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November 1, 2024

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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.

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ERCOT Demand Exceeds 82 GW for 1st Time

AUSTIN, Texas — “Welcome to the heat dome, y’all,” Austin-based energy consultant Alison Silverstein said during a panel discussion at NARUC’s Summer Policy Summit, acknowledging the sizzling temperatures outside that had the Texas capital city under an excessive heat warning until 8 p.m.

Temperatures in Austin topped out at 105 degrees Fahrenheit, helping ERCOT to again set a record for hourly peak demand when load averaged 82.03 GW during the hour ending at 4 p.m. That broke the record set Monday when demand averaged 81.91 GW during the 6 p.m. hour.

Demand averaged 82.54 GW during the hour ending at 5 p.m., raising the previous high.

Temperatures are forecast to remain above 100 degrees in much of the state into next week. ERCOT’s six-day forecast projects demand to approach 84 GW Wednesday and exceed 80 GW through Friday.

The record came on the last day of ERCOT’s third weather watch of the season. The grid operator says it’s continuing to operate the grid conservatively and bringing generating resources online early in case of sudden changes in generation or demand.

ERCOT had more than 7,000 MW of operating reserves available late Tuesday afternoon.

With the new peak, the ISO’s hourly average demand now has exceeded 80 GW 23 times this summer. It reached that mark once last year.

Average prices were less than $30/MWh Tuesday, a sign that congestion was not an issue.

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Maryland Climate Report Lays out Pathways to Achieving Goals

To cut its greenhouse gas emissions 60% below 2006 levels by 2031, Maryland will need to grow solar and wind generation 500% across the state, while pushing for early closure of natural gas plants and convincing the 11 other states in the Regional Greenhouse Gas Initiative (RGGI) to up their emission-reduction targets to 100% by 2045.

Those ambitious goals are just a few of a long list of actions the state could take to reach the GHG-reduction and clean energy targets set out in the Climate Solutions Now Act (SB 528) passed in 2022, according to the Maryland Climate Pathway report released recently by the state’s Department of the Environment (MDE). (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)

The 60% cut is an interim step toward the law’s goal for Maryland to slash GHG emissions to net-zero by 2045, one of the most ambitious climate goals in the country. Another provision of the law required MDE to draft a plan for implementing the CSNA, to be submitted to the governor and General Assembly by June 30.

Emissions trajectory to reach Maryland’s net-zero target in 2045 | MDE/CGS

The Center for Global Sustainability at the University of Maryland College Park authored the report, which was released on June 30, kicking off a comment period and a series of live and virtual public hearings. The first live public hearing is scheduled for July 25 at Bowie State University in Bowie.

A final virtual hearing is scheduled for Sept. 26, and a final report is due by year-end.

Gov. Wes Moore (D) hailed the report as a “science-based path” and “a major step forward in addressing the historic challenges we face when it comes to our climate goals.”

“The report outlines a host of options to not only help address climate change, but also to help create a new center for industry in Maryland that will promote equity, ensure economic benefit and make Maryland a world leader in sustainable practices for generations to come,” Moore said.

“The integrity of the report is strong,” Kim Coble, executive director of the Maryland League of Conservation Voters, agreed, while stressing the 118-page document is neither a policy statement nor a final set of decisions or recommendations.

“It was never meant to be a policy statement,” Coble said. “It says, ‘Here are pathways to get to this very ambitious reduction goal. … You can do this; you can do that; you can accelerate here.’”

Accelerated action by lawmakers and others will be critical, Coble said. The report notes that Maryland already is halfway to the 60% target, with GHG emissions down 36.7 million metric tons (MMT) as of 2020.  But the report says that even if all of the CSNA’s provisions, along with other existing state policies, are fully implemented, Maryland still will fall short of the 2031 target by about 10.6 MMT.

Timeline with milestones set by Maryland for achieving climate goals | MDE/CGS

Filling that gap will require new policy actions that may or may not be politically or economically feasible, says Michael Powell, an environmental lawyer at Gordon Feinblatt, who previously served as principal counsel for MDE.

For example, the report calls for new standards requiring zero-emission home appliances and all-electric new construction, goals that Powell says may be overly ambitious, given the diverse demographics and political leanings across different regions in the state.

“People seem a little more willing to look at heat pumps in new construction, but there seems to be very strong resistance to giving up gas stoves,” he said.

Other potential steps on the report’s pathway to the 60% cut in GHG emissions include:

  • creating an in-state, economy-wide cap-and-invest program, in addition to RGGI;
  • shifting the passenger vehicle fleet and medium- and heavy-duty trucking fleet to zero-emission vehicles via implementation of California’s Advanced Clean Cars II rule, which Moore adopted earlier this year, and the clean trucks targets set in the Clean Trucks Act signed into law in April;
  • updating the state’s building codes and setting new building performance standards;
  • shifting the electricity Maryland imports to clean power by getting RGGI to set a 100% emissions reduction goal by 2045; and
  • leveraging the green hydrogen and carbon capture tax credits in the Inflation Reduction Act to develop alternative fuels and energy sources in the state.

Under the Advanced Clean Cars II rule, all new light-duty and passenger vehicles sold in the state will need to be zero-emission by the 2035 model year. The Clean Trucks Act calls for MDE to set regulations for increasing sales of zero-emissions trucks by Dec. 1, 2023, but also to perform a needs assessment report by Dec. 1, 2024.

Possible, not Probable

A major concern about the report is its lack of specificity on how its ambitious goals will be achieved, what the price tag will be and how those costs will be allocated.

For example, Powell pointed to considerable obstacles to decarbonizing imported power, which accounts for about 40% of its electric power, according to the U.S. Energy Information Administration.

Beyond PJM’s massive interconnection queue — which stands around 290 GW, most of which is renewable energy and storage — Powell sees growing opposition to utility-scale solar across the state, a trend that is occurring across the country.

“Pile those one on top of the other, [and] it means that utility-scale solar is actually down in the state,” he said. “The plan calls for PJM [states] to adopt a net-zero target. Looking at the political landscape, I think that’s a real challenge.”

Coble also noted that the report makes some faulty assumptions about current levels of renewable energy adoption in the state. The state’s current renewable portfolio standard — calling for 50% of the state’s power to be renewable by 2030 — includes a 14.5% carve-out for solar. But according to the Solar Energy Industries Association, solar now provides only 5.17% of the state’s power.

Powell sees the goals set out in the report as possible, but maybe not probable.

“We need to find out, is the General Assembly willing to put the kind of funding and incentives for some of the proposals in the report?” he asked. “Because I personally do not believe that private enterprise can achieve those goals without a lot of state funding.”

Coble said another key factor will be “courageous leadership from our elected officials, from this administration. Courageous leadership is going to make or break the success of this, more than anything else.”

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Rhode Island Energy Rejects Revolution Wind 2 Proposal

Rhode Island Energy said Tuesday it would not move forward with a power purchase agreement with Revolution Wind 2, which submitted the only proposal in Rhode Island’s most recent offshore wind solicitation.

The 884-MW proposal by Ørsted and Eversource was determined to be too expensive and to not meet all the requirements of the state’s Affordable Clean Energy Security Act (ACES).

Rhode Island Energy, a subsidiary of PPL, ran the solicitation and would have purchased the electricity generated by a successful project. The company said in a news release that it will continue to work to expand the amount of power flowing off the ocean and into the Ocean State.

“We recognize some will be disappointed that we didn’t choose to move forward on negotiating this PPA, but that doesn’t mean we are abandoning our commitment to offshore wind in Rhode Island,” Rhode Island Energy President Dave Bonenberger said. “In fact, we are already in discussions with state and regional leaders about new opportunities to bring more offshore wind to the state, which we hope to progress in the coming months.”

Among those unhappy with the decision was Ørsted, the world’s top offshore wind developer.

A spokesperson told NetZero Insider via email:

“We’re disappointed that Rhode Island Energy did not select Revolution Wind 2. This project would put Rhode Island’s 100% clean energy future in reach, delivering renewable energy to hundreds of thousands of homes and creating more than $2 billion in direct economic benefits to the state, with historic investments in local union jobs, workforce training, ports and the supply chain. We will assess our options for Revolution Wind 2.”

The news came one day after federal regulators issued the environmental impact statement for Revolution Wind 1, poising it to be the fourth wind project permitted in federal waters. It would stand at least 16 miles south of Rhode Island and send 400 MW to Rhode Island and 304 MW to Connecticut.

Revolution Wind 1 also is a product of the Ørsted-Eversource partnership, which is in the process of dissolving as Eversource exits offshore wind development.

Rhode Island’s latest solicitation was launched in mid-2022, a time when developers were starting to seek renegotiation of existing deals amid soaring construction costs and interest rates.

New York attracted a robust response to its 2022 solicitation, but it included the option for a future inflation adjustment, an option that potentially will raise costs for consumers.

Rhode Island Energy, by contrast, received just the one proposal in March 2023, and its comments soon after suggested that the deal with Revolution Wind 2 would be costly.

After four months of review, the company expanded on those comments Tuesday, saying the costs were deemed too expensive for customers to bear.

“The economic development benefits included in the proposal were weighted and valued appropriately by our evaluation team, but ultimately it was determined those features did not outweigh the affordability concerns and other ACES standards,” Bonenberger said in the news release.

Rhode Island Energy said that within 60 days, it will submit a comprehensive explanation of its decision to the state Public Utilities Commission. The state Office of Energy Resources and the Division of Public Utilities and Carriers will file comments as well, the company said, and the bidders will have a chance to respond.

Rhode Island Energy said it would continue to work with the state agencies and stakeholders to find more affordable ways to bring additional offshore wind energy to the state.

Offshore wind power is an important part of the state’s strategy to use 100% renewable energy by 2033 and achieve net-zero status by 2050.

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FERC Seeks More Info on NYISO DER Aggregation Proposal

FERC staff asked NYISO to provide additional detail on the ISO’s proposed tariff revisions for integrating distributed energy resource aggregations into its markets, including a rationale for its 10-kW minimum (ER23-2040).

FERC’s July 18 deficiency notice requested an explanation for the 10-kW threshold, “as opposed to another threshold,” and asked whether the ISO’s position would change once it deploys the automation features it is currently developing. State regulators and clean energy groups have protested the 10-kW minimum, which the ISO said was needed to save staff time reviewing aggregations for interconnection. (See NYISO Defends DER Aggregation Proposal, 10-kW Minimum.)

FERC’s letter also sought detail on other revisions, including how long utilities would have to review DER reliability and safety study results and what the review would entail. Staff also asked what would constitute a “material modification” to a DER and how the ISO would conduct its aggregation derating process.

Additionally, FERC asked NYISO to justify its new DER metering and telemetry requirements, explain why it is appropriate to use certain reference levels for aggregations, and expand on its definitions related to the elimination of locational-based marginal pricing and bid-based reference levels for aggregations.

NYISO must respond to FERC’s letter by Aug. 17.

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MISO Convening Task Team to Shore Up Credit Policy

CARMEL, Ind. — MISO said it will debut a task team dedicated to improving its credit policy as market participants experience more price volatility in the market and default risk grows.

Brian Brown, of MISO’s credit and risk management team, said MISO is in the process of forming the Credit Policy Enhancements Task Team, with meetings to begin in September. At the July 13 Market Subcommittee meeting, Brown said risky circumstances, such as widespread winter storms, are occurring more frequently and could give rise to “defaults or near-default situations.”

Brown said the task team will examine extreme weather events to see how MISO’s credit policy can be strengthened to discourage defaults. Brown said MISO will look at its minimum capitalization requirements to account for increased price volatility, review its estimated exposure calculations and credit requirements for virtual transactions, and explore the possibility of adding a minimum collateral requirement for all market participants — something MISO doesn’t have.

He also said MISO may update the bankruptcy language in its tariff to align with Federal Bankruptcy Code requirements and consider tariff language that allows MISO to implement flexible payment terms in the event of a marketwide event that causes “large, unexpected market charges.”

Brown said as a result of the task team’s work, MISO may begin to make some FERC filings to reinforce its credit policy in the first quarter of 2024.

“We really hadn’t experienced any losses prior to 2021. What we’re noticing is there’s an increase in volatility in the markets. … Frankly, we’ve got some scar tissue from dealing with some issues,” Brown said, referencing virtual traders who nearly defaulted and lost $150,000 in the market in January 2021 and the market participants who lost $38,000 related to the Brazos bankruptcy following Winter Storm Uri in February 2021. The storm led to MISO making 140 margin calls totaling $325 million. MISO makes margin calls when a market participant’s credit exposure is greater than the financial security and unsecured credit they have in place, and MISO requests additional collateral or reduced activity in its market.

MISO said it avoided defaults during the December 2022 winter storm, though it had to issue more than 100 credit exposure warnings. (See MISO Defends Energy Exports During December Storm.)