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August 11, 2024

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PJM Recounts Emergency Conditions, Actions in Elliott Report

PJM on Monday released a report detailing a litany of emergency actions taken on Dec. 23 and 24 as a severe winter storm sent temperatures plunging across the region and containing new data on generation and market performance.

The RTO’s analysis of the storm, commonly called Elliott, provides 30 recommended changes to forecasting, modeling, accreditation and market rules. It says that PJM was well positioned in the days leading up to the storm, but a series of unforeseen factors — including a sharper than expected drop in temperatures, an unprecedented amount of forced outages and abnormal consumer behavior around the holiday weekend — led to several emergency actions having to be taken to maintain reliability, including two blocks of performance assessment intervals (PAIs) in which generator underperformance led to $1.8 billion in penalties.

A workshop has been scheduled for July 24 to discuss the report.

“As documented in this report, PJM was prepared for the 2022/2023 winter, as well as Winter Storm Elliott, based on the information available, and conducted extensive preparations and communications with members, adjacent systems and the natural gas industry in advance of the storm, in addition to the regular steps PJM takes each year to prepare for winter,” the report said. “Despite numerous refinements to both the capacity market rules and winter preparation requirements that came out of the 2014 polar vortex, Winter Storm Uri in [February] 2021 and other recent examples of increasingly extreme weather patterns, Winter Storm Elliott created a convergence of circumstances that strained the grid.”

Recommendations

Many of the report’s findings have guided PJM’s recommended changes to the capacity market currently being considered under the Critical Issue Fast Path (CIFP) process, including shifting to a seasonal capacity market, an approach to risk modeling that lays more of the reliability focus on the winter and fuel security requirements. The timing of the report’s release has been viewed as critical by many stakeholders participating in CIFP meetings, with voting on proposals scheduled for next month. (See PJM Completes CIFP Presentation; Stakeholders Present Alternatives.)

The recommendations outside the CIFP process include increasing education and training for members around emergency procedures and reporting requirements; evaluating the expected load reduction that a voltage reduction could yield as load composition changes; and exploring ways of increasing synchronized reserve performance through procurement practices, compensation and the amount procured.

The report also includes several recommendations related to the intersection between the electric and natural gas industry, such as aligning when gas generators are scheduled in PJM’s markets and their fuel nomination cycles, as well as improvements to how they report unit-specific parameters to PJM to improve awareness of their availability. Those proposals are under discussion at the Electric-Gas Coordination Senior Task Force.

The report also states that PJM plans next month to open a stakeholder discussion on whether the reserve market design, including prices and performance incentives, aligns with operational needs.

Generator Performance

The forced outage rate for PJM capacity resources throughout the storm was one of the highest PJM has seen in a severe winter weather event, with 24% of resources being offline — exceeding the 22% forced outage rate seen during the polar vortex. Forced outages peaked at 46 GW at 7 a.m. on Dec. 24 and “remained at an unacceptably high level through Dec. 25.”

Many of the outages were not immediately reported, resulting in the RTO’s operators being told the unit would not be able to operate when they attempted to dispatch the generator.

“While generators are required to provide updates on their operating parameters, including operating status, ramp times and fuel availability, in 92% of generator outages, PJM operators had an hour’s notice or less — in most cases, PJM was informed of outages when dispatchers called generators to request them to turn on,” the report stated.

Gas-fired generators made up about 70% of the outages, with gas supply issues being the single largest cause, followed by freezing and problems with plant equipment.

Natural gas well freeze-offs were a major contributor to generators being offline, with production in Ohio halved and down by about 20% in Pennsylvania, with the impact particularly acute for larger gas generators that require a uniform supply of fuel at high pressure. The timing of the storm falling on a holiday weekend also meant that gas trading markets would not be open for a prolonged period, limiting the liquidity of fuel.

“Many gas buyers, especially [local distribution companies] and other customers with more predictable gas usage levels, purchase their gas supplies on Friday for the Saturday, Sunday and Monday gas days. Gas generators in many cases need to buy their gas supply each day of the weekend period based on their awarded or anticipated dispatch. With the majority of gas traded on Friday, the market for gas commodity can become less liquid, resulting in increased supply scarcity and potentially higher intraday gas prices,” the report said.

Several portions of PJM’s and stakeholders’ CIFP proposals are centered around improving gas reliability by revising their accreditation and creating new fuel requirements. On July 10, PJM presented a proposed dual-fuel status for resources that can start and operate on a backup fuel with at least 48 hours of storage. It also discussed creating additional data reporting around whether gas generators have firm fuel or not and potentially reflecting that in their accreditation.

Coal resources made up about 16% of forced outages, largely because of issues with boilers.

Wind resources overperformed during the storm, contributing 13.7% of the bonus megawatts across the two PAIs, despite only making up 1.9% of installed capacity. Nuclear generators also exceeded their commitments, making up 34.5% of the bonus power while representing 17.7% of capacity.

The gas and coal units that did operate performed well throughout the emergency conditions, providing 29.2% and 17.3% of the bonus power.

Synchronized reserve resources also performed poorly throughout the storm. While the first deployment had a response rate of 86.4%, which PJM attributed in part to the short duration of that event, the average was 47.8% across the five deployments, some of which were hours long. PJM noted that deployments are uncommon, especially clustered in a short time frame.

“Five synchronized reserve events over a two-day period is extremely unusual. All five of the events on Dec. 23 and Dec. 24 exceeded 10 minutes in duration, which is again extraordinary. Since the start of 2021, there have been 47 synchronized reserve events, of which only 17 (36%) were more than 10 minutes in duration, and five of these 17 occurred during Winter Storm Elliott,” the report said.

Demand response resources provided significantly less than curtailment service providers (CSPs) anticipated they could provide when called upon. When PJM dispatched 4,336 MW of DR on Dec. 23, providers estimated they could provide the full amount, but PJM’s analysis of customer load data suggests that only 1.1 GW was delivered. When all available DR was dispatched leading up to the Dec. 24 morning peak, CSPs estimated they could deliver 7,400 MW of the 7,522 dispatched, but PJM said that only 2.4 GW was provided.

“The significant difference between the data provided to PJM about load curtailment capability and the actual performance clearly identify an opportunity and need to improve the rules and processes regarding load management capability estimates,” the report said.

PJM Operations

In the days leading up to the storm, the conditions appeared to be within the norms that PJM had experienced in the past: Temperatures weren’t forecast to be abnormal, and historically loads for the days leading up to Christmas had been overforecast. On the day before the storm’s arrival, PJM increased its load forecast for Dec. 23 from 124.6 GW to 127 GW and procured additional capacity and reserves above what was cleared in the day-ahead market. Actual loads came in at 136 GW and were nearly 10 GW above forecast the following day at 131.1 GW.

While providing exports to the Tennessee Valley Authority and other neighbors, some of whom were in emergency conditions, PJM entered its first of four synchronized reserve deployments at 10:14 a.m. in part from numerous generators tripping offline and failing to start, causing the area control error (ACE) to fall. As loads ramped up substantially higher than expected for the Dec. 23 evening peak, many of the generators PJM attempted to dispatch were tripping offline or failing to start, with a rate of 1.8 GW per hour at 2 p.m.

“PJM found that it was unexpectedly and rapidly exhausting its operating and primary reserves because of the unexpected generator outages,” the report said.

By 4 p.m. the ACE had fallen to nearly ‑3 GW, prompting PJM to begin curtailing exports. It also issued a pre-emergency load management reduction action to deploy DR resources and implemented a maximum generation action, directing generators to operate above their economic maximum outputs. This began the first block of PAIs, which would last five and a half hours, or 66 five-minute intervals.

PJM remained in emergency conditions until 11 p.m., but the nighttime load “valley” remained unprecedentedly high, 40 GW over the next highest valley in the past decade, limiting the ability for pumped hydro plants to be refilled. PJM provided some exports to neighbors that were in emergency conditions, and synchronized reserve events were called at 12:05, 2:23 and 4:23 a.m. on Dec. 24.

PJM began curtailing load again at 4 a.m. on Dec. 24 and issued a call for consumers to reduce their electric usage until at least 10 a.m. On top of forced outages, about 6 GW that was scheduled to come online for the morning peak failed to start and PJM re-entered emergency conditions at 4:20 a.m. with DR deployments and a maximum generation action five minutes later. At 4:52 a.m. it issued a voltage-reduction alert.

Approaching the morning peak at 8:30, which capped out at 130 GW of load, PJM was receiving emergency imports from NYISO and TVA, and Duke Carolinas and Duke Energy Progress were shedding load. The report states that forced outages around the morning peak amounted to 41 GW and 200 unit trips. PJM issued a voltage-reduction warning at 7:15 a.m. and remained in emergency conditions until it canceled the maximum generation action and DR deployment at 10 p.m.

At 4:58 a.m., an 850-MW generator tripped offline, causing the ACE to fall below 1,500 MW and prompting the start of a NERC Disturbance Control Standard (DCS) event, which requires that PJM recover ACE to at least ‑630 MW within 15 minutes. PJM called for an additional 500 MW of shared reserves from the Northeast Power Coordinating Council, having received 1 GW shortly before the start of the DCS, and was able to recover the ACE after 15 minutes and 52 seconds.

At the height of the emergency, the report said that if PJM lost emergency imports or another large generator tripped, a voltage-reduction action may have been necessary.

“If another large unit was lost or imports from NYISO into PJM were cut, PJM would have considered initiating a voltage-reduction action, which would have resulted in approximately 1,700 MW of relief. … If necessary, this action would have been followed by a manual load dump warning to communicate load dump allocations to transmission owners,” the report said.

Several complaints to FERC related to non-performance penalties accrued during the storm argue that PJM violated its tariff by continuing to export while implementing emergency procedures. The Elliott report laid out a series of instances in which PJM curtailed non-firm exports as conditions in the RTO worsened, but it stated that cutting all aid to its neighbors wouldn’t have prevented PJM from entering emergency conditions and would have likely worsened emergencies in surrounding regions that were in load shed. (See FERC Sends Elliott Complaints Against PJM to Settlement Judge.)

“Even if the operators had cut all non-firm exports, there would have been a deficit of at least 1,789 MW needed to satisfy PJM load and firm exports. Pre-emergency and emergency actions thus would have been necessary to satisfy capacity needs even if all non-firm exports had been cut,” the report said.

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FERC Accepts Results of ISO-NE FCA 17

FERC accepted the results of ISO-NE’s Forward Capacity Auction (FCA) 17 on Tuesday, ruling that the issues raised by a group of climate activists are outside the scope of the proceeding (ER23-1435).

ISO-NE held FCA 17 in March of this year, procuring resources for the capacity commitment period that extends from June 2026 through May 2027. A group of climate and environmental organizations including No Coal No Gas, 350 Mass, Lexington Climate Action Network and the Berkshire Environmental Action Team, along with 149 individuals, submitted comments protesting the auction, arguing that the design of the auction favors fossil fuels over renewables.

“ISO-NE’s Forward Capacity Market structure, particularly the continued payments to fossil fuel generators, poses extreme risk to ratepayers, the climate and grid reliability,” No Coal No Gas wrote in its initial comments. “FCA 17 awards hundreds of millions of ratepayer dollars to keep the oldest, dirtiest, least economical fossil fuel powered generators online for use as peaker plants. By propping up these failing fossil fuel powered generators as stand-by peaker plants and sending bonus payments to base load generators, ISO-NE is preventing a just transition on our dime.”

Meanwhile, ISO-NE argued that it conducted the auction in accordance with its tariff with no preference toward any type of resource, and that complaints about the structural design of the FCM are outside the scope of the FERC proceeding.

“We’re governed by federal law that requires our markets to be open to all resources that can provide the required services,” an ISO-NE spokesperson told RTO Insider. “These payments are not subsidies, but rather the result of a competitive market in which all resources compete to provide grid services at the lowest cost.”

Answering ISO-NE’s arguments, No Coal No Gas wrote that the public has not been provided with adequate opportunity to engage with and give input on the FCA process. No Coal No Gas disputed the results of the prior two auctions (ER21-1226 and ER22-1417), while FERC ruled both times the issues raised are beyond the scope of the proceedings.

“Community stakeholders have an extremely limited ability to contribute to the Commission’s responsibilities regarding the administration of our electric grid, and the ISO wishes to bar comments appropriately filed through one of our only opportunities to so contribute as outside the scope of the proceedings,” the No Coal No Gas coalition wrote, adding that the one ISO-NE forum dedicated to public engagement, the Consumer Liaison Group, has no direct effect on RTO policy.

FERC again sided with ISO-NE for FCA 17, agreeing with the RTO that the issues raised about payments to fossil fuel resources are outside the proceeding’s scope.

“No party has argued or provided evidence that ISO-NE failed to conduct FCA 17 in accordance with its Tariff,” FERC wrote. “The protests of NCNG, other organizations and Pro Se Commenters raise issues that are outside the scope of this proceeding because they do not bear on the sole question here — namely, whether ISO-NE conducted FCA 17 in accordance with its own Tariff rules. Instead, these protests focus on the FCM market design, as NCNG itself recognizes when it urges ISO-NE and the Commission to redesign the FCM to focus primarily on climate change in its decision-making.”

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No Shortfall Anticipated for Summer of 2027, ISO-NE Says

No energy shortfall is anticipated for the summer of 2027, ISO-NE told the NEPOOL Reliability and Transmission committees on Wednesday, adding that some reserve shortfall appeared in just one of the worst-case scenarios modeled.

The results are part of ISO-NE’s ongoing study with the Electric Power Research Institute looking at how extreme weather affects grid reliability, taking into account how climate change is projected to affect the probability and magnitude of extreme weather. The RTO noted that the expected growth of utility-scale and behind-the-meter solar, offshore wind and storage all contributed to minimizing reliability risks.

While results indicated the New England Clean Energy Connect transmission line would help reduce reserve shortfall in the worst case studied, the RTO found the presence of the Everett Marine Terminal (EMT) did not significantly impact the reserve shortfall.

“Results with and without EMT are similar, as there is minimal depletion of stored fuels in any cases,” said Stephen George of ISO-NE, adding the reserve shortfall seen in the study was manageable. “Cases where reserve shortfalls occur are representative of capacity deficiency conditions, which are managed through ISO’s Operating Procedure No. 4 (OP-4), Actions During a Capacity Deficiency.”

Aaron Patterson of The NorthBridge Group, representing Constellation Energy, the owner of both EMT and the Mystic Generating Station, EMT’s main customer, criticized how the winter iteration of the study modeled the availability of LNG with and without EMT. (See Limited Exposure to Supply Shortfall for ISO-NE During Extreme Weather.)

“The results of the ISO-NE/EPRI study with respect to the impact of EMT retirement are not credible,” Patterson said. “The assumption that the retirement of EMT would have no impact on regional LNG stocks over the course of a winter event is not supported by any data or analysis, and a review of history and the demonstrated capabilities of EMT compared to other facilities suggest that it is not accurate.”

Patterson said the ISO-NE assumption that the loss of Everett wouldn’t significantly affect the amount of LNG available to the region “drives the general conclusion of the study with respect to EMT that retirement of EMT has no material impact on regional electric reliability during extreme winter events.”

While ISO-NE’s modeling assumed the two other LNG facilities servicing the region would be able to make up for the loss of EMT, Constellation argued this assumption is overly optimistic.

Patterson said Everett historically has had an LNG inventory of 6 Bcf during the coldest 21-day periods of the past five years, equating to almost 60% of the available LNG projected by ISO-NE’s 2027 modeling.

“Given this outsize contribution from EMT, the unsupported assumption that the other two facilities would be able to effectively more than double their assumed contribution to LNG stocks without EMT is not credible,” Patterson said.

ISO-NE argued that the LNG assumptions used in the study are reasonable, noting they ran the winter analysis with a range of LNG inventories, including a low LNG scenario that reduced the starting inventory by 3 Bcf (from 6.5 to 3.5 Bcf total).

The study’s results for the winter of 2032 likely will be shared at the Reliability Committee meeting in August, while the summer 2032 results likely will be available in September, ISO-NE said.

Increased Regional Network Service Costs

David Burnham of Eversource told the committees the projected regional network service (RNS) costs for the next five years likely will increase annually by approximately $10 per kW-year. RNS costs are projected to reach $196 per kW-year by 2028, compared to $141.6 expected for 2023.

RNS costs are the costs of transmission service paid by transmission customers in New England. For 2023, asset condition projects made up more than $570 million of the $1.3 billion in total projected regional costs, while regional system plan projects are expected to cost more than $540 million. In 2024, asset condition costs are expected to increase to $890 million, while system plan projects are anticipated to cost more than $300 million, with total costs nearing $1.4 billion.

Eversource Project Costs Rise

Eversource presented to the committees about a series of ongoing projects, including a group of projects in the Greater Boston area, which have ballooned in cost to $921 million, compared to the original 2017 estimate of $572 million.

The utility company cited unanticipated underground interferences, work hour restrictions, soil management and groundwater treatment costs, and material costs as the drivers of the increase.

Eversource also presented on a series of projects in Eastern Connecticut, including upgrades at several substations and rebuilds of multiple 115-kV lines. The company requested a total transmission cost allocation of nearly $200 million, with the final components of the projects to be active by fall of this year.

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Avangrid, Utilities Reach Deal to Cancel Commonwealth Wind PPAs

Avangrid and three electric utilities have reached a deal to terminate the power purchase agreements for Commonwealth Wind, the 1,230-MW offshore wind farm Avangrid says it can no longer build under terms of the PPAs.

The developer would pay Eversource, National Grid and Unitil a combined $48 million under three proposals posted Monday by the Massachusetts Department of Public Utilities. (DPU 22-70/22-71/22-72.)

The issue has been percolating for nearly a year, after Avangrid said the project was no longer tenable under the terms negotiated due to rapidly rising costs and interest rates.

Avangrid sought a pause in DPU’s review of the PPAs, and when the three utilities refused to negotiate, it sought to terminate the PPAs. DPU refused, sending the matter to a state-level court, where it remains an open case, at least for now.

Commonwealth Wind is not the only project whose developers say they cannot go forward under terms negotiated. Developers of Beacon, Empire, Ocean Wind 1, Park City, SouthCoast and Sunrise also have sought concessions that would raise the cost of the electricity they produce.

Attorneys for Eversource, National Grid and Unitil on Thursday asked DPU to rule on the termination requests within 30 days.

The proposals, similarly worded except for the dollar amounts, call for Commonwealth Wind to pay Unitil $480,000, National Grid $21,619,200 and Eversource $25,900,800 after DPU approves the terminations.

Avangrid has said it remains committed to the Commonwealth Wind project and hopes to rebid it in Massachusetts’ next offshore wind solicitation.

The draft structure of that solicitation, announced in May, includes a provision for indexed pricing, allowing developers to hedge against unknown future inflationary effects during the yearslong development process.

New York offered a similar option in its latest offshore wind solicitation. Previous solicitations did not contain such a provision, and now some of the developers holding contracts issued previously — for the Beacon, Empire and Sunrise projects, 4,230 MW in total — want the option as well.

There was a bit of turnabout to Sunrise Wind telling New York regulators last month that it needed more money to go forward with the 924-MW project — Ørsted is a 50-50 partner in Sunrise with Eversource, which for months had been refusing requests by Commonwealth and SouthCoast in Massachusetts for more money.

Eversource is in the final stages of ending its partnership with Ørsted and exiting offshore wind development altogether.

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Judge Dismisses Groundwater Lawsuit Against South Fork Wind

A federal judge has dismissed an attempt by Long Island residents to halt construction of an onshore portion of the South Fork Wind project, out of concern it will spread groundwater contamination.

The judge ruled that the federal agencies they sued are not involved with onshore trenching for South Fork, which is likely to be the first commercial-scale wind farm operational in federal waters.

The 132-MW South Fork is 35 miles off the eastern tip of Long Island. Its export cable will interconnect with the onshore grid in East Hampton.

Construction began in late 2022 and it is expected to start generating power this year.

In March 2022, four residents of East Hampton went to court to block South Fork, saying that while they supported the renewable energy generated by the project — which will not be visible from the upscale East End town — the trenches needed for the export cable will spread existing PFAS chemical contamination in the groundwater.

This poses a risk to public and private wells, including the ones they use, they said.

They targeted the U.S. Department of the Interior, Bureau of Ocean Energy Management, Department of the Army and Army Corps of Engineers, saying these agencies abdicated their legally required duty to provide thoughtful and serious consideration of known environmental concerns before granting approvals and permits for the project.

The plaintiffs are two married couples with property in the same part of town. Both use their houses as their primary residence, and both of their wells are contaminated with per- and polyfluoroalkyl substances — PFAS, the so-called forever chemicals considered a potential health threat and yet widespread in modern products, the environment and the tissues of most human beings and other animals.

The plaintiffs do not drink their well water but use it for irrigation and other purposes.

They asserted in their lawsuit that they would suffer irreparable harm from the project, and asked the court to order an immediate halt to activities that could spread PFAS.

On Monday, Senior U.S. District Judge Frederic Block granted a motion by the four defendant agencies and by South Fork Wind LLC (as an intervenor) to dismiss the complaint.

He noted that the New York Public Service Commission authorized the onshore portion of the project in March 2021 after determining through years of review that it would not exacerbate PFAS contamination.

BOEM did not approve the offshore portion until January 2022.

None of the defendants approved the onshore trenching or have jurisdiction over it, Block wrote.

Therefore, the four agencies cannot be connected to the plaintiffs’ alleged injuries and the plaintiffs lack standing to bring such a complaint, he said.

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NJ Sets Advanced Clean Cars II Proposal in Motion

Gov. Phil Murphy said Monday he has started New Jersey’s adoption of California’s Advanced Clean Cars II (ACCII) rules, filing a proposal with the state Office of Administrative Law that would require electric vehicle manufacturers to increase light-duty EV sales until they account for all new sales in the state by 2035.

The office is expected to publish the proposal in the New Jersey Register on Aug. 21, triggering a public comment period that will run through Oct. 20, 2023.

Murphy announced the plan in February, prompting environmentalists to urge the rules be enacted by the end of the year, ready for the 2027 car sales year.

As adopted by California last August, ACC II requires car manufacturers to provide an increasing percentage of zero-emission vehicles (ZEVs) for sale each year. It defines zero-emission vehicles as battery-electric, hydrogen fuel cell or plug-in hybrid. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

The regulation starts with a 35% ZEV sales requirement for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035.

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

“Our commitment to bringing the ACCII proposal to fruition is a commitment to every New Jersey family and the air they breathe,” Murphy said in a statement.

Transportation, accounting for 42% of the carbon emissions in New Jersey, is the state’s largest source of emissions.

Murphy’s announcement was welcomed by environmental groups, but the New Jersey Business and Industry Association (NJBIA)  and the New Jersey Coalition of Automotive Retailers (NJCAR) criticized the plan, saying the state is not ready for such a fast uptake of EVs. (See Enviros Demand NJ Move Faster on 100% EV Rule.)

‘Impossible’ Task

Ray Cantor, deputy chief government affairs officer for the NJBIA, said implementing (ACC II) “is likely to result in a major increase in New Jersey residents who actually won’t be able to afford to drive.”

With EVs accounting for about 7% of vehicle sales, jumping to 43% when the rules kick in during the 2027 vehicle year is unfeasible, Cantor said.

“We do know that EV sales will increase. However, such a steep ramp-up in electric-only vehicles over 12 years in New Jersey seems impractical, if not impossible, when you consider the lack of charging infrastructure and planning for it,” Cantor said. He added that “such a policy also begs the obvious question of where all this increased electricity will be sourced from.”

If manufacturers fail to meet the mandated targets, “it’s likely there will be a sizable penalty or surcharge imposed on the buyer of every non-EV car sold,” he said. “This mandate will actually drive up the cost of all cars in New Jersey, new and used, by thousands of dollars.”

Jim Appleton, president of NJCAR, said his members have nothing against selling EVs, but “consumer interest in EVs is nowhere near the levels mandated by the California architects of ACC II.”

“New Jersey is not California,” he said. “Rising new and used vehicle prices are a major driver of inflation and adopting this policy will be like throwing fuel on the fire.  By taking away ICE [internal combustion engine] vehicle options for New Jersey consumers, this policy will lead automakers to send only their most expensive and profitable ICE vehicles here, in order to push reluctant buyers to more expensive EVs that may not meet their individual needs.”

Consumer Demand

New Jersey’s Energy Master Plan calls for the state to deploy 330,000 light-duty EVs by 2025. Modeling by the International Council on Clean Transportation projects that New Jersey will have 7.5 million EVs on the road by 2050 if the ACC II rules are enacted, and just 1.3 million if it isn’t.

The state in December had 91,569 EVs on the road, accounting for 1.42% of the state’s light-duty vehicles, according to Atlas Public Policy, a research company. On July 12, the BPU announced the launch of the fourth year of the Charge Up New Jersey incentive program, which offers up to $4,000 for EVs priced below $45,000 and up to $1,500 for vehicles priced between $45,001 and $55,000.

Washington, Oregon, New York, Massachusetts, Virginia and Vermont already have adopted the California ACC II program and Colorado, Maryland, Delaware and Rhode Island are considering it. New Mexico Gov. Michelle Lujan Grisham announced earlier this month that the state would increase its clean vehicle sales to 82% by 2032. (See NM Sets Course to Adopt New Clean Vehicle Rules.)

In New Jersey, environmentalists welcomed Murphy’s advance of the rules. Anjuli Ramos-Busot, New Jersey Director of the Sierra Club, called it “one of the most important policies for New Jersey to adopt.”

“The EV market is already here, the manufacturers are committed and the public wants the options,” she said in a statement included with Murphy’s announcement.

In contrast to Cantor’s prediction, Allison McLeod, public policy director at the New Jersey League of Conservation Voters, said the rules would make EVs more accessible to drivers.

“Since the majority of New Jerseyans — particularly low-income drivers — purchase used vehicles, it will also help with the purchase of affordable vehicles in the secondary market,” she said.

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House Subcommittee Considers Advanced Nuclear Bills

The House Energy and Commerce Subcommittee on Energy, Climate and Grid Security took testimony Tuesday on 15 bills aimed at promoting advanced nuclear plants.

“Our goal is to advance durable and bipartisan policies that will expand nuclear energy and its many benefits for the nation,” said subcommittee Chair Jeff Duncan (R-S.C.). “Policies that make sense for the regulation of nuclear power today, and the new technology is expected to seek licensing and deployment in the coming years.”

Ranking Member Diana DeGette (D-Colo.) said the U.S. can be both a leader in new nuclear technology and regulations that ensure its safety. The Nuclear Regulatory Commission is expected to start formally processing new applications for new reactor designs in the coming years, but it needs to staff up to get that work done efficiently and effectively, while one-third of its staff is eligible for retirement.

“This expected attrition, in addition to the anticipated increase in reactor applications, creates a challenge for the NRC as it completes this work,” DeGette said. “And that’s why I introduced the Strengthening the NRC Workforce Act of 2023.”

The bill would authorize the NRC chair to make hires when the agency is generally short-staffed or needs to replace key employees. The bill is modeled on similar legislation that Congress approved for FERC in 2020, and Democrats also support another bill that would set up an Office of Participation at NRC, which again is modeled on FERC’s office.

Michael Goff, principal deputy assistant secretary of the Department of Energy’s Office of Nuclear Energy, said his agency has no opinion on any of the bills the committee is considering — but the Biden administration shares some of the same goals as the legislators.

“The Biden-Harris administration is prioritizing activities that keep the existing fleet of nuclear power plants in operation, that deploy advanced reactor technologies, that secure and sustain the nuclear fuel cycle, and that expand international nuclear energy cooperation,” Goff said.

Nuclear energy is important to getting the grid to zero emissions by 2035 and the overall economy to net zero by 2050, he said.

Strategic Nuclear Investments

A major issue now is that the U.S. nuclear industry is still highly dependent on Russia for fuel, getting 24% of its uranium from there last year despite its invasion of Ukraine, Goff said. Combined with imports from Kazakhstan and Uzbekistan, countries in Russia’s sphere of influence provide about half of the total nuclear fuel in the U.S., Rep. Bob Latta (R-Ohio) said.

“Expanding our domestic fuel capacity will require strategic investments coupled with import restrictions that protect those investments well into the future,” Goff said. “We must act swiftly to support domestic enrichment capabilities and prepare our industry for this transition. The department welcomes the opportunity to work with Congress to address this national security vulnerability.”

The NRC is gearing up to review new reactor designs and expects four applications to actually start building new plants, and if those are successful, it will take more applications going forward, said agency Executive Director of Operations Dan Dorman.

“As industry is developing new and advanced reactor designs, our staff is reviewing pre-application materials and submitted applications commensurate with the risk and safety significance of the proposed technology,” Dorman said.

NRC staff has submitted a pending proposal that would update the regulators’ review process to deal with the new designs, but some on the committee and in the industry have questioned whether it goes far enough.

“It’s not at all clear that NRC is performing its safety mission and service to the broader mission to enable nuclear energy,” Duncan said.

NRC staff talk about its mission as “enabling the safe and secure use of nuclear technology,” and the agency has been working to consider risks of different proposals up front so the proper amount of resources can be applied in different cases, Dorman said.

“There’s one critical point that I hope that this committee will take away from my testimony today: It is that we are not going to develop an innovative advanced nuclear sector capable of meeting our energy security and climate objectives if we don’t fix the Nuclear Regulatory Commission,” said Breakthrough Institute Executive Director Ted Nordhaus.

Congress has long recognized the importance of nuclear plants to the country’s economic welfare, but the regulatory agency is more narrowly focused on the safety of the plants themselves, he added. NRC should be legally required to consider the overall impact of electric generation and its impact on public health and the carbon intensity of the economy, Nordhaus said.

Good Energy Collective Deputy Director Jackie Toth supports new reactor designs but cautioned Congress about making legislative changes to the NRC’s mission. Changes to a trusted safety regulator just when its activity is ramping up significantly threaten to undermine public confidence in the NRC, she said.

“The cultural changes at the commission that may be necessary to meet this moment and increase the timeliness and efficiency of its activities will depend more on the resonance and strength of commission leadership and the availability of resources for staff than on a change in mission,” Toth said.

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NJ Rejects Solar Bids as Too Expensive

New Jersey’s Board of Public Utilities (BPU) will launch a new solicitation for its Competitive Solar Incentive (CSI) program on Oct. 1 after rejecting a first round of bids as too expensive.

The capacity targets for the solicitation, which will close on Dec. 31, will be largely unchanged from the first solicitation, which closed March 31. The CSI program, with a goal of developing 300 MW of capacity a year, is the state’s first program to target grid-scale projects and is a key element of the state’s solar effort. The BPU’s rejection comes amid growing scrutiny from Republicans and business groups about the cost of the state’s clean energy programs, most prominently the offshore wind sector. The CSI was part of the state’s new solar incentive program, Successor Solar Incentive (“SuSI”) Program, enacted in July 2021 after criticism that previous incentive programs were too generous. (See NJ BPU Approves Rules for Grid Solar Program.)

The board pursued the competitive solicitation in an effort to use market forces to reduce incentive rates.

Veronique Oomen, BPU’s renewable energy project manager, who outlined the agency’s analysis of the first  solicitation at the board’s July 12 meeting, did not say how many bids were submitted, and the board order also did not specify. But all the “responsive” bids exceeded the confidential price caps developed by the BPU, the order said.

“Bids came in at significantly higher price levels than anticipated,” Oomen said. “Staff attributes this mainly to a nationwide high level of economic and regulatory uncertainty at the time of the solicitation, as well as higher than historic levels of cost, which all impacted the development of larger scale solar.”

Due to the “robust response to the solicitation,” Oomen said, BPU staff suggested that the board launch the new solicitation with the same capacity targets as the first bid process. The four BPU commissioners present approved the recommendation, largely without comment.

Developer Concern

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said he was disappointed at the board’s rejection and predicted that it would put the program back months and result in the state seeing a lower-than-expected solar capacity in 2023.

He said the board initially said its internal modeling was designed to remove outlier bids in case there was insufficient competition, rather than using it to set incentive levels, which would be left to the competitive solicitation. The fact that the bids were higher than the board expected “clearly shows that their modeling didn’t take into account the realities of inflation, supply chain issues and COVID and everything else,” he said.

“This either comes down to you want to have competition dictate price … or you don’t,” he said. “And if the board wants to just set prices and say, ‘Listen, this is what grid-based power is worth to the people in New Jersey,’ and nobody can build for that, well, then you don’t want to do it.”

“Let us know, so we don’t waste our time going through all these exercises of bidding,” he added. “These guys have locked up properties. These guys have leases. These guys went and did all the project requirements that were required before they put in a bid. They put in escrow money. They put in a bid fee. They did all the things they were supposed to, and [it’s disappointing] for all of them to be rejected.”

Solar Capacity Growth, Targets

Gov. Phil Murphy, seeking to require all electricity purchased in the state be emission free by 2035, has set targets of 12.2 GW of solar energy by 2030 and 17.2 GW by 2035. (See NJ Governor Sets Out Accelerated Emissions Targets.)

The state had installed 4.5 GW by the end of May, the latest BPU figures available, after adding  458,588 kW in 2022, the state’s largest annual total ever.

In developing the SuSI program, the BPU sought to add 750 MW of new capacity a year. Aside from the CSI program, SuSI includes an incentive program — the Administratively Determined Incentive (ADI) program — aimed at smaller projects, with subsidy levels set by the BPU. Since opening in August 2021, that program has incentivized the development of 200 MW of solar, according to the BPU.

The CSI, which is for projects greater than 5 MW, requires developers to submit projects in one of five categories: basic grid supply (with a target of 140 MW); grid supply on a built environment (target 80 MW); grid supply on contaminated sites and landfills (target 40 MW); net-metered nonresidential projects above 5 MW (target 40 MW); and storage paired with solar (target 160 MWh).

“The competitive solicitation process was specifically intended to ensure that New Jersey ratepayers are incentivizing the projects that seek the lowest incentive contribution from the ratepayers,” the order released last week explained. It added that there was “uncertainty” as to how many bidders there would be. “

As a result, the board had the “the discretion to establish confidential high and low bid thresholds prior to the solicitation.” To ensure that all parties submitted their best price, the board gave each bidder the opportunity to provide their “Best and Final Offer” two weeks after the bid submission period closed, the order said.

Bids Affected by Uncertainty

The order said that “several significant and time-specific barriers may have adversely impacted the level of competition in this first solicitation,” including rising inflation and uncertainty over tariffs on solar panels from Southeast Asia.

The BPU also speculated that some developers may have been put off by the short amount of time allowed in the schedule between the program’s launch in December and the opening of the first solicitation in February, hindering developers’ ability to prepare bids. The order also suggested the requirements for electrical and building permits may have dissuaded some potential applicants. The requirements eventually were waived.

In addition, agency staff speculated some developers balked at a requirement that bidders show that they had an “established position in the PJM interconnection queue.” That requirement “effectively limited the first solicitation to projects that had already started development several years before the program was launched,” the order said.

The board’s order for a new solicitation concluded that “circumstances specific to the timing of the first solicitation, particularly the elevated regulatory risk at the federal level, and market trepidation around both inflation and economic uncertainty, could have played a role in elevating risk premiums for projects participating in the first solicitation.”

The BPU staff also recommended that the agency conduct an “in-depth analysis” of the way it calculated its internal price caps, with an eye to setting the internal caps for the next solicitation.

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NERC’s Cancel Details Grid Threats to House Energy Subcommittee

Appearing before the House Energy and Commerce Committee’s Oversight and Investigations Subcommittee on Tuesday, Manny Cancel, a senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), warned that the North American power grid remains beset by cyber and physical threats.

In a hearing that stretched more than two hours, subcommittee members grilled Cancel and his fellow witnesses on the biggest threats to the nation’s energy infrastructure, including extreme weather. Questions were often colored by members’ partisan alignments, with Republicans criticizing the Biden administration for allegedly burdening utilities that are already struggling to maintain security with environmental requirements and Democrats trying to draw focus to extreme weather events and the administration’s efforts to combat climate change.

Cancel and the other witnesses — who included Sam Chanoski of the Idaho National Laboratory and Bruce Walker, president and chief security officer of the nonprofit Alliance for Critical Infrastructure Security consultancy — tried to avoid getting entangled in these partisan debates, drawing the conversation back to the security environment.

“While there have been no major outages resulting from a cyberattack in the United States, the threat landscape is complex and includes continuously evolving and persistent threats from sophisticated, capable adversaries,” Cancel said in his opening statement, mentioning the dangers posed by foreign cyber actors, as well as physical dangers from domestic extremists.

Among those foreign adversaries, Cancel gave particular weight to China and its cyber campaign discovered this year, when several federal agencies warned that Volt Typhoon, a cyber actor believed to be sponsored by China, had infiltrated a number of “critical infrastructure organizations” in the U.S. (See NERC Issues Cybersecurity Data Request.) He also called Russia a “top cyber threat [that] refines and employs espionage, influence and attack capability,” and he that noted Iran and North Korea’s “growing expertise and willingness to conduct aggressive cyber operations.”

Rep. Cathy McMorris Rodgers | House Energy and Commerce Committee

Asked by committee Chair Cathy McMorris Rodgers (R-Wash.) whether the E-ISAC currently sees more threats from China or Russia, Cancel admitted the leader is “probably China right now.” But he added that Russia “continues to be a very complex adversary as well,” with the capability to wage a widescale attack against a national power grid as demonstrated against Ukraine in 2015 and 2016. But the industry is seeing “a lot of activity from both” nations, he said.

Rep. Morgan Griffith (R-Va.) | House Energy and Commerce Committee

Subcommittee Chair Morgan Griffith (R-Va.) pointed out that China’s infiltration efforts remain ongoing, with the State Department having discovered just last month that the country had backed a group of hackers that infiltrated its email systems, along with those of other agencies.

He suggested that the news showed that “China is likely capable of cyberattacks that could disrupt our infrastructure” before pivoting to criticism of energy-efficiency standards that the Department of Energy proposed last year for distribution transformers. Griffith called the timing of the proposal “terrible,” implying that the standards would make it much more difficult to replace vital equipment compromised in a foreign cyber incident.

On the domestic side, Cancel noted that the last 12 months have seen several high-profile attempts at sabotaging grid equipment, two of which — in Washington state and North Carolina — succeeded in causing outages for thousands of people. He also mentioned a plot to attack the electric grid in Baltimore that resulted in the arrest of two neo-Nazis in February. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.)

Rep. Kathy Castor (D-Fla.), the subcommittee’s ranking member, picked up the domestic extremist thread in her questioning, asking Walker, “What is going on … with the white nationalist movement, attacking transformers across America?” She was referring not only to the Baltimore plot, but also to three men who pleaded guilty last year to conspiring online to damage electric substations in order to start a race war. (See FBI: Conspirators Planned Grid Attack to Start Race War.)

Walker responded that “physical destruction works. People understand how to do it, [and] the means to do it are readily accessible.” He added that NERC has also highlighted the ongoing threat of domestic extremism, most recently in its 2023 State of Reliability report, released last month.

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Cap-and-trade Driving up Washington Gasoline Prices, Critics Say

Critics of Washington’s cap-and-trade system are blaming the six-month-old program for leaving the state with the highest gasoline prices in the nation.

But cap-and-trade defenders urge caution in drawing that conclusion, saying there are multiple reasons Washington drivers are paying so much at the pump.

What’s not up for debate is that Washington’s gas prices currently far exceed those in the rest of the country and outpace other pricey Western states. American Automobile Association figures show U.S. gas prices averaged $3.54/gallon on July 11, while stations in Washington averaged $4.959. Rounding out the top four markets were California ($4.882), Hawaii ($4.702) and Oregon ($4.615), typically among the most expensive for gas.

AAA data from a year ago showed Washington sixth in the nation at $5.36, well below No. 1 California ($6.088) but still above the national average of $4.81.

Washington’s high gasoline prices coincide with unexpectedly steep prices for carbon allowances in the state’s most recent cap-and-trade auction in May. The auction administered by the Department of Ecology cleared all 8.585 million vintage 2023 allowances on offer at a settlement price of $56.10, compared with $48.50 for first auction in February.

The clearing price exceeded the $51.90 soft cap that triggers use of the program’s Allowance Price Containment Reserve (APCR), a mechanism designed to rein in market impacts when allowance prices reach a level considered overly burdensome for emitters. (See Wash. Cap-and-Trade Prices Break Soft Cap.)

‘Not in the Realm of Possibility’

Todd Myers, environmental director for the Washington Policy Center, a Seattle-based conservative think tank, acknowledges  that many factors affect fluctuating gasoline prices. However, he pins current costs on the cap-and-trade program.

“The question is why Washington is the most expensive in the United States. Why are Washington’s prices going up faster than everyone else?” Myers asked.

Myers cited the calculation that a gallon of gasoline produces 1/100th of a metric ton of pollution. With auction prices hovering around $50 per metric ton, that translates into a 50-cent increase per gallon if all the costs are passed on to drivers, he said.

Yoram Bauman, a liberal economist based in Salt Lake City, agrees with Myers’ calculations. In 2016, Bauman helped lead the failed effort to pass Washington’s Initiative 732, a ballot measure that called for creation of a cap-and-trade program coupled with a 1% drop in the state’s sales tax to offset increased fuel costs. Voters rejected I-732 by 18%.

Bauman said I-732 advocates expected cap-and-trade costs to be passed on to customers at the pump.  “The idea that the oil companies are gonna suck it up is not in the realm of possibility,” he said.

Oil major Chevron also agrees that cap-and-trade is what is driving Washington prices. In an email to NetZero Insider, the company said “recent carbon cap-and-trade compliance costs raise gasoline prices by about 10% in the state. … The Washington program is designed to force rapid cuts to carbon intensity in a way that requires consumers to pay higher gasoline prices.”

But disputing that link is the office of Gov. Jay Inslee, a strong supporter of cap-and-trade. In an email, Inslee spokesperson Jaime Smith wrote that gas prices “fluctuate widely due to a variety of factors,” noting that geopolitical events have increased the price of crude oil and pointing out that AAA has said maintenance work at Washington refineries has been a “significant factor” for the region’s prices.

“In May, prices rose more quickly in Oregon than in [Washington]. Despite that, gas prices in Washington are currently about 55 cents a gallon less than they were a year ago,” Smith wrote. “While critics of our climate policy will try to pin any and all price increase on the [2021’s Climate Change Act], they conveniently ignore that fossil fuel suppliers have always had some of their highest profit margins in the Northwest. Recent numbers from the industry indicate their profit margin in Washington ranges between 60 [and] 80 cents per gallon.”

Washington and California have the only full-fledged cap-and-trade programs in the nation. Washington has made noises about possibly joining the Western Climate Initiative, which includes both California and the Canadian province of Quebec.

Relief in Sight?

Meanwhile, possible measures to address the high prices have begun to surface in Washington.

“There are many things that can be done. I don’t think the governor or the supporters want to do anything, however,” Myers wrote in a follow-up email. “The higher the price of the allowances and the larger the impact on gas prices, the more money that goes into the state coffers. Plus, as much as the governor plays dumb, he knows the high allowance prices increase gas prices and he wants that because he wants to push people into [electric vehicles].”

“It’s important to note that with only two auctions complete, it is too soon to accurately assess the policy’s price impacts,” Smith said.

Smith also noted that Washington’s program is designed to eventually link with California’s, which would provide auction participants access to a larger marketplace, trimming allowance prices.

And in light of the high allowance prices, the Department of Ecology will hold the APCR auction Aug. 9, potentially relieving some of the pressure on fuel suppliers.

On July 5, state Sen. Chris Gildon (R) sent the Ecology Department a note asking it to take action on its own before the next legislative session.

He wants the department to slow the pace of reducing state emissions and is asking for more allowances to be offered in the quarterly auctions to help prevent bidding wars.

Gildon also asked the agency to give itself the power to temporarily suspend the cap-and trade program when needed. He wants more emphasis on giving farmers a break on gasoline prices, and he seeks no-cost allowances for state industries competing with foreign companies that don’t have caps on their carbon emissions.

Ecology already is meeting with agriculture stakeholders to come up with a formal proposal to help farmers by September.

Near the end of the 2023 legislative session, state Sens. Mark Mullet (D) and Joe Nguyen (D) introduced a bill that would require the state to set up a remittance program for farm fuel users and freight haulers of agricultural products.

Under Senate Bill 5766, covered users would submit receipts every quarter showing the purchases for fuel used for farming and transporting agricultural products. For each gallon of fuel consumed, the user would be eligible for a remittance equal to the price of a ton of carbon at the most recent state emissions auction, multiplied by 0.8%.

The bill appeared too late for a full vote last spring but will be in the hopper when the 2024 session begins.

“When we passed the [cap-and-trade law], we made a promise to Washington’s farmers to protect them from additional costs that could potentially be passed on from the bill. We need to keep that promise,” Mullet said in an April press release. “We hoped this was going to be addressed in implementation, but we heard clearly in budget hearings that this issue still needs to be addressed. This bill is a small, reasonable step that keeps our promise to our farmers.”

Meanwhile, foreign competition to Washington’s smokestack industries — one of Gildon’s concerns — has been on the state government’s radar for years. This category of “energy-intensive, trade-exposed” (EITE) industries are responsible for roughly 10% of the state’s carbon emissions. EITE industries in Washington include petroleum refiners, manufacturers in the metals, paper, aerospace, wood products, chemicals, computer and electronics sectors, and food processors and cement producers.

In 2022, Rep. Joe Fitzgibbon (D) introduced House Bill 1682 to help EITE industries compete with foreign counterparts who would not have to deal with Washington’s stricter carbon emissions standards. The bill would have slowed down how quickly EITE industries would be required to comply with the state’s increasingly stricter emissions standards.

Fitzgibbon’s bill would have ordered EITE plants to submit 2015-2019 data to the state in 2022, setting a baseline for future calculations. Then, in 2023, each EITE plant would have received a free allowance of permitted emissions equal to the baseline set in 2022. The free allowance would then drop to 97% of a plant’s baseline in 2027, to 94% in 2031 and to 88% in 2035. After 2035, the free allowances would decrease 6% annually from the preceding year.

The bill also would have allowed a facility to request an increase in its allowance if it could prove it was using the best available pollution-fighting technologies.

But EITE industries opposed the bill, arguing they did not have the technologies to deal with emissions on the state’s timetable. The Western States Petroleum Association originally opposed the bill, but eventually switched to neutral with concerns on a revised version. BP America West Coast supported the bill from the beginning. In a 2022 interview, Fitzgibbon said opposition from the EITE industries and their supporters killed the bill behind the scenes.

For Myers, one problem to be addressed is that oil companies are limited in the percentage of allowances they buy per auction, leaving them at the mercy of speculators who also buy the credits to sell later at higher prices. He also called for measures to encourage lower final auction prices, which would translate to decreases in gas prices.

To Bauman, the I-732 approach still holds a key for the success of the current cap-and-trade program. High gas prices provide an incentive to shift away from fossil fuels, which is a key component in combating climate change, he said.

“The best option is to balance the price increase on fossil fuels by reducing taxes elsewhere. This is what we tried to do with I-732: offset the impacts of a carbon tax with a reduction in the state sales tax and other tax cuts that would have put money back into people’s pockets,” he said.