process is already well underway and has been for some time … I think it would be a mistake to postpone that,” he said.

PJM’s Adam Keech said it’s likely that the Board of Managers will make a decision on whether and how to delay the auction schedule “relatively soon.”

Responding to stakeholder requests that the board members attend future Markets and Reliability Committee meetings to provide clarity on what they want to see in revised auction rules, Keech said that it was determined that since initiating the CIFP process was an action of the full board, it would not be proper to have a subset of the body come before stakeholders. Instead, he suggested that members write letters to the board with any questions or comments that they have on the process.

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DOE, EPA Team Up on Reliability Efforts

Responding to what they called “a time of significant dynamism,” the Department of Energy and the Environmental Protection Agency on Friday announced a new framework for “routine and robust communication” to manage the grid’s transition to clean energy sources.

In a memorandum of understanding, EPA and DOE identified the increasing frequency of severe weather, coupled with the adoption of renewable generation and energy storage resources, as drivers of “ongoing change” in the bulk power system. They said the changes are only likely to continue thanks to investments in decarbonization from the Bipartisan Infrastructure Law and the Inflation Reduction Act. (See EPA’s Becker Breaks Down $32B of Federal Funding for Decarbonization.)

“A reliable electric power system is essential to our national security, continued economic growth and the protection of public health. That’s why DOE and EPA are uniting our long-standing efforts to ensure a robust and resilient system,” EPA Administrator Michael Regan said in a press release accompanying the MOU. He pledged to “support grid reliability and resiliency at every stage as [EPA] advances efforts to reduce pollution, protect public health, and deliver environmental and economic benefits for all.”   

DOE and EPA identified their roles as helping to wrangle the “robust and multilayered system” — including stakeholders such as FERC, NERC, regional entities, state public utility commissions, utilities and public interest organizations — that maintain the reliability of the North American grid. The agencies said they intend to conduct “regular and effective communication and consultation” with stakeholders “within … statutory authorities and mandates.”

According to the MOU, both EPA and DOE have created internal bodies focused on electric reliability, with key staff designated as points of contact for routine interagency communication. The agencies are planning to meet at least twice a year to discuss their respective work on reliability, in addition to holding joint meetings as needed with NERC and other stakeholders to solicit input.

The agencies said their outreach efforts would revolve around five key areas:

  • Analysis, including “sharing information about modeling and analysis of electric power investments, operations,” and other topics, along with discussing additional data needed to evaluate risks;
  • Engagement with entities to identify current and emerging reliability risks, tools that may be useful in protecting reliability, and actions that might help maintain reliability;
  • Monitoring the BPS to identify any potential risks;
  • Short-term interventions within the agencies’ statutory mandates to address immediate reliability risks; and
  • Sharing information on implementation of policies and programs to protect reliability; investments in upgrades to generation, storage and distribution infrastructure; and policies that support reliability planning and infrastructure development.

NERC said in a statement that it “commends” the MOU and its goals of facilitating communication. The organization noted that its own reliability assessments have consistently shown increasing impacts from extreme weather and the changing generation mix, with most of the continent assessed at either high or elevated risk of energy shortfalls in the most recent Long-Term Reliability Assessment. (See NERC Warns of Ongoing Extreme Weather Risks.)

“We believe that the energy transition that is occurring can work reliably, but the pace of change needs to be managed, and we have stressed the critical need to evaluate the impacts of these polices on reliability,” NERC said. “NERC is encouraged by the MOU and looks forward to engaging with DOE, EPA and others in this important effort.”