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November 9, 2024

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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.

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EPA Poised to Approve California Clean Truck Rules, Report Says

Good news is reportedly on the way to the California Air Resources Board regarding federal approval for its Advanced Clean Trucks regulation, which will require manufacturers to sell an increasing percentage of zero-emission trucks each year.

The Washington Post reported on Monday that the EPA has decided to grant waivers to CARB for Advanced Clean Trucks and two other regulations. The Post cited three unnamed sources who had been briefed on the plans.

As of Monday, EPA hadn’t made a formal announcement on the waivers.

CARB needs the EPA waivers because vehicle emission standards in the three regulations differ from federal standards. Under the federal Clean Air Act, a waiver may be issued if California’s standards are at least as stringent as federal standards. The state must receive the EPA waiver before it may enforce the rule.

The zero-emission sales requirements of Advanced Clean Trucks, which apply to medium- and heavy-duty vehicles sold in the state, are scheduled to take effect in 2024.

The waiver decision also has implications for other states that have adopted California’s Advanced Clean Trucks rule. Those include Washington, Oregon, New York, New Jersey, Massachusetts and Vermont.

An EPA spokesperson didn’t answer a question from NetZero Insider on Monday regarding whether the agency had decided to approve the waivers. She also didn’t specify when a decision would be made.

“EPA is working to issue its decisions on the waivers before us as expeditiously as possible,” the spokesperson said in an email.

A CARB spokesperson on Monday referred questions to the EPA, saying that CARB is “not aware of anything new on this.”

Monday’s news follows a report last year saying that EPA was considering a partial denial of the waiver for Advanced Clean Trucks that would impact the regulation’s first few years. That news report also cited an unnamed source. (See CARB Awaits EPA Decision on Advanced Clean Trucks Rule.)

EPA told NetZero Insider at the time that it was just getting started on the process for reviewing the waiver requests. EPA published an initial notice regarding the waivers in June, followed by a public hearing later that month. The deadline for written public comment was Aug. 2.

The Post reported that approval of the waivers was planned for earlier this month but was delayed because of “last-minute complications.”

The zero-emission sales requirements in Advanced Clean Trucks are based on vehicle classification. For Class 2b and 3 trucks, such as step vans and city delivery trucks, the rule requires 5% ZEV sales in 2024, increasing to 55% in 2035. ZEV sales requirements for Class 7 and 8 tractors range from 5% in 2024 to 40% in 2035.

In addition to Advanced Clean Trucks, CARB is awaiting an EPA waiver for the Heavy-Duty Low NOx Omnibus Regulation, which aims to reduce emissions of nitrogen oxides from trucks. A waiver is also pending for an amended emission warranty regulation that extends emissions warranty periods for heavy-duty diesel trucks in model years 2022 and later.

The waiver discussion comes as CARB is poised to approve another zero-emission truck regulation, Advanced Clean Fleets. The regulation would cover three types of fleets: drayage, state and local, and fleets deemed high priority. The regulation would require some or all new trucks added to the fleets to be zero-emission starting in January 2024. (See CARB Examining Obstacles on Road to ZEV Fleet Adoption.)

The regulation may go to the CARB board for final approval as soon as next month.

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FERC Dismisses Complaint over Con Ed Wholesale Distribution Rate

FERC on Thursday denied a New York company’s complaint against Consolidated Edison (NYSE:ED), saying it did not provide any evidence that the utility’s wholesale distribution service (WDS) rate was unjust or unreasonable (EL23-8).

There is little information online about the company, called Cubit Power One. According to an application filed with the New York City Industrial Development Agency in 2014, it is a special-purpose entity created “to develop green manufacturing facilities” seeking to build an “energy-efficient packaged ice manufacturing facility with on-site power generation” on Staten Island, with plans to eventually turn it into the city’s first carbon-capture plant. Its listed website is defunct.

That on-site generator, an 11-MW combined heat and power unit, was at the center of Cubit’s complaint. It told FERC that revisions Con Ed proposed making to its WDS rate in response to a New York Public Service Commission proceeding would severely reduce the income the company received from selling the unit’s extra power onto the grid.

The WDS rate is based on electric distribution companies’ average retail standby service rates, which are charged for the delivery of replacement energy that would normally be produced by distributed generators.

The New York PSC last March adopted a new cost allocation methodology for standby rates to “more accurately align individual customers’ contribution to system costs with the rates such customers pay, thereby sending improved price signals to those customers.” It required EDCs to submit revised standby and buyback rates (15-E-0751).

Con Ed’s current WDS rate is $7.59/kW/month and is charged when the amount being sold is over 1,500 kW. Cubit alleged that the new rate as a result of the PSC proceeding could be less than $0.20/kW/month. It argued that the new rate would allow Con Ed to “recover costs well in excess of Con Ed’s own cost of service.” Cubit also claimed that a Con Ed employee had sent an email saying the new rate would be $2.29/kW/month.

In response, Con Ed said that Cubit failed to include a later message from the email chain, which said that assumption was subject to change based on the PSC proceeding.

“Cubit’s arguments are based on conjectures regarding what may ultimately happen in the New York commission rate proceeding,” FERC said. The proposed rates submitted as part of that proceeding “are subject to change at any time.”

FERC noted that Con Ed will file an updated WDS rate once the PSC proceeding is completed, at which time it will determine whether it is just and reasonable.

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FERC Refuses Rehearing of PG&E-San Francisco Dispute

FERC on Thursday denied Pacific Gas and Electric’s request for rehearing in a case that has pitted the utility against the city and county of San Francisco for more than 18 years over PG&E’s application of its wholesale distribution tariff (WDT) to the municipal customers of San Francisco’s public utility (EL15-3-005, EL5-704-027).

The utility, the San Francisco Public Utilities Commission (SFPUC), operates a hydroelectric power project in the Hetch Hetchy Valley, near Yosemite National Park, and owns transmission lines that bring power from the Sierra Nevada to San Francisco.

It supplies electricity to schools, public housing tenants, libraries and municipal departments using the distribution system PG&E owns and operates in San Francisco — making the publicly owned utility both a customer and competitor of PG&E.

Since 2014, San Francisco has argued to FERC that PG&E has unreasonably denied distribution service to many of its 2,200 metered interconnection points under section 212(h) of the Federal Power Act.

The section prohibits mandatory retail wheeling such as forcing PG&E to deliver another utility’s power through its distribution lines. But it exempts cities and counties where “such entity was providing electric service to such ultimate consumer on the date of enactment of this subsection [Oct. 24, 1992].”

A FERC administrative law judge issued an initial decision in November 2016 that supported San Francisco’s argument. It cited the commission’s orders under Suffolk County Electric Agency (96 FERC ¶ 61,349) from November 2001. In that line of decisions, known as Suffolk I-IV, FERC said section 212(h) grandfathered classes of customers, not individual customers at specific delivery points.

“The Commission’s orders and opinions … support San Francisco’s argument that grandfathering applies to the class of customers that was eligible to receive wholesale distribution service on October 24, 1992, regardless of where in the city those customers may be located now or in the future,” the ALJ wrote. The judge defined the “class” of customers in the case as all “municipal public purpose load” in San Francisco.

PG&E, in contrast, contended that only “points of delivery” that existed prior to Oct. 24, 1992, could be grandfathered under its WDT. Customers that had relocated since that time were ineligible, it said.

FERC Overturned

In a November 2019 order, FERC disagreed with the ALJ’s decision. It found the Suffolk precedent inapplicable and said PG&E had not unreasonably denied service to some of San Francisco’s end users.

“The commission explained that San Francisco’s ‘class of customer’ approach would entitle all municipal public purpose load as designated by San Francisco that was eligible to receive wholesale distribution service on October 24, 1992,” FERC explained in Thursday’s order. “Ultimately, the commission concluded … that PG&E’s point of delivery approach to determining which San Francisco customers qualify for service under the WDT was just.”

The D.C. Circuit Court of Appeals reversed FERC’s decision in January 2022. It found that FERC’s interpretation of section 212(h) and PG&E’s tariff were too narrow, and its “attempts to defend its interpretation [were] unpersuasive.”

“That the tariff references ‘points of delivery’ does not necessarily imply that only specific points of delivery may be grandfathered, and those references to ‘points of delivery’ do not change the fact that the tariff expressly references the criteria of Section 212(h)(2),” it said.

The court criticized FERC’s orders in the case as demonstrating a “troubling pattern of inattentiveness to potential anticompetitive effects of PG&E’s administration of its open-access tariff.” Faced with claims that PG&E was refusing service to San Francisco customers, FERC “fell short of meeting its duty to ensure that rules or practices affecting wholesale rates are just and reasonable,” it said.

The appeals court sent the case back to FERC on remand. (See San Francisco Wins Against PG&E, FERC in DC Circuit.)

FERC issued a new decision in October that followed the court’s direction and agreed with San Francisco that its precedent did not limit grandfathering to a fixed location.

“The commission concluded that San Francisco’s loads within the customer classes served on October 24, 1992, are entitled to grandfathered service under the WDT, granted the complaint filed by San Francisco, and directed PG&E to submit revised WDT provisions,” FERC noted Thursday.

PG&E requested a rehearing.

PG&E Denied

In its request, “PG&E argues that the commission in the order on remand exceeded [its] authority in FPA section 212(h),” FERC noted. “PG&E urges the commission to set aside Suffolk County because, according to PG&E, the Suffolk County customer-class approach to grandfathering is inconsistent with the plain language of the statute, the intent of the statute in its legislative history, and the concept of grandfathering.”

PG&E also contended that “even assuming Suffolk County is valid and applicable precedent, the commission in the order on remand failed to address the potential for harmonizing PG&E’s proposed delivery-point methodology with the Suffolk County customer-class approach.”

FERC rejected PG&E’s arguments.

“PG&E asserts that the ‘customer-class approach’ can be reconciled with grandfathering based on points of delivery to provide service to a specific type of customer within a defined service area, because limiting grandfathering eligibility does not conflict with the text or intent of section 212(h),” FERC said.

But “in the order on remand, and as further discussed here, the commission has defined a coherent class of San Francisco customers eligible for grandfathering,” FERC said. “As the D.C. Circuit explained, the WDT ‘allows grandfathering of a customer San Francisco served under the prior interconnection agreement even though the customer seeks [WDT] service at a new delivery point.’

“Consistent with Suffolk County, eligibility under FPA section 212(h) therefore extends not only to the customers who were actually receiving service on October 24, 1992, but also to all subsequently interconnected customers of the same class.”

Second Case

In its January 2022 decision, cited above, the D.C. Circuit reversed FERC in a second case involving PG&E’s provision of distribution service in San Francisco.

In that case, the city and county contested PG&E’s refusal to provide lower-voltage secondary service to many sites within the city. PG&E instead offered to connect higher-voltage primary service, which requires the installation of transformers and carries higher fixed costs for ratepayers.

The city argued that the practice violated PG&E’s WDT.

The court remanded the matter back to FERC after overturning the commission’s unanimous 2020 decision rejecting San Francisco’s complaint.

In December, FERC ordered settlement judge procedures for the then three-year-old dispute. (See Settlement Hearing Ordered for PG&E, SF Distribution Dispute.)

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New York PSC Approves 20% Installed Reserve Margin

The New York Public Service Commission on Thursday approved a slight increase to the amount of reserve resources that load-serving entities must have available for the upcoming capability year (07-E-0088).

The New York State Reliability Council (NYSRC) had in December proposed raising the installed reserve margin from 19.6% to 20% for the 2023/24 capability year, which begins May 1 (05-E-1180). The figure equates to an installed capacity requirement of 120% of forecasted peak load for the year.

The council told the PSC it based its decision on the addition of 549.3 MW of wind generation and the need to maintain 350 MW of operating reserves during load shedding. It calculated the figure using the GE MARS system to examine factors such as demand uncertainty and scheduled or forced outages to establish a value above forecasted peak such that the loss-of-load expectation from resource deficiencies is fewer than 0.1 event days per year on average.

NYISO supported the proposal, as its own analyses yielded an IRM of 19.9%; 20% was “within a range of reasonable IRM levels that will maintain reliability.”

The PSC also said that the adopted IRM will “not have a significant adverse impact on the environment.”

The NYSRC will re-evaluate the IRM before the end of the year and submit another value should conditions change.