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November 7, 2024

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California Governor Seeks Central Procurement Authority

The office of California Gov. Gavin Newsom has proposed legislation that would establish a central procurement authority to ensure the state has sufficient electricity resources to avoid shortfalls as it struggles with extreme heat, tight supply and a changing resource mix across the West.

The proposal is contained in budget trailer bill language that follow’s Newsom’s fiscal year 2023/24 budget released in January. No lawmaker has yet signed on to carry the bill in the current legislative session.

The governor’s proposal would give the California Public Utilities Commission (CPUC) the option to name the state Department of Water Resources (DWR) or an investor-owned utility to procure energy for the state’s load-serving entities, including public utilities and community choice aggregators.

“For California to achieve its long-term greenhouse gas emission reduction goals, while maintaining a reliable electrical system and providing customers with greater choice in electricity retail providers, the state must establish a new central procurement function within the [DWR] that enables the development of a more diverse portfolio of renewable and zero-carbon energy resources,” it says.

The state has directed investor-owned utilities to procure for other LSEs in the past, but DWR has not performed that function. The governor’s legislative language would authorize it to do so if called upon by the CPUC.

The department’s State Water Project is a major producer of electricity through its hydroelectric projects and the state’s single largest consumer of electricity, which it uses to operate pumping plants that deliver water throughout the state.

Under the proposal, DWR could issue bonds and recover costs through ratepayer charges approved by the CPUC as long as the charges “[do] not unreasonably increase costs to customers … compared with the procurement of diverse clean energy resources by an electrical corporation.”

DWR would have to conduct a competitive procurement process and “prioritize investments that do not compete with the procurement of diverse clean energy resources already planned for development and disclosed by load-serving entities or local publicly owned electric utilities.”

LAO Report

In a March 10 report on the governor’s proposal, the state Legislative Analyst’s Office says that “according to the administration, the DWR procurement is intended to be for long lead‑time resources such as offshore wind, geothermal, and long duration storage. The proposed statutory changes, however, do not explicitly limit this procurement option to those types of resources.”

“DWR would utilize its new Strategic Reliability Reserve office and staff to manage the procurement,” the LAO report says.

The department administers the state’s Electricity Supply Strategic Reliability Reserve Program (ESSRRP), a $5.2 billion fund sought by Newsom in last year’s budget and enacted in June to pay for new generation and storage, to keep older natural gas plants online and to provide emergency backup generation through DWR. (See California to Pass Sweeping Energy Policy Changes.)

California has experienced blackouts and near misses the past three summers as it tries to shift its resource mix from fossil fuels to renewable power amid extreme heat, wildfires, drought and strained supply in neighboring states.

Another component of the governor’s legislative proposal is a requirement that load-serving entities pay for failing to obtain sufficient resources to meet demand by making payments to the strategic reserve fund. The move is intended to “discourage LSEs from over-relying” on the ESSRRP, the report says.

“The state would assess a payment if an LSE does not meet its reliability obligations in a month when the state had to access the ESSRRP,” it says. “Specifically, the payment would be based on a calculation that factors in the cost of the energy resource provided by the ESSRRP and the LSE’s deficiency in meeting its monthly resource adequacy or planning reserve requirements. The payments would be calculated by the CPUC and the California Energy Commission.”

The payments would be in addition to fines for resource inadequacy imposed by the CPUC.

Questions for Lawmakers

The LAO report proposes questions for lawmakers to consider when weighing the governor’s proposal, including the potential impact on ratepayers of adding DWR procurement costs to their already-high electricity bills.

It also questions the market effects of central procurement by DWR.

“The current market for energy resources is strained, with a large number of LSEs competing for a relatively small pool of projects that often will take years to develop,” it says. “How the entrance of DWR — a large, well‑resourced entity with the backing of the state — would influence the market for new energy resources is unclear.”

The report also questions whether the state needs new central procurement authority or whether current resource planning processes and the ability of IOUs to procure for other LSEs is enough.

Having DWR in charge of long-lead time resources poses risks, the report says.

“The administration has expressed concerns that LSEs might be hesitant to procure large, long‑lead time resources because of their high cost and risk as newer technologies,” it says. “The Governor’s proposal to have the state pursue procuring these resources instead essentially shifts this risk from the privately owned utilities (and their investors) to ratepayers and taxpayers. While this could help facilitate the development of these important resources, additional information is needed about the types of risks involved and their magnitude for the Legislature to determine if they are worth the potential benefits.”

Finally, the LAO asks whether the energy policy changes should be considered as part of the budget process.

“The Governor’s proposals represent significant policy changes for the state, and they do not have a particularly strong nexus with the budget,” the report says. “The Legislature will want to consider the most appropriate venue for discussing and deliberating these proposed changes. For example, the Legislature could consider these proposals through the policy process, rather than as part of the budget process.”

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Maryland Bill Would Require Utilities to Report Votes at PJM

A bill passed by the Maryland House of Delegates last week would require that utilities submit annual reports detailing their votes at PJM, including an explanation of how each vote benefits the public interest.

Del. Lorig Charkoudian, the sponsor of HB1186, said the bill would provide needed insight for legislators into the decision-making at PJM and aid them in determining if utilities operating in the state are acting contrary to clean energy policy goals and ratepayers’ interests. The General Assembly holds the authority to determine the state’s generation mix targets and is expected to protect consumers, she said, but its legislation is often undermined by decisions made by PJM stakeholders.

The House passed the bill 100-35 on Saturday, advancing it to the Senate Education, Energy and the Environment Committee.

“We’re in this position where sometimes I call PJM a shadow government because you have an LLC that is theoretically … neutral on policy, but in reality the decisions they make every day … absolutely make or break our climate change rules,” Charkoudian told RTO Insider.

Most of the state’s utilities are voting members of PJM:

  • the four investor-owned utilities: Exelon’s (NASDAQ:EXC) Delmarva Power and Light, Potomac Electric Power Co. (Pepco) and Baltimore Gas and Electric; and FirstEnergy’s (NYSE:FE) Potomac Edison;
  • the municipal utilities for Berlin, Easton, Hagerstown, Thurmont and Williamsport; and
  • the Southern Maryland Electric Cooperative (SMECO).

Two rural electric co-ops — A&N Electric and Choptank Electric — are members of Virginia-based Old Dominion Electric Cooperative, itself a PJM member but presumably would not be subject to the bill. According to the fiscal and policy note for the bill released by the Department of Legislative Services, “the companies can likely submit the required voting record information with existing resources. If not, local expenditures increase minimally. Revenues are not affected.”

Charkoudian said that lawmakers’ attempts to understand how local utilities are voting on matters affecting the state are stymied by PJM rules, which do not make public the votes individual entities make at the lower committees and task forces. Though votes at the Members Committee are public, Charkoudian said initiatives benefiting the state may be blocked before they reach that level without legislators being able to understand why.

In particular, she pointed to the parameters defining the variable resource requirement curve as influencing the type of generation that is likely to be built in the state, while backlogs in the interconnection queue have limited the ability for renewable generation to be developed.

“I don’t think this bill solves the problem, but it leads to a better … conversation about what we can do to ensure that PJM is reinforcing what we’re trying to do,” Charkoudian said.

PJM spokesperson Jeff Shields said that all committees where votes are taken are open to the public and media.

“PJM has not been asked to opine on this legislation,” Shields said. “All committees where votes are taken are open to the public and to the media. Votes of PJM’s most senior committee, the Members Committee, are public, and a voting report is posted showing individual votes.”

Stakeholder Comments

The Maryland Energy Administration, Office of People’s Counsel and the state’s chapter of the Sierra Club submitted favorable testimony to the House Economic Matters Committee. They argued that the bill would provide transparency without interfering with utilities’ ability to cast votes on issues before PJM.

“Public service companies are provided with state-granted monopolies in order to perform important public functions and are required to operate ‘in the interest of the public,’” the OPC said. “At the same time, however, many public service companies are private companies with fiduciary obligations to earn profits for their investors. Unless effectively regulated, public service company votes at PJM can result in serious misalignments with the public interest.”

The IOUs and SMECO all submitted testimony in opposition to the bill, which they say would stifle debate and create significant administrative burden without providing much benefit to legislators.

Exelon Vice President of Federal Regulatory Affairs Sharon Midgley, a regular attendee of PJM committee meetings, said the company supports transparency and is willing to engage with policymakers and regulators, but it believes the legislation in its current form misses the mark. She said the requirement that the public benefit rationale for each vote be described is vague, with there being many competing issues of public interest, including affordability, security and the environment.

For votes in the lower committees, Midgley said there is currently no framework for logging individual votes — particularly those taken by voice or acclamation, which allow an item to pass if there are no objections. Requiring those votes to be cast would add a responsibility to stakeholders based in other states and sectors.

Midgley also pointed to PJM’s Manual 34, which states that all matters before stakeholders are considered preliminary until a vote is taken by the MC.

“All participants understand that documents, reports, slideshows and other written material used at all until final Member Committee and/or PJM board approval are intended to be works in progress and to encourage dialogue, discussion, debate and, preferably, movement towards consensus,” the manual says. “Therefore, such work products should be treated in the spirit to which they are intended; that is, not as final or complete documents, nor the final position or view of a participant.”

In its comments, FirstEnergy noted that the votes at the Markets and Reliability Committee and MC consolidate all affiliates together so each corporate entity has a single vote, which it said often means that its vote on an issue may not be driven by issues in any one state.

“Because of this consolidated vote, there are times when FirstEnergy’s ‘vote’ is not driven by Potomac Edison or Maryland considerations. Compelling utilities to report and explain their vote in these situations just does not make sense,” said the company, which has subsidiaries in Ohio, Pennsylvania, West Virginia and New Jersey.

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MISO Issued Show-cause on Seasonal Capacity Auction Values

FERC on Friday issued MISO a show-cause order saying the grid operator appears to be violating its tariff by failing to publish a systemwide unforced capacity ratio ahead of its first four-season capacity auction in a few weeks.

The commission said although MISO has updated individual units’ ratios of unforced capacity to intermediate seasonal-accredited capacity, it hasn’t updated the systemwide ratio (EL23-46). It ordered MISO within seven days to either show cause as to why it would not have to update the ratio or explain how it will revise the ratio before it conducts its seasonal capacity auctions for the 2023/24 planning year beginning June 1.

Commissioner Mark Christie said FERC’s order on MISO’s missing ratio is more proof that grid operators’ capacity markets are convoluted and dysfunctional.  

The ratios are a new concept added alongside MISO’s seasonal, availability-based accreditation style. (See FERC Affirms MISO’s Seasonal Auctions, Accreditation.) MISO and market participants use the ratios to validate capacity values. The RTO said it intended it to be “an annual calculation posted well in advance of each PRA in order to provide market participants certainty as they plan to meet planning reserve margin requirements.”

In an early March filing to FERC to explain issues surrounding the systemwide ratio, MISO said its tariff was silent on the matter of when the ratio should be published in advance of its four-season Planning Resource Auction (PRA) conducted in April. The RTO said it published the annual ratio on Dec. 15, but found that its software registered some previously approved and exempt generator outages over the last three years as illegitimate, thus lowering expected capacity.

While MISO said it issued individual corrections for affected generators, it said it could not update the systemwide ratio again in time for the 2023/24 PRA.

Late last month, Director of Resource Adequacy Coordination Zakaria Joundi said MISO’s filing on the ratio is “an attempt to share and communicate with FERC what we’ve been up to” and signal to FERC that “potential process changes” may be needed moving onto the next planning year.

At the time, Joundi said MISO was in the “final stretch” before running its first seasonal auctions.

FERC said that while it was sympathetic to the challenges MISO faced in pulling off its first seasonal auction, the RTO was nonetheless violating its tariff by not releasing an updated ratio.

“We understand that this is the first year in which MISO is transitioning to its seasonal capacity construct and that errors may occur in executing complex calculations,” FERC said. “In this instance, MISO identified an error in how outage exemptions were calculated and corrected this error by updating the [seasonal accredited capacity] values of affected resources.  However, the … tariff does not afford MISO with discretion to decide whether to update the ratio; rather, MISO must calculate the ratio consistent with the formula set forth in the tariff.”

In an email to RTO Insider, MISO said it was reviewing FERC’s order and will submit a formal response by March 24.

Christie Criticizes Capacity Markets 

Christie seized on the order as further evidence that grid operators’ capacity markets are plagued by complicated rules.

He said MISO’s seasonal capacity construct is “daunting[ly] complex,” pointing out that the seasonal accreditation values assigned to some thermal resources in the ratio aren’t even “directly” used as their accredited capacity.

“Given these Rube Goldberg machinations, it is perhaps no wonder that something went awry in MISO’s accreditation calculations — though, in fairness, MISO attributes the incorrect calculations to an error by its Control Room Operations Window (CROW) software program in assessing the timeliness of outage submissions (which I suppose represents a serving of CROW),” Christie wrote in a concurrence to the order.

“This proceeding shows once again that these administrative constructs known as capacity markets are characterized by such hopeless complexity and impenetrable opacity that they represent the classic example of a game that only insiders can play and win,” Christie continued. “The interest groups that have the time and resources to navigate this labyrinth can and will make sure their interests are protected or at least advocated well. Whether the public interest is or even can be protected in this insiders’ game is increasingly a salient question.”

Speaking this month at the Gulf Coast Power Association’s MISO-SPP conference, MISO Independent Market Monitor David Patton predicted MISO will gather “lessons learned” from the April auctions and results. He said MISO moved too hastily to design and seek approval for its seasonal market.

“With the speed at which they implemented it, there’s going to be some things that are going to be not quite right,” Patton said.

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Guterres: G20 Nations Should Commit to Net Zero by 2040

If the world does not slash its greenhouse gas emissions immediately, it will likely hit the 1.5-degree Celsius tipping point for potential climate catastrophe by the mid-2030s, according to one of the lead authors of the Sixth Assessment Report (AR6) Synthesis released Monday by the U.N.’s Intergovernmental Panel on Climate Change (IPCC).

“The real question is whether our will to reduce emissions quickly means we reach 1.5 degrees [and we] go a little bit over but then come back down, or whether we go blasting through 1.5 degrees, go through even 2 degrees and keep on going,” Peter Thorne said at a press conference livestreamed from Interlaken, Switzerland. “This is why the rest of this decade is key. The rest of this decade is whether we apply the brakes and stop the warming.”

The 1.5-degree limit for climate change was originally set by the Paris Agreement, finalized at the 2015 U.N. Climate Conference of the Parties (COP21), and kept alive, barely, at subsequent U.N. conferences, including COP27 in Egypt last November. The AR6 Synthesis, a combination of three previous IPCC reports, once again raises an urgent and immediate call to nations to up their commitments and their actions to make deep cuts in GHG emissions by 2030. (See Closing the Emissions and Honesty Gaps at COP27.)

Antonio Guterres (IPCC) FI.jpgUN Secretary General António Guterres | IPCC

In a video message to the Interlaken event, U.N. Secretary General António Guterres called the report “a how-to guide to defuse the climate time bomb,” as well as “a survival guide for humanity.” He then proposed an “acceleration agenda,” with the Group of 20 (G20) countries with the largest economies, including the U.S., to committing to net-zero electricity generation by 2035 and net-zero economies by 2040.

Targets for developing countries would be 2040 for net-zero electricity and 2050 for net zero economy-wide.

The plan also calls for phasing out coal by 2030 in developed countries and 2040 in all other countries, and “a global phasedown of existing oil and gas production compatible with the 2050 global net-zero target,” Guterres said.

“I am also calling on CEOs of all oil and gas companies to be part of the solution,” he said. “They should present credible, comprehensive and detailed transition plans … [with] actual emission cuts for 2025 and 2030 and efforts to change business models to phase out fossil fuels and scale up renewable energy.”

Developed countries must also deliver on their financial commitments to help developing countries with their own energy transitions and create “a roadmap to double adaptation finance before 2025.” The new loss and damage fund agreed to at COP27, to compensate developing countries already suffering from the effects of climate change, should be implemented this year, Guterres said.

“In short, our world needs climate action on all fronts: everything, everywhere, all at once,” Guterres said.

The Synthesis report also sets a marker for COP28, to be held in the United Arab Emirates in November, when the first “global stocktake” will be held to evaluate nations’ progress toward the goals of the Paris Agreement. The stocktake is a two-year process, which began at in 2021, at COP26 in Glasgow, according to the U.N.

“The global stocktake is critically important because the international community has yet to live up to its commitments, and climate action has yet to reflect deep transformations needed across all sectors to build a resilient future,” the U.N. said in a blog post.

‘The Ultimate No-brainer’

With each successive IPCC report, the evidence of warming and its impacts grow more alarming and potentially catastrophic. Figures in the AR6 Synthesis show that global surface temperatures were already close to 1.1 degrees higher in 2011-2020 than in the last half of the 19th century.

“In 2019, atmospheric CO2 concentrations (410 parts per million) were higher than at any time in at least 2 million years,” the report says. “Concentrations of methane (1,866 parts per billion) and nitrous oxide (332 parts per billion) were higher than at any time in at least 800,000 years.”

The impacts include higher mortality rates from extreme weather events, food and water insecurity, and “hundreds of local losses of species,” the report says. “Approximately 3.3 billion to 3.6 billion people live in contexts that are highly vulnerable to climate change,” with “the largest adverse impacts” being felt in developing countries and among remote populations in island nations and indigenous communities.

As an immediate step, Guterres called for global early warning systems against natural disasters within four years. But the report also suggests that as global temperatures continue to rise, causing more frequent and severe extreme weather events, such systems and other adaptation measures could rapidly lose their effectiveness.

Adaptation is widely defined in the report to include agricultural practices such as soil conservation, as well as wetlands and forests restoration and green urban planning. But “unless mitigation [to cut emissions] also happens at the pace that’s required, many of the adaptation [measures] we’re investing in now will not remain as effective as they are today,” said Aditi Mukherji, another lead author.

Still, IPCC Chair Hoesung Lee said the report also provides a message of hope that “we already have the technology and know-how to get the job done.” His list of immediate to-dos includes “renewable energy instead of fossil fuels, energy efficiency, green transport, green urban infrastructure, halting deforestation, ecosystem restoration, and sustainable food systems that reduce food loss and waste.”

“Investing in these areas and more besides will help to stabilize our climate change, nature and biodiversity loss, and pollution and waste,” he said. “It is frankly the ultimate no-brainer.”

Looking at currently available technologies, Lee pointed to energy efficiency as an area ripe for expansion, with the potential to cut energy demand by 40 to 70% in some sectors over the next two decades. Urban centers could also achieve major reductions in emissions through “comprehensive, climate-friendly development patterns,” he said.

Finance will be another vital area for climate action, said Dipak Dasgupta, another lead author. “At the core, [the] financial system needs to respond to the challenges ahead. … Our underlying assessment suggests that … the investments that need to take place in climate adaptation and mitigation need to rise by two to six times at least.”

The way forward must combine government policy with a shift in financial institutions, Dasgupta said. “The central banks, the regulators themselves, have to start recognizing the urgency,” he said. Finance needs to flow to the least developed, most vulnerable areas that need it the most, sooner rather than later, he said.

The authors also argued for more than institutional change. “What we need now is a political will on the part of the policymakers [and the] constituents [who decide] who would be the political leaders,” Lee said.

Peter Thorne (IPCC) FI.jpgPeter Thorne, a lead author of AR6 Synthesis | IPCC

Public support for immediate action is critical, with individual, “personal motivation” driving a policy path toward net zero, he said.

Thorne agreed that a level of personal commitment is going to be needed to push past “the point … where climate change can be somebody else’s problem. If we had had to the foresight to act in 1990, to start to act in a meaningful way … we would have a vast array of options available to us to still avoid 1.5,” he said.

“We have to act now … across all scales. Do not say it is your government’s problem, your community’s problem. It is your problem as part of that community, as part of that country, to make a difference at this point for a resilient future.”

Climate Tradeoffs

President Biden has already committed the U.S. to cutting GHG emissions by 50 to 52% by 2030, decarbonizing the electric power system by 2035 and going net zero economy-wide by 2050. But, according to the AR6 Synthesis, even such ambitious targets may not be enough to curb climate change.

“Only a small number of the most ambitious global modeled pathways to limit global warming to 1.5 degrees C … by 2100 [do so] without exceeding this level temporarily,” the report says. One way forward is having “annual rates of [carbon dioxide removal] greater than residual CO2 emissions.”

Jessie Stolark, executive director of the Carbon Capture Coalition, welcomed the report’s support for carbon-removal technologies and “the critical role that dramatically accelerated deployment of carbon-management technologies and associated infrastructure must play in managing emissions.”

Pointing to new incentives for carbon capture and sequestration in the Inflation Reduction Act, Stolark said, “The task ahead requires us to heed the continued and increasing alarms being sounded by the world’s scientific community and implement the available policy framework in a swift and effective manner, to ensure carbon-management technologies can achieve their full greenhouse gas emissions reductions potential, as outlined in this new report.”

Recent reports from the U.S. Energy Information Administration and the National Renewable Energy Laboratory also underline the pivotal role computer models may play in determining whether the political, personal and financial will can be mustered for effective and sustained climate action.

The EIA’s Annual Energy Outlook (AEO) 2023 predicts the U.S. will be able to cut its CO2 emissions by 25 to 38% below 2005 levels by 2030, falling well short of Biden’s target. The AEO sees electric generating capacity doubling by 2050, with solar, wind and storage accounting for most of the increase, but nuclear and natural gas remain more or less static. (See EIA: Major Solar Growth Ahead, but EV Adoption Stalls After 2030.)

The range for solar runs from 22 to 56% of U.S. power production, EIA Assistant Administrator Angelina LaRose said at a launch event for the report in D.C. on Thursday. Bonus tax credits in the IRA — for example, for projects paying prevailing wages and offering registered apprenticeships — could raise those figures to 39 to 59%, LaRose said.

But, the AEO’s estimates in many cases did not take into account the full potential impact of IRA incentives, according to EIA Administrator Joseph DeCarolis, because the Internal Revenue Service has yet to issue final guidance on how they will be implemented.

The NREL report, also released on Thursday, used a different computer model, which did factor in a fuller picture of the IRA. Combined with provisions of the Infrastructure Investment and Jobs Act, the IRA incentives could drive clean energy to 71 to 90% of all power generation, while also cutting power sector CO2 emissions by 72 to 91% below 2005 levels, both by 2030, the report says.

Supporting those figures will also require “over 24 TW-miles [terawatt-miles] of new long-distance transmission” to be deployed by 2030, “a 16% increase in total installed capacity compared to today,” the report says. Without it, wind power deployments could fall from providing 29% of U.S. electric generation to 22%, the report says.

Steven Rose, principal research economist at the Electric Power Research Institute, cautioned about the need to understand the assumptions built into different models, whatever the climate goals being advanced.

“There are typically fairly strong policy and technology assumptions behind those [goals],” Rose said in an interview with NetZero Insider. “Getting down to specifics of policies, as opposed to more stylized conditions that models tend to represent, one of the things I would highlight is that local opportunities [for climate action] are going to vary significantly. If we think about people in this country, we think about different parts of the country and what might be their opportunities for decarbonizing. … There’s no one-size-fits-all. …

“There are clearly options for mitigating climate change, but they’re not all equal,” said Rose, a review editor of the AR6 Synthesis and a lead writer on a previous IPCC report. “So, we need to think about how we’re going to try to facilitate and achieve decarbonization, recognizing that there are some tradeoffs that need to be recognized and considered … and balanced.”

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Study: Philadelphia Gas Infrastructure Costs Rise as Consumers Electrify

Philadelphia Gas Works must spend billions of dollars in the coming decades to replace old, leak-prone pipes as more customers are likely to switch to electric heating, according to a report released Monday by Boston-based nonprofit Home Efficiency Energy Team (HEET).

The report projects the utility will spend $6 billion to $8 billion replacing gas pipelines through 2058 — the date by which PGW aims to replace all cast iron mains, which tend to be the most leaky in its distribution system — with costs increasing 8.5% annually since 2015. Even with that investment, it’s likely that an additional 378 miles of currently leak-prone mains won’t be covered and an additional 379 miles installed during the 1970s and 80s will then be beyond their useful service life.

“It’s extremely likely that we’re going to get to 2058 and we’ll have a pile of vintage pipeline that hasn’t been replaced,” said Dorie Seavey, the HEET economist who wrote the report.

PGW did not return requests for comment on this article but did provide a statement on the report.

“The pursuit of carbon neutrality involves balancing the often-competing goals of safety, reliability, affordability and sustainability,” PGW spokesperson Richard Barnes said. “HEET’s use of data and analytics presents precisely the type of informed debate that is necessary to make progress. While the considerations and impacts we must weigh are broader than those of HEET’s study, we welcome and even pursue other perspectives and particularly expertise from other markets and geographic regions.”

The utility implemented an accelerated main replacement program in 2013, which funds additional replacements above the baseline of approximately 18 miles of gas mains per year, through a ratepayer surcharge, bringing total replacements to between 27 and 37 miles per year between 2016 and 2021. The report estimated that it would take an additional 10.5 miles per year to address all leak-prone pipes by 2058, which would add $1.7 billion to $2 billion to the overall cost.

PGW is also making significant investments in gas processing infrastructure, adding around $200 million to its five-year capital plan to make upgrades to its LNG equipment and to replace a liquefier at its Richmond plant.

Between rising infrastructure and fuel prices and the growing affordability of electrification for consumers, Seavey said, the rising cost of maintaining the gas infrastructure will likely fall on a shrinking number of customers. The report notes that Philadelphia has one of the highest rates of customers receiving assistance with their energy bills, effectively making PGW dependent on federal subsidies.

“The economics of gas is changing, and some degree of electrification is inevitable. To the extent that gas demand and throughput decline, and customers migrate to other thermal energy sources, then gas utility distribution spending will need to be recovered from fewer customers. Customers who don’t electrify, or are unable to (such as tenants and low-income households), will be left on an increasingly costly gas system,” the report says.

The 2058 goal could also put PGW in conflict with the city’s commitment to reach net-zero carbon emissions by 2050 should it continue using the infrastructure to deliver natural gas.

The report notes that PGW’s June 2021 Methane Reduction Report says the utility is exploring renewable natural gas (RNG) as an alternative fuel, but it also points to a December 2021 Business Diversification Study prepared for the company that says RNG could come with numerous downsides, including “limited available resources, high fuel costs and limited air quality improvements.”

Networked Geothermal Offers Alternative

HEET Codirector Audrey Schulman said thermal energy networks, which use piped water to deliver both heating and cooling, providing a sustainable option that avoids putting the burden of electrification directly onto consumers. The city council allocated $500,000 in PGW’s 2023 capital budget for a feasibility study on networked geothermal.

“Philadelphia has always been innovative in this area and thoughtful, and this is an opportunity for Philadelphia to move forward in an innovative way,” she said.

HEET has been involved in a networked geothermal installation in Framingham, Mass., which will provide air conditioning for a school, fire station, businesses and over 40 homes starting this summer. (See Nonprofit Plans River-source Geothermal in Eastern Mass.)

New York is also experimenting with the technology through the Utility Thermal Energy Network and Jobs Act of 2022, which permits utilities to install and operate the networks and requires larger utilities to submit pilot programs. (See NY Governor Signs Clean Building Codes, Thermal Networks Legislation.)

The HEET report also pointed to synchronizing clusters of electrified buildings with retiring gas infrastructure and using innovations in leak repair and monitoring to extend the lifespan of existing pipes.

“As PGW explores geothermal and other alternatives for Philadelphia, we look forward to partnering with HEET and other organizations to help crystalize the energy opportunities that lie ahead,” PGW’s Barnes said in the utility’s statement about the report.

Mitch Chanin, of POWER Philadelphia, an activist group that worked with HEET on the report, said his group is concerned about the public safety and environmental risk leaking gas mains pose within the city, noting there have been multiple explosions — some fatal — in recent years. The organization is pushing the city to consider several alternatives to natural gas, including thermal networks, energy efficiency, home retrofits and heat pumps.

Given PGW’s status as a public utility and its experience installing underground infrastructure throughout the city, the company is well-positioned to be at the forefront of any effort to install networked geothermal, Chanin said. Working at utility scale also comes with the prospect of lowering the cost of electrification for the city’s low-income residents and lessening the electric load impact of the shift.

“As we plan for the future of Philadelphia, this is really important, and we cannot achieve our city’s climate goals without shifts at PGW. We don’t have a plan yet that matches our goal,” he said.

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FERC Order May Delay MISO’s 1st Seasonal Capacity Auction

NEW ORLEANS — MISO may have to delay its first seasonal capacity auction after FERC issued a show-cause order Friday for the RTO’s capacity ratio that it must publish ahead of the auction.

FERC ordered MISO to either update an unforced capacity to intermediate seasonal accredited capacity ratio that it uses to gauge anticipated supply or explain why it shouldn’t have to. (See MISO Issued Show-cause on Seasonal Capacity Auction Values.)

Executives said this week the order will hinder MISO’s ability to conduct the seasonal auction on time.

Staff reported that a software error counted previously excused generation outages against capacity accreditation, resulting in smaller capacity values than expected. While they corrected individual ratios for multiple units, they did not update a summary systemwide ratio. The RTO said it didn’t have time to rework the systemwide data point before it conducts the 2023/24 planning resource auction.

“It will likely mean an ultimate delay in our auction,” Zak Joundi, director of resource adequacy coordination, told the Board of Directors’ Markets Committee Tuesday.

Joundi said MISO expects to publish auction results in mid-May, about a month behind schedule.

The four seasonal auctions that were to be conducted concurrently in early April are the grid operators first stab at using a seasonal capacity framework.

Joundi said FERC’s order was “hot off the presses” and that staff was still reviewing the commission’s directive. He acknowledged that members and staff might be disappointed by the delay, but the ratio must be recalculated.

“I understand that there are a lot of folks in the room that have done a lot of work,” he said.

“We’re going to comply with what FERC tells us and get this auction run as quickly as possible,” MISO Independent Market Monitor David Patton said.

Patton had alerted the RTO late last year that it was artificially inflating seasonal capacity requirements because it assumed generators on planned outages were offering capacity. (See IMM: Faulty Assumption in MISO’s Seasonal Auction Design.)

“A little bump in the road here, but you’re a leader in this area, and I commend you,” MISO director Tripp Doggett said, referencing the seasonal auction.

WEC Energy Group’s Chris Plante said the potential delay and revised ratio shows that the stakeholder community may have been justified in urging MISO to delay the auctions for a year and to use its normal annual method for the 2023/24 planning year.

“I think there’s a lesson to be learned here, and that’s stakeholders are experts in this process alongside MISO,” he said.

Staff used mounting reliability risks outside the summer peak as evidence that they needed to get a jump on dividing capacity contributions and requirements by season.

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PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF

PJM on Wednesday presented a preliminary proposal to overhaul its capacity market to the Resource Adequacy Senior Task Force.

The proposal aims to address the core reliability concerns the Board of Managers shared in its February letter invoking the Critical Issues Fast Path (CIFP) process. (See PJM Board Initiates Fast-track Process to Address Reliability.) A more formal package of specific revisions will be unveiled during the “stage one” CIFP meeting March 29.

PJM also presented the problem statement and issue charge laying out the RATF’s work. Under the issue charge’s roadmap, stakeholder proposals will be developed through the second stage, followed by their finalization in the third stage.

The RTO said its proposal would revise several market structures related to risk modeling, performance assessment and testing, resource accreditation and market power. The approach to risk modeling would shift to a reliability metric based on expected unserved energy (EUE), expand the dataset used with a longer historical lookback of 50 or more years, and consider temperature when modeling forced outages.

Walter-Graf-(FERC)-Content.jpgWalter Graf, PJM | FERC

PJM’s Walter Graf said the current methodology over-accredits certain resources compared to their contribution to the grid during high-stress periods, which results in the amount of capacity in the variable resource requirement curve being artificially inflated. This could lead to depressed clearing prices and a stronger retirement signal for some units.

The proposal suggests switching to marginal accreditation, though Graf said PJM is open to alternatives such as marginal reliability impact. It would also consider resources’ past availability throughout different weather and load patterns and would bring demand response into the effective load-carrying capability (ELCC) accreditation model.

To account for the most severe winter weather, PJM proposes to set more stringent winterization requirements above the minimums mandated by NERC. For resources that cannot meet those standards, two options were presented: to create a “winter disqualification” by which they would receive no obligation and compensation for the season, or an “annual disqualification” that would prohibit their participation in the capacity market outright.

Several stakeholders questioned how the greater consideration of seasonal weather would affect resources’ capacity ratings and whether the effort suggests a need for a seasonal product. Graf said PJM is envisioning an annual commitment with a seasonal differentiation mindset.

PJM is also considering four options for performance interval assessment (PAI) triggers, including maintaining the status quo, limiting triggers to exclude pre-emergency actions and warnings, during operating reserve shortages, and an amalgamation of the three that would include a minimum number of hours that would be assessed each year.

Pat Bruno of PJM said the second and third option would improve how PAIs reflect capacity emergencies and could incentivize more output, with the downfall of having fewer assessment hours. The fourth option would address that by expanding the hours looked at outside PAIs to include the hours with the tightest operating reserve margins to ensure that there are at least 30 assessment hours each year.

Part of the goal with the changes is to reflect the role PJM has in scheduling resources and potentially excuse those not dispatched from Capacity Performance penalties. Bruno gave the example of having an hourly baseline at night reflecting the lower output of solar resources to allow them to be exempt from penalties.

Stakeholders Pivot Proposals to CIFP

Several stakeholder packages already being drafted by the RASTF will also be reworked into the CIFP process.

Independent Market Monitor Joe Bowring presented an overview of the package he plans to bring before the group that centers on eliminating extreme penalties from the capacity market and focusing on incentivizing generators to perform during emergencies. It would define the amount of capacity a generator can offer as its installed capacity multiplied by its modified equivalent availability factor (EAF) and would only allow that capacity to be paid for when it is available by hour. He argued the approach would treat intermittent and thermal resources comparably and eliminate the asymmetric treatment created by PJM’s application of ELCC.

“The Capacity Performance design has strayed from the basic principles of a capacity market design by incorporating energy market shortage pricing in the capacity market through the PAI concept,” Bowring said. “That does not and cannot work as demonstrated by the experience of [December’s] Winter Storm Elliott. The goal of the IMM proposal is to return to capacity market basics and re-establish a workable capacity market design that does not create the type of administrative and settlements crisis created by Winter Storm Elliott.”

All generation would be subject to the must-offer requirement under the Monitor’s proposal, which would also require capacity resources to have firm fuel or dual fuel, and to test frequently.

Though he applauded PJM’s proposal to switch to marginal accreditation from the current average approach, Bowring also said he believes ELCC will provide incorrect market signals and prove impossible to implement as the marginal value of intermittent resources rapidly declines as penetration increases.

“You [will] come to the point where you have a relatively low capacity value, but your obligation remains at your full maximum facility output,” he said.

E-Cubed Policy Associates outlined a proposal that would use a multi-seasonal capacity market design, with overarching annual participation requirements, as well as sub-seasonal requisites. Sub-annual auctions would be held to procure capacity for the seasons, using a modified demand curve based on the amount cleared in the annual auctions. It would also utilize a unit-specific market seller offer cap, with no default values calculated by PJM.

A proposal from the Eastern Kentucky Power Cooperative (EKPC) would create two reserve target standards and an hourly accreditation model based on modeling installed capacity available during target conditions. Base level capacity would be based on expected hourly system needs under normal conditions and focus on maximizing availability. Insurance level capacity would be modeled on extreme load scenarios and qualified based on dispatchability, firm fuel and the ability to operate during extreme conditions.

The EKPC proposal also called for the stakeholders to consider changes to the energy market to address gas fuel security issues by allowing multiday commitments. The single largest cause of generator outages during Elliott, according to PJM presentations to the Market Implementation Committee, was fuel unavailability for gas generators, with one reason discussed being the multiday nomination process pipeline operators use not being aligned with the daily commitments used by PJM.

Auction Delay Discussion Continues

Stakeholders also continued discussions over whether future Base Residual Auctions should be delayed to allow any capacity market changes to be effective sooner. Two alternative auction schedules presented by PJM include keeping the 2025/26 BRA scheduled for June 2023 but delaying the following two auctions by sixth months, or delaying the 2025/26 auction to May 2024 and delaying the following three by sixth months. (See PJM Stakeholders Debate Capacity Auction Delays.)

Several state consumer advocates and regulators said they’re opposed to any delays, with Morris Schreim, senior adviser to the Maryland Public Service Commission, saying it could be the first time PJM has sought a delay not related to a FERC remand or action, suggesting that auction parameters were not just and reasonable.

“This would really be … the first time PJM ever on its own volition purposely delayed an auction,” he said.

LS Power’s Marji Philips supported delaying the 2025/26 auction, which she said is necessary to ensure fair price signals that will keep resources needed for reliability from retiring early. She said that rather than asking stakeholders for guidance, PJM should be taking leadership and pushing for a delay itself.

“The idea that resources will continue to come in and stay on the system and maintain reliability … is not a well grounded financial analysis of how plant owners participate in the market,” she said.

Bowring opposed delaying the auctions, noting that most of the required work in preparing for the 2025/26 auction had already been completed by resource owners and the IMM. He also responded to assertions that capacity market prices are too low and that auction delays will permit a design with higher prices.

“Capacity market prices are not too low and they are not too high. Generation owners offered the prices they wanted for the period of Winter Storm Elliott, without any effective market power mitigation, and the market clearing prices reflect those offers. Total energy, ancillary services and capacity market net revenues are what matters. Energy market net revenues have increased significantly, and resources are generally covering their avoidable costs. See the State of the Market Report for the details,” he said. (See PJM Monitor: Rise in Fuel Costs Led to Record-high Prices in 2022.)

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SERC LTRA Notes Challenges from IBRs, DERs

SERC Reliability sounded a note of confidence in its Long-Term Reliability Assessment (LTRA), released this month, predicting that planning reserve margins in most of its subregions will be more than enough to meet demand over the next 10 years.

However, the regional entity also noted the ongoing changes to the electric grid’s generation mix and growing stresses from extreme weather, and warned that system operators must be prepared for rapidly changing circumstances to maintain reliability.

DER Growth to Offset Demand 

The LTRA is based on data collected from registered entities in SERC’s seven subregions and is intended to identify “trends, emerging issues, and potential risks” over the 2022-2031 assessment period. Some of the data was also provided to NERC for the ERO-wide LTRA last year, in which SERC was one of the few regions where none of the footprint was assessed as facing high or elevated risk of energy shortfalls. (See NERC Warns of Ongoing Extreme Weather Risks.) SERC said some of the data in the new report “reflects further updates … since the release of the NERC report.”

SERC’s report projected “almost flat” demand across the territory until 2031, with nearly all its subregions expecting average annual load growth of less than 1%. The outlier is SERC PJM, which includes all or parts of North Carolina, Virginia and Kentucky, where load is projected to grow 2.17% annually from 2022-2031.

However, the RE specified that it does expect electricity demand to grow despite slow expansion in net load thanks to factors like electrification of transportation and the anticipated switch to electric residential heating — which will also help turn some subregions from summer- to winter-peaking.

SERC said the demand growth will likely be offset by adoption of rooftop solar panels and other distributed energy resources (DER) that “mask the residential load on the system” — a phenomenon that experts have been warning about for years. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)

The RE noted DERs as a particular issue in the SERC East subregion, comprising South Carolina and most of North Carolina, and SERC Central, which includes all or parts of Alabama, Georgia, Iowa, Kentucky, Mississippi, Missouri, North Carolina, Oklahoma, Tennessee and Virginia. In both subregions SERC said entities must work to adjust their system models to account for the role of DERs in absorbing residential demand.

All subregions except the MISO-Central area — which includes all or parts of Iowa, Kentucky, Missouri and Illinois — expect to have enough resources to meet their prospective reserve margins through 2031. In MISO-Central, a summer-peaking area, entities are projected to fall short of the 15% summer reference reserve margin in every year through 2031 because of planned generation retirements, mostly among coal plants. However, SERC observed that the subregion “has access to additional firm deliverable resources up to the MISO regional directional transfer limit.”

More Work Needed on IBRs

The region’s ongoing move from thermal resources to renewables garnered a separate section in the report, with SERC noting that “many states and utilities … have established, or have proposals to establish, carbon reduction goals and promote the integration of greater levels of renewable resources such as solar, wind and battery energy storage.”

Because of these resources’ variable energy output, they rely on inverters to connect to the grid. As with DERs, this creates difficulties in modeling because these inverter-based resources (IBR) do not behave the same way as traditional resources. Like NERC and other REs, SERC expects this problem to grow in importance as the penetration of IBRs on the grid continues.

“Even as industry experience grows, and as effective modeling and engineering study techniques are developed into guidelines and reliability standards to meet these challenges, IBR commissioning practices for utilities remain an area of challenge and are still to be addressed,” the report said.

It highlighted two documents produced by SERC’s Variable Energy Resource Working Group — the SERC Guidance Document for IBR Commissioning Process and the SERC Guidance Document for IBR Interconnection Practices — as valuable resources for registered entities to update their practices. Both documents are available upon request through the SERC website.

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SPP Unveils Markets+ Governance Structure

SPP last week rolled out the governance structure that will oversee the first developmental phase of Markets+, the RTO’s day-ahead and real-time market in the Western Interconnection.

The RTO said Markets+ will provide “fully independent governance” from day one and give Western stakeholders a “meaningful say” in the market’s implementation.

Antoine Lucas, SPP’s vice president of markets who is responsible for overseeing the Markets+ launch, said the grid operator has always relied on the “integrity” of its governance model.

“The model designed to govern Markets+ builds on that legacy of success,” he said in a statement. “It will ensure stakeholders from across the Western Interconnection … all have a voice in the design, development and administration of Markets+.”

Staff shared further details of the governance model during a webinar last Thursday. Developed last year with western stakeholders, it is essentially the same process found in SPP’s final service offering for Markets+. The model will be used to develop tariff language, protocols and governing documents in a package to be approved by stakeholders and filed with FERC. (See SPP Issues Final Markets+ Proposal.)

SPP Director Steve Wright likened it to the final service offering to Markets+’s constitution.

“We’ll be seeking to act consistently with that. It really does set the roles and responsibilities for all of the governance,” Wright said during the webinar.

Wright will chair the Interim Markets+ Independent Panel (IMIP), which will provide independent oversight and the top level of decision making during the market’s first developmental phase. He will be joined by fellow independent directors Elizabeth Moore and John Cupparo. Any actions taken by a simple majority on Markets+ tariff language will be presented to the full SPP board and filed with FERC.

Wright, a former Bonneville Power Administration administrator and CEO of Washington’s Chelan Public Utility, and Cupparo, a former senior executive at Berkshire Hathaway Energy and WECC board member, bring extensive experience in the Western Interconnection.

“I encourage folks to embrace this opportunity, and I really look forward to moving through this process as quickly as the stakeholders would like,” Cupparo said.

“Technically, if there are disputes, they could come to the IMIP for resolution,” Wright said. “We would certainly hope and encourage that there will be no disputes that we would need to resolve. We really would like to see folks in the West deciding how they want this thing to be put together in establishing their own leadership, and that we are merely providing support for that.

“I want to really emphasize this is your market design, not SPP’s market design. You have the ability to define how this will go,” he said. “Our role is to try to manage the process in a way to make sure that you get to the substantive outcomes that you want. We’ll certainly be encouraging collaborative discussions that lead to decisions driven by Western stakeholders and not driven by the IMIP.”

MIP, IMIP, MSC and MPEC

The Markets+ Independent Panel (MIP), a five-member panel independent from Markets+ participants and stakeholders, will eventually be established and replace the IMIP for the market’s second phase of development.

SPP staff had originally intended to stand up the MIP for the first phase, but stakeholders indicated they preferred a truly independent board, SPP General Counsel Paul Suskie said. More than two dozen participating organizations provided comments during the process.

The IMIP — and eventually the MIP — will oversee a structure that includes a Markets+ State Committee (MSC), a Markets+ Participants Executive Committee (MPEC), and multiple working groups and task forces, including the Market Design and Seams working groups and the Greenhouse Gas Task Force.

The MSC will be comprised of regulators from each state in the Markets+ footprint: Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming. The group is designed to advise the MIP, MPEC and working groups on policy issues and initiative prioritization.

Eric Blank, chair of the Colorado Public Utilities Commission, is leading the effort with the Western Interstate Energy Board to draft the MSC’s charter and formation efforts. Blank and SPP staff will update the board on Markets+ and the MSC during a Thursday webinar.

The MPEC offers a forum for Markets+ market participants and stakeholders to discuss issues related to the market’s administration and advancement, including establishing working groups, proposing tariff amendments and administrative rate changes. SPP staff is drafting charters that include each group’s purpose, scope and representation; they will be reviewed and voted on during the committee’s first meeting April 18-19 in Westminster, Colorado.

MPEC meetings are open to all stakeholders, but only entities that execute a market participant Phase One funding agreement or a stakeholder Phase One participation agreement are eligible to appoint a representative to the committee.

Markets+ has attracted 10 participants and several stakeholder groups, including the American Clean Power Association, The Energy Authority and Western Resource Advocates.

Western stakeholders and SPP staff spent more than nine months developing the governance structure. Staff said that having reached a critical mass threshold for Markets+ participation earlier this year, it has executed additional funding agreements. (See SPP Moving Quickly on Markets+’s Development.)

“From the overall board’s perspective, we are very encouraged by the commitment to the funding agreements and rapidity with which they were put in place,” Wright said. “It has certainly caused us to accelerate all of our activities, including pushing forward the establishment of this governance structure and the establishment of the IMIP.”

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Enviros Demand NJ Move Faster on 100% EV Rule

Supporters of New Jersey’s efforts to adopt California’s Advanced Clean Cars II (ACC II) rule on Monday urged state officials to move faster, saying the state lags others and is in danger of missing the crucial year-end deadline to enable the rule to cover 2027 vehicles.

More than two dozen speakers testified at a hearing held to outline the process for adopting ACC II; most were in favor of the proposal. New Jersey Department of Environmental Protection (DEP) officials were seeking input on whether the state should advance on adopting the rules. Supporters said because New Jersey is following California’s model, it has little flexibility in changing the rules, which would have to be adopted almost wholly or not at all.

“Our goal is to adopt by the end of the year, so that we can capture model year 2027,” Peg Hanna, assistant director, air monitoring and mobile sources for the DEP, said at the meeting. “But that is an extremely ambitious time frame for us to propose and adopt a rule.”

Most of the speakers said the state needed to make it happen to quickly reduce pollution, reap the economic benefits of jump-starting a new market and to compete with other states.

“The climate emergency demands it, and we’re so behind,” said David Pringle, a steering committee member of Empower New Jersey, noting that some states adopted the rules in time for model year 2026.  “We’re not a leader of the pack here. We’re behind the pack, and we have to catch up.”

Kit Kennedy, managing director of the climate and clean energy program at Natural Resources Defense Council, said the rules are key to helping slow the worsening impacts of climate change on the state, such as those from Superstorm Sandy in 2012.

“The transportation sector is the largest emitter of greenhouse gas emissions in the country and in New Jersey,” he said. “Zeroing out pollution from this sector will help to improve air quality and health while saving drivers money and reducing pain at the pump.”

The sole opposing voice at the hearing, Eric Blomgren, chief administrator and director of government for the New Jersey Gasoline, Convenience Store, Automotive Association (NJGCA), decried the rules. He said it is “fundamentally unfair” for the state to deny consumers the option to use gasoline vehicles.

“A transition should be done entirely through incentives to consumers, through free citizens making the choice themselves based on what makes sense for their life, their family and for their budget,” he said. He called the rules a “full government ban of a product which currently makes up 95% of the new sales market.”

Asked what prevented the state from moving swiftly, Hanna said it was a question of “internal prioritization” within the DEP, with the agency trying to adopt several different policies with limited administrative resources, some of which must be used to meet federal deadlines.

“It really is a balancing act,” she said, adding that “it remains our goal to adopt by the end of the year.”

Alex Ambrose, transportation and climate policy analyst at liberal think tank New Jersey Policy Perspective, urged the state to adopt the rules by April.

“Trying to reach these the goals that our state has set out without this rule in place for this year is like fighting with one hand tied behind our back, and we are sabotaging ourselves,” she said. “We’re like an out-of-state driver that is stuck in the left lane right now while other states are zooming past us towards the cleaner and healthier future.”

Ascending Sales Limits 

About 90,000 EVs are registered in New Jersey, a small fraction of the 6 million light-duty vehicles on the road, but a big jump up from approximately 30,000 EVs in the state at the end of 2019.

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 shows that New Jersey will reach 7.5 million EVs on the road by 2050 if the rules are enacted, and just 1.3 million EVs on the road if it isn’t, according to a presentation made at the meeting.

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

Oregon, Washington, Vermont, Virginia, New York and Massachusetts have followed suit in adopting the rules, while Delaware, Colorado, Washington, D.C., and Connecticut are considering doing the same. On Monday, Maryland said it would fast-track adoption of the rules. (See Maryland to Adopt California’s Advanced Clean Cars II Rule.)

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 sold in a state.

Not all clean vehicles qualify under the rules, however. EVs must have a range of at least 200 miles, and plug in hybrids must be able to drive at least 70 miles on a charge, said Rob Schell, DEP’s supervising environmental specialist. The vehicles also must include an onboard charger of 5.76 kW or higher that can charge the vehicle in four hours or less, and be equipped to plug into DC fast charging ports.

Creating Market Certainty 

Tom Van Heeke, senior policy advisor for EV manufacturer Rivian, said passing the rules before year’s end is crucial not only for “achieving climate goals and achieving prescribed emissions reductions targets but also for investment certainty and planning both within the auto industry and then in sort of adjacent industries.”

“One of the core purposes of the rule is to provide a clear, well-understood glide slope that everyone can build and plan around in their businesses,” he said.

Eve Gabel-Frank, speaking for ChargEVC, a research organization and coalition of advocates that promotes EV use, said that even with 90,000 EVs on the road, the state is far away from its 2025 goal of 330,000 and the adoption of ACC II is key to reaching the goal by providing a signal to EV manufacturers.

“The reality of this is manufacturers are going to prioritize supply of EVs to the ACC II states,” she said. “So, if we don’t adopt [the rule], New Jersey drivers will either go without EVs, or be forced to travel to neighboring states to purchase the vehicles they want, which also has the added negative effect of moving economic activity out of the state.”

Preparing To Transition

That need to plan and prepare was echoed in a recent report by the New Jersey Coalition of Automotive Retailers, which found that the market sector still needs preparation for the rapid transition from gasoline and diesel vehicles to EVs.

In a study conducted in September and just released, the organization surveyed its members to learn what car manufacturers are requiring franchise auto dealers to complete, install or purchase to “prepare their dealerships for the EV revolution to come.”

“New Jersey’s electrification process will take years, if not a decade to really pick up momentum,” the report said. “Most manufacturers have committed themselves to being all or mostly electric in a few decades. While dealers support electrification and stand ready to invest in EV infrastructure, they are reluctant to invest too much too soon while there is limited availability on product, in addition to the sheer cost of electrification.”  

The report said dealers expect to spend $151 million on preparing for greater EV adoption by consumers, and most manufacturers have a plan to electrify their franchises within the next 15 to 20 years. Twenty-seven out of 33 dealerships in the survey said they have started or are starting the EV process, the report found.

“The biggest obstacle to electrification facing the dealership body is electricity itself,” the report concluded, saying that the organization should conduct another study in a year.

“Dealership principals from a wide variety of brands expressed concern about whether there is currently enough power or electrical infrastructure to accommodate every automobile franchise in the state, or enough infrastructure to support home chargers for customers, which several principals also expressed concern over.

The concern for some centered on the cost of the electrical upgrades and the timeline for electric companies to install those upgrades,” the report found.