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November 12, 2024

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ISO-NE Recommends Delaying FCA 19

ISO-NE is recommending a one-year delay of Forward Capacity Auction 19 (FCA 19) to implement resource capacity accreditation (RCA) changes and determine whether to move to a prompt and seasonal capacity market, the RTO told the NEPOOL Markets Committee on Tuesday.

Since June, the RTO has been taking stakeholder feedback on the best path forward for FCA 19 following a delay caused by a software issue in the RCA process, as well as on a potential move to a prompt and/or seasonal market. (See NEPOOL Debates Options for FCA 19.) FCA 19, scheduled for February 2025, corresponds with Capacity Commitment Period 19 (CCP 19), which runs from 2028 to 2029.

After laying out a series of options in previous meetings, ISO-NE endorsed “option 2A,” which would provide some extra time to finish the RCA process for FCA 19 and further discuss the merits of capacity market changes.

Chris Geissler of ISO-NE said this option “recognizes the importance of simultaneously implementing a revised capacity accreditation framework that coincides with the elimination of the minimum offer price rule (MOPR) for FCA 19.”

The RCA project is intended help the organization “more accurately reflect resource contributions to resource adequacy.” ISO-NE has expressed its desire to time the implementation of these changes with the scheduled elimination of the MOPR. (See FERC Accepts ISO-NE’s MOPR Transition Plan.)

“While some stakeholders prefer maintaining the status quo (FCA 19 without RCA), the ISO is concerned it may not adequately prepare the region for the changing resource mix and expected clean energy system,” Geissler said.

Clean Energy Stakeholders Weigh in

A range of clean energy stakeholders outlined questions, comments and concerns about the potential capacity market changes. The comments highlight the lack of consensus among various renewable energy groups, along with uncertainty about how a prompt seasonal market would affect resources.

Deepwater Wind Block Island, a subsidiary of Ørsted, supported implementing RCA changes and moving to a prompt and seasonal capacity market for CCP 19, writing that the move would limit uncertainty for long-term investments while helping reliability. The company added that ISO-NE’s preliminary analysis of the RCA design indicated it would enable offshore wind resources to clear more capacity.

“The combination of incorporating RCA and the removal of the MOPR in CCP 19 will enable offshore wind resources the opportunity to compete with other existing resources on a more even playing field,” wrote Eric Wilkinson of Ørsted. “Ratepayers will benefit from these changes by increasing the amount of capacity being provided from clean energy resources.”

In contrast, representatives of New Leaf Energy and SYSO Inc. expressed their opposition to delaying the auction and supported holding it under the current rules without RCA changes. The companies argued that any delay of the auction would introduce uncertainty and hurt new resources looking to connect to the grid, because new generators rely on the forward capacity market to secure capacity rights.

“Postponing the FCA without a replacement process for generators to secure these rights will prevent new resources from knowing whether they can access the capacity market, threatening the financial viability of these projects, as well as the pace of the clean energy transition,” the memo said.

The companies added that delaying the auction could lead to a backlog of projects in the interconnection queue once a new process is implemented.

ISO-NE told the Markets Committee it might need to separate the interconnection process from the capacity market to comply with FERC Order 2023 no matter which capacity market design ultimately is chosen (RM22-14). (See FERC Updates Interconnection Queue Process with Order 2023.)

“To address FERC Order 2023, the ISO will be required to migrate to a single annual cluster process, with equal queue positions and shared upgrade cost allocation within the cluster, for studying new interconnections,” ISO-NE noted.

In an August letter to ISO-NE, Advanced Energy United, which advocates for clean energy policies on behalf of its member companies, wrote that there are significant “information gaps” surrounding the effects of ISO-NE’s stated options for CCP 19 on new resources, retirements, the RCA process and subsequent capacity commitment periods.

“We do not feel stakeholders can make informed decisions without further explanation addressing these information gaps,” Advanced Energy United wrote. “While we appreciate the time constraints driving ISO to move quickly to land on a preferred path forward, we believe the significance of the decision necessitates a fulsome exploration of the implications of each pathway, and we are not yet satisfied that ISO-NE and NEPOOL have completed such an exploration.”

Aleks Mitreski of Brookfield Renewables expressed concerns in a presentation to the Markets Committee on Tuesday relating to the entry and exit of resources, along with transmission upgrades. Mitreski added that some of the issues with the forward capacity market likely could be fixed without overhauling the entire market design.

Next Steps

ISO-NE proposed making an initial FERC filing by the end of this year to delay the auction, followed by another filing next year to either finalize the one-year delay including the RCA changes or to create a new schedule to implement a prompt auction for FCA-19, which would be held in 2028.

ISO-NE will present the detailed tariff revisions at the October MC meeting, followed by a November MC vote and a Participants Committee vote in December.

Also at the October MC meeting, ISO-NE will resume discussion on the RCA proposal, which likely will extend into next year. The RTO is targeting an August 2024 vote on the proposal.

ISO-NE also has commissioned the Analysis Group to conduct a qualitative and quantitative analysis of the potential effects of moving to a prompt and/or seasonal market. The consulting firm will need to work on a tight schedule, as ISO-NE expects it to present to the MC the scope of its work in October, the methodology in November and results in December.

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NW Stakeholders Divided on BPA Timeline for Day-ahead Decision

Northwest electricity sector stakeholders this week expressed divisions over the Bonneville Power Administration’s plan to pursue an aggressive timeline for deciding whether to join CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+.

BPA’s decision will carry significant weight in the Northwest, where the federal power marketing agency controls more than 22 GW of mostly hydroelectric generation, operates 70% of the transmission grid and serves dozens of large customers, including the region’s extensive network of publicly owned utilities.

Its choice also could influence the decisions of system operators elsewhere in the West. Supporters of the accelerated timeline seem to be hoping for such an outcome, not only to boost the clout of BPA but of the Northwest in general.

“We’ve been followers for far too long, and we actually have a chance here to be a leader — and, yes, that means sticking our neck out there a little bit,” Shawn Smith, managing director of energy resources at Chelan County (Wash.) Public Utility District, said Monday at a BPA public workshop to discuss the day-ahead market decision. Smith was referring to a view shared by many in the region that public power entities became involved in CAISO’s Western Energy Imbalance Market (WEIM) too late to hold much sway in its initial development.

“I think it’s really important for BPA to come out and express where they’re leaning [in] Q1 of next year,” said Laura Trolese, director of Western markets strategy at The Energy Authority, which provides energy market services to public power entities.

Trolese noted the region is facing a wave of changes related to resource adequacy, state climate policies and organized electricity markets.

“It’s moving at a pace that we’ve never seen, but we have to start making decisions and move forward with all of the uncertainty and figure things out as we go. We just can’t wait for everything to be figured out before BPA makes a decision,” she said. “At that point, there’s no decision to make, so I really appreciate these guys stepping up and starting this process.”

Michael Linn, director of market analytics at the Public Power Council, acknowledged that SPP has not yet completed a Markets+ tariff and many issues related to the initiative remain outstanding. (The RTO expects to file with FERC in early 2024.)

“But we know about governance; we know about some price formation. And, frankly, the way Bonneville signals or leans may ultimately kind of determine a path forward for either of these markets,” Linn said. “So I think it’s important to acknowledge that … indecision at this point is a decision and it almost is a forfeiture of our leverage as a region [that has] a lot of transmission and hydropower.”

‘Crucially Important’

Other meeting participants questioned the need for such speed.

Speaking on behalf of the Western Public Agencies Group, which represents Oregon and Washington public utilities involved in BPA proceedings, Lea Fisher contended that BPA’s process for joining the WEIM and the Western Power Pool’s Western Resource Adequacy Program (WRAP) seemed more “substantive” than the process envisioned for choosing a day-ahead market. Fisher pointed out that BPA has proposed a seven-month process consisting of five workshops, compared with a 14-month process with 10 workshops for the WRAP and a five-phase, three-year process for joining the WEIM.

“You can see how the process BPA has currently outlined for the decision to join a day-ahead market seems light in comparison,” she said, asking whether there would be another “follow-on” process after the agency made its determination.

Matt Hayes, BPA program manager and policy analyst, said the seventh-month process would be “analogous” to the agency’s initial process for deciding to join the WEIM, which would be followed by a “much longer” process related to implementation.

But chief among the skeptics of BPA’s timeline was Fred Heutte, senior policy associate with the Northwest Energy Coalition (NWEC), who said the “big question” was the uncertainty around FERC’s responses to the EDAM and Markets+ tariff filings. Heutte said the EDAM filing was “very complete,” but took five years to put together, while “much, much less time” has been spent on developing Markets+.

“And it’s really evident sitting in some — not all — of the Markets+ meetings, that there are a lot of key pieces that haven’t yet been hammered down,” he said, adding that NWEC is “feeling a bit of unease about the schedule.”

“I think you’re just articulating the challenge and sort of the misery of what my group deals with on a daily basis,” Russ Mantifel, BPA director of market initiatives, said. “But other entities are making decisions, right? But Bonneville is not in a vacuum, where we get to have self-determination over exactly what all of our options are going to be. And I’ve never delivered what has been considered to be good news. I’ve never run a process where people thought we had enough time.”

Heutte said BPA faces a “crucially important” choice.

“Among other things, it’s a choice to leave the EIM after taking so long to get into it and realize some real value from it. And the big thought that I have right now is, look before we leap,” he said.

‘Not Equally Distributed’

If NWEC’s reservations about the timeline are colored by a concern that BPA could stymie the potential for a single West-wide electricity market by choosing Markets+ over EDAM, then BPA officials did little to assuage that concern on Monday.

Industry sources not authorized to speak on behalf of their organizations have told RTO Insider that BPA is favoring Markets+ — in part because of an in-depth economic study commissioned by the Western Markets Exploratory Group  to ascertain Western market benefits.

The sources said the study, which has not been released to the public, shows that, in a single market, a disproportionate share of the benefits would flow to California, while a two-market solution would provide greater financial benefits to BPA and the Northwest at large.

Mantifel spoke around the specifics of the study on Monday but appeared to confirm that assessment.

“The results are complicated … and identifying who receives which benefits is also an important part. Societally, a broad footprint produces more diversity, more optimization [and] produces more benefits, but I think they’re not equally distributed,” he said.

BPA plans to hold a call on Oct. 23 to discuss the “quantitative results” of the study related to the agency, he said.

During the meeting, Mantifel also praised BPA’s experience in working with SPP during the Markets+ design process.

Responding to a question about whether BPA preferred SPP’s stakeholder-driven process for dealing with market initiatives over CAISO’s staff-led approach, he said, “I think we’ve really enjoyed our experience with the SPP process. Being engaged in it is difficult; sometimes it feels messy. But that process, I think, is a good representation of how representative that organization is.”

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SPP REAL Team Compromises on PBA, ELCC Revisions

DFW AIRPORT, Texas — SPP stakeholders last week asked two working groups to consider compromise language on a pair of tariff revisions related to resource adequacy policies.

The Resource and Energy Adequacy Leadership (REAL) Team voted to ask the Supply Adequacy and Cost Allocation working groups (SAWG and CAWG) to review the revision requests (RR554 and RR568) following the team’s Sept. 8 meeting. RR554 details the performance-based accreditation (PBA) policy, and RR568 lays out the effective load-carrying capability (ELCC) policy.

SPP staff proposed the compromise after pushback from the Market Monitoring Unit (MMU) and a lengthy discussion among the REAL Team’s members. The Monitor said it couldn’t support RR554 as written over accuracy and equity concerns, and it said RR568 included inconsistencies that could be considered unduly discriminatory.

“I think it’s important that we attempt to restore trust among the MMU that we will deliver on commitments,” Texas Public Utility Commissioner Will McAdams, the REAL Team’s chair, said during the meeting. “I think this policy debate has highlighted that it’s just trying to identify and assign the appropriate vehicle to carry out these strategic aims of the organization.”

Texas regulator and REAL Team Chair Will McAdams listens to speakers during SPP’s Resource Adequacy Summit. | © RTO Insider LLC

Keith Collins, the MMU’s vice president, said he appreciated McAdams’ effort to advance the RRs.

“We’re supportive of considering [the potential RR changes] and moving them forward,” he said.

Staff said the compromise’s modifications could be implemented while still maintaining the RRs’ structural frameworks and timeline. The primary change is using seven years of historical outage data, rather than 10, in determining conventional resources’ accredited capacity under RR554.

The MMU had suggested five years of historical data, saying the PBA “asymmetrically” treats historical performance. It said outage exemptions are inconsistent with ELCC and performance is assessed over the entire season, not when needed.

The compromise also proposes adding out-of-management-control events, such as tornadoes and other violent storms, in calculating the ELCC for wind, solar and storage resources, and weighting the PBA during resource advisories, conservative operations and energy emergency alerts.

Under RR554, PBA places more value on conventional resources that are reliable and available to perform when needed the most. It is intended to ensure the appropriate capacity value to calculate SPP’s planning reserve margin.

RR568 is a response to FERC’s rejection this year of SPP’s first attempt to add ELCC (the amount of incremental load a resource can dependably and reliably serve during peak hours). The revision reduces a three-tiered structure to just two, firm and nonfirm transmission service. Staff will study only firm service in its ELCC analysis. (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)

The Advanced Power Alliance’s Steve Gaw (left) makes his case during the REAL Team’s Sept. 8 meeting. | © RTO Insider LLC

The REAL Team has targeted the October series of governance meetings to gain approval of the two RRs. They are scheduled to be deployed for the 2026 summer season.

The SAWG meets Sept. 26-27 and the CAWG meets Oct. 3. The REAL Team will review their input during an Oct. 5 virtual meeting.

“Time is of the essence, and we need to have strategies in place that include contingencies,” Director Steve Wright said.

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BNOW Calls for Standardizing, Sharing OSW Data

An offshore wind advocacy group is calling for greater collaboration among the developers and researchers who are shaping the industry as it takes hold in the U.S.

The massive quantities of data being gathered on wind turbines, the ocean and the interaction between them typically are held as proprietary trade secrets as multibillion-dollar contracts are pursued, the Business Network for Offshore Wind said.

In its new report — “Building a Collaborative Data Strategy for the U.S. Offshore Wind Industry” — BNOW makes the case for standardizing and sharing this information, so the industry can build a body of knowledge, standardize maintenance procedures, maximize turbine efficiency and more accurately estimate costs.

After more than a decade of preparation and false starts, the U.S. offshore wind industry is out of the starting gate, with “steel in the water” this year for the nation’s first two utility-scale wind farms and more facilities being approved as regulators push to meet President Biden’s 30 GW by 2030 goal.

But just as it developed some real momentum, the industry has been slammed with cost increases and supply chain constraints so severe that multiple projects are being delayed or threatened with cancellation unless they get more money from ratepayers.

BNOW says the industry is at a tipping point, with an imperative for stakeholders to see offshore wind as collective, critical energy infrastructure rather than a series of individual power plants.

“Better data is the answer, and this report illustrates the opportunity and urgency for the industry to chart a path towards an environmental data strategy,” BNOW President Liz Burdock said in a news release Monday. “Harnessing data shared in a collaborative fashion can cut down on the permitting timeline and ensure greater environmental stewardship, building public confidence and fostering greater investor confidence in the U.S. market.”

Among the report’s points:

Environmental data typically has been collected primarily to meet siting and development requirements but typically has not been shared because of competitive reasons. If shared, it could form the basis for long-term analysis, learning and problem-solving.

Collection protocols and data standards are negotiated on a project-by-project basis, complicating any effort to build a dataset for a given region.

Minimizing environmental impact and mitigating concerns raised by stakeholders is a concern for the entire industry, not just individual projects.

Steps have been taken in this direction: New York requires offshore developers selling power to the state to make non-proprietary environmental data publicly available as soon as possible, for example, but none of the surrounding states do the same. And Ørsted has a data-sharing agreement with the National Oceanic and Atmospheric Administration. But there is not a consistent long-term framework for sharing by other developers.

Standardization is important. The United Kingdom, for example, required all developers seeking offshore wind leases in Crown Estate waters to submit their data for archiving but did not specify a format for it — so it has an assortment of data that is difficult to analyze as a whole.

Data from individual U.S. projects typically is compartmentalized for limited audiences, making it difficult to compare projects over time, look at regional interactions or consider multiple projects.

BNOW’s Aybala Sen, a co-author of the report, said it laid out a critical first step toward a collaborative strategy.

“Identifying both data challenges and opportunities as well as working collaboratively to outline a path forward is necessary to the widespread and enhanced use of offshore wind data, and ultimately, the industry’s overarching success.”

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EPA Predicts IRA Will Speed Electric Emissions Reductions

A new EPA report projects significant emissions reductions from the electric power sector by 2030 as provisions of the IRA take hold.

The report — “Electricity Sector Emissions Impacts of the Inflation Reduction Act” — is imprecise because of the range of constraints that could increase or decrease over the next seven years, including policy, technology and availability.

But even the low-end models suggest a large decrease in greenhouse gas output: The electric sector could see a reduction of 49 to 83% from 2005 levels by 2030, or even as high as 91% under advanced-technology scenarios. The report projects a 40 to 68% decrease would occur without the IRA.

EPA was mandated to produce the report as part of the Low Emissions Electricity Program of the IRA.

The report models carbon dioxide emissions reductions with and without the provisions of the IRA. Both scenarios incorporate state and federal policies finalized before Biden signed the IRA into law in August 2022. Neither scenario reflects rules and regulations now being developed or finalized.

The report incorporates data from 10 multisector models (changes in generation and use of electricity) and four electric-sector models (changes only in generation) created by EPA, the Department of Energy and the National Renewable Energy Laboratory.

All but one of the models show the bulk of the reductions will result from construction of new wind and solar facilities assisted by IRA incentives; infrastructure buildout assisted by the Infrastructure Investment and Jobs Act; and increased energy storage. The other model relies heavily on carbon capture and storage to reduce emissions.

All the models are based on increased use of low- and zero-emissions technologies and decreased use of high-emission coal- and gas-fired generation.

That is at the heart of the IRA: Its provisions support clean electrical generation, encourage electrification of end uses and promote energy efficiency.

Under the various models, emissions are expected to be 11 to 25% lower in 2030 than in 2005 in the transportation sector, 49 to 63% lower in the buildings sector and 11 to 43% lower in the industrial sector. Economywide, emissions are projected to drop 35 to 43% by 2030.

Transportation is the laggard because of the sheer number of internal combustion vehicles that must be replaced by EVs, and because some modes of transportation may not see wholesale changes attributable to the IRA.

EPA noted that future analyses of the IRA’s effects would benefit from completion of processes still in motion — final tax credit guidance on clean hydrogen, for example, or further improvement in technology. Complementary federal, state and local policies are expected to evolve as well.

Some IRA tax credits extend beyond 2030, as well. And the technology development and deployment expected to result from the IRA will not be complete by 2030.

In a news release Tuesday, EPA called the IRA the most significant policy action on clean energy and climate change ever, and EPA Administrator Michael Regan hailed the impact projected in the report.

“The Inflation Reduction Act is transforming energy production and consumption in dramatic ways, paving the way towards a clean energy future,” he said. “This report shows robust evidence that America’s clean energy transformation is driving significant reductions in CO2 emissions, putting us on a clear path to achieve President Biden’s bold climate goals.”

EPA is part of the executive branch of federal government, and the IRA is a signature achievement of the executive, President Joe Biden.

He faces a tough fight for re-election and the IRA faces a potentially rocky road if he loses or if the Republicans who opposed the package of spending and policy measures succeed in winning control of both chambers of Congress.

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DOE Report Lays out Commercialization Path for VPPs

The U.S. Department of Energy on Tuesday released a new “Liftoff” report laying out how virtual power plants (VPPs) can reach commercialization.

VPPs are aggregations of distributed energy resources such as rooftop solar, batteries, electric vehicles and traditional demand response programs.

“Pathways to Commercial Liftoff: Virtual Power Plants” is meant to spark a dialogue between DOE, regulators, policymakers, utilities, ISO/RTOs, corporations, research organizations, advocacy groups and others around challenges and potential solutions for commercialization. It’s the fifth Liftoff report, with others covering advanced nuclear, long-duration energy storage, carbon management and clean hydrogen.

Electricity demand is growing nationally for the first time in a decade as fossil plants retire. Deploying 80 to 160 GW of VPPs by 2030, triple the current level, could support rapid electrification compared to building more peaker plants, the report said. National peak demand is expected to grow from 743 GW to 802 GW by 2030, while 162 to 183 GW of generation will retire the rest of this decade.

“In all scenarios, the mix of weather-dependent renewable generation will be unprecedented, leading to more variable electricity supply and higher demand for transmission capacity,” the report said. “Transmission interconnection backlogs, which have stretched to an average of five years, pose potential resource adequacy challenges. Large-scale deployment of VPPs could help address demand increases and rising peaks at lower cost than conventional resources, reducing the energy costs for Americans — one in six of whom are already behind on electricity bills.”

The report counts between 30 and 60 GW of VPPs today, largely made up of DR programs aimed at trimming loads when demand spikes. But VPPs can be used for many other activities that benefit the grid, it said.

“Example functions of VPPs on the market today include shifting the timing of EV charging to avoid overloading local distribution system equipment; supplying homes with energy from on-site solar-plus-storage systems during peak hours to reduce demand on the bulk power system; charging distributed batteries at opportune times to reduce utility-scale solar curtailment; dispatching energy from commercial EV batteries back to the grid; and contributing ancillary services to maintain power quality, all while minimizing impact to the DER owner,” the report said.

VPPs can be 40 to 60% cheaper than the alternatives of utility-scale batteries or natural gas peaker plants, so deploying up to 160 GW by 2030 could save customers about $10 billion annually. That would be enough to contribute 10 to 20% of peak demand, with local differences driven by DER availability and the mix of utility-scale generation.

The economic benefits are in line with a Brattle Group report from this spring, whose authors also worked with DOE staff on the Liftoff report. (See Brattle Group Finds VPPs Cheapest Alternative for Resource Adequacy.)

The resources capable of making up VPPs are expected to grow regardless, with EV charging infrastructure adding between 20 and 90 GW each year of nameplate demand capacity and 300 to 540 GWh of nameplate storage capacity from their batteries. It also will add 5 to 6 GW per year of flexible demand from smart appliances and nonresidential DR, another 20 to 35 GW of distributed generation (mostly solar) and 7 to 24 GWh from distributed batteries outside EVs.

The report includes some policy suggestions, such as expanding DER adoption by offering low-cost financing and rebates to induce customers to shift spending to products that can respond to grid needs. The enrollment process in VPP programs could be simplified by adopting opt-out enrollment when consumers buy DER devices, and the sector would benefit from increased customer education, it said.

The operations of VPPs should be standardized so the assets can be more repeatable in order to shorten the design and pilot stages of individual deployment, it said. The resources also should be integrated into standard utility planning, and utilities need the right incentives to use them.

The resources can be integrated into organized wholesale markets as FERC Order 2222 is implemented in different ISO/RTOs.

VPPs are highly configurable, the report said, meaning they can meet different grid needs at both the distribution and transmission levels. Reshaping demand curves and providing ancillary services can increase grid resilience and cut congestion.

They also are affordable, which is important: While the grid needs major investments, some one in six households already are behind on their electric bills, the report said.

“As lower-cost options for increasing grid capacity, VPPs can moderate the cost burden on ratepayers. They provide services from DERs available on the distribution grid in ways that can be more cost-effective than increasing bulk system resources,” the report said.

California is seeing rapid electrification and decarbonization, and some estimates have utilities there spending up to $50 billion to fortify their distribution systems by 2035, but the report said VPPs could cut that by 70%, down to just $15 billion. Demand has been rapidly growing in Texas, by about 9% from 2018 to 2022, and analysis suggests DERs could save customers $150 per year on average by 2030.

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NJ Businesses Demand Halt to EV Sales Promotion Rules

New Jersey’s plan to adopt California’s Advanced Clean Cars II (ACC II) rules, which gradually limit the sales of fossil-fuel vehicles and eventually ban them in 2035, will be “crippling” to communities, businesses and the economy and should be abandoned, a coalition of 100 business groups told legislative leaders Tuesday.

A two-page letter crafted by the New Jersey Business and Industry Association (NJBIA) and sent to Senate President Nicholas Scutari and Assembly Speaker Craig Coughlin, both Democrats, said the plan would impose “a substantial expense on property taxpayers, without a necessary funding mechanism, for building and maintaining robust charging infrastructure.”

The letter, produced under the name New Jersey Business Coalition, comes midway through the public comment period held by the New Jersey Department of Environmental Protection to solicit comments on the rules in preparation for their implementation. The period, which runs from Aug. 21 to Oct. 20, includes a Sept. 21 public hearing.

Alongside the NJBIA, one of the state’s largest business groups, the letter signers included about two dozen regional and local chambers of commerce, and associations such as the New Jersey Motor Truck Association, New Jersey Tourism Industry Association, NAIOP-NJ, the New Jersey Bankers Association and the state Retail Merchants Association.

“We share the governor’s desire to reduce carbon emissions, but the significant disadvantages of this proposal greatly outweigh any potential benefits,” the coalition said in a release.

Asked about the letter, Bailey Lawrence, a spokesman for Gov. Phil Murphy (D), said his administration “will continue to advance its pursuit of a clean energy future, including through voluntary, incentive-based EV programs that preserve consumer choice while putting money back in the pockets of hard-working New Jerseyans.”

Increased Burden

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

The regulation starts with a 35% ZEV sales requirement for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. ACC II also includes increasingly stringent low-emissions vehicle standards aimed at reducing tailpipe emissions of gasoline-powered cars and heavier passenger trucks.

When state officials in March outlined the process for adopting ACC II, environmentalists at a public hearing into the process urged the state to approve the rules by the end of the year so they would affect 2027 vehicles sales. DEP officials concurred with the plan but said it would be tough for the state to move that quickly. (See Enviros Demand NJ Move Faster on 100% EV Rule.)

The coalition letter, saying the ACC II plan is “impractical and misguided,” argues the rules would “inequitably strain the limited resources of families, businesses (and) governments” because of the far higher costs of EVs than fossil-fueled vehicles and the infrastructure costs of charging stations. In addition, by forcing the purchase of EVs, the letter says, the rules would elevate the demand for electricity above the level the grid can handle.

“New Jersey residents should have the ultimate choice in the vehicles they purchase,” the letter states. “By denying thousands of New Jerseyans access to an affordable vehicle, this mandate would be crippling to our communities, businesses, economy and labor workforce, and would exacerbate income inequality in our state.”

“Even with historic investments over the next decade, there is no guarantee that the infrastructure to support such a massive network of charging stations can be built in just 12 years in a reliable manner and maintained to support our large population,” the letter adds. It argues that rather than “doubling down” on EVs, the state also should consider vehicles powered by compressed natural gas (CNG), propane auto-gas, hydrogen and renewable diesel, as well as hybrid cars.

The letter urged the legislators to reject ACC II and delay taking action until the legislature can vote on the issue.

Increasing EV Adoption

The state had 93,000 EVs at the end of 2022, according to the Board of Public Utilities, well below the state’s target of 330,000 registered light-duty EVs by 2025. The number of EVs also is a tiny proportion of the estimated 6 million light-duty vehicles registered in the state.

Washington, Oregon, New York, Massachusetts, Virginia and Vermont already have adopted the California ACC II program, and Colorado, New Mexico, Maryland, Delaware, Maine, Connecticut, D.C. and Rhode Island are considering the rules, according to the Natural Resources Defense Council (NRDC). (See NM Sets Course to Adopt New Clean Vehicle Rules.)

A report released by the NRDC and the Sierra Club in May concluded that if the state adopted ACC II, about 16% of vehicles sold in the state would be EVs by 2030 and 94% would be EVs by 2050, depending on how it was adopted. The report stated that under a “business as usual” approach in which ACC II is not adopted, about 30% of vehicles in the state would be EVs, but it would remain at that level. (See NJ EV Charger Plan Advances as Enviros Demand ACC II Adoption.)

“The fact is that ACC II provides significant benefits to New Jersey (up to $97 billion in net societal benefits),” Kathy Harris, NRDC’s senior clean energy advocate, wrote in an email to NetZero Insider in response to the coalition letter. The gradual increase in required EV sales gives the state and private developers time to expand charging infrastructure in the state, she said.

“Importantly, ACC II will not prevent NJ drivers from purchasing affordable vehicles, as the regulation only affects new vehicle sales, and will instead expand the clean car options available for sale within New Jersey,” she said.

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PJM PC/TEAC Briefs: Sept. 5, 2023

Planning Committee

PJM Presents Quick Fix on Load Forecast Guidelines

VALLEY FORGE, Pa. — The frequency and magnitude of load forecast adjustment requests PJM is receiving from electric distribution companies (EDCs) has led the RTO to bring a problem statement, issue charge and proposed manual revisions on the timeline those adjustments are approved on.

The changes are being sought through the quick-fix process, which allows an issue charge and proposed solution to be brought concurrently and voted on in an expedited manner.

PJM’s proposal would move the Load Analysis Subcommittee’s review of forecast adjustment requests to September and October to provide more time for consideration, and EDCs would be requested to provide hourly data and a 15-year forecast of their adjusted load.

PJM’s Molly Mooney told the Planning Committee on Sept. 5 that numerous factors are taken into account to avoid double-counting load during forecasting, and any types of industries reflected in federal employment figures wouldn’t be counted as a discrete large load increase. Loads from data centers, however, are difficult to forecast because of their disproportionate demand and the fast turnaround between when an interconnection is requested and the in-service date.

Paul Sotkiewicz, president of E-Cubed Policy Associates, asked what PJM’s lead time is between when it finds out about an expected load and that consumer going live on the grid.

PJM’s Dave Souder said much of the load goes through the supplemental process at the Transmission Expansion Advisory Committee, providing a few years’ notice. The issue charge seeks to obtain that information from EDCs further out so more analysis can be built into the planning process.

James Wilson, a consultant for state consumer advocates, said data centers are largely being constructed by a few major parties that are concerned about transmission constraints hindering their projects, leading them to investigate siting in multiple EDCs when only one project will come to fruition. If this is not accounted for, he said projects could be double-counted and transmission built to serve loads that are not built.

Wilson urged PJM to hire an independent consultant to do a long-term forecast of data center load and questioned what PJM’s response would be if EDCs were unwilling to do a 15-year forecast of data center loads. He said that in the event that an EDC submits a total load adjustment request for load-serving entities within their territory, those entities should be required to verify the adjustment.

Mooney said increasing the horizon on the data PJM is seeking also allows for more time to collaborate with EDCs and work through any issues distributors may have with the process.

First Read of 2023 Reserve Requirement Study

Load forecast uncertainty and increased winter risk are driving a significant increase in the reserve procurement levels recommended by the 2023 Reserve Requirement Study (RRS), which went before the PC for a first read. (See PJM Presents Preliminary 2023 Reserve Requirement Study to Stakeholders.)

The installed reserve margin (IRM), which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 delivery year in the 2022 study to 17.6% for the 2027/28 DY using PRISM modeling software. The forecast pool requirement, which considers forced outage rates, also would increase from 9.18% to 11.65% for the corresponding DYs.

Numerous changes were made to the study’s processes this year, including two parallel analyses using the PRISM software historically used in the RRS, as well as using software developed to perform hourly loss-of-load modeling used in effective load-carrying capability (ELCC) and the inclusion of data from the 2014 polar vortex and the December 2022 winter storm. PJM has historically not included the 2014 storm in the RRS dataset, but experience from the storm led staff to revise that practice.

The preliminary results of PJM’s 2023 Reserve Requirement Study (RRS) would lead to higher reserve margins under both the PRISM and hourly models | PJM

The hourly modeling largely led to higher figures, yielding an IRM of 18.3% for the 2027/28 DY and 12.31% FPR, with much of the difference between the PRISM values arising from the load model. Prior to stakeholders voting on endorsement, PJM plans to recommend use of either the PRISM or hourly results, which stakeholders will have the opportunity to chose between.

PJM’s Patricio Rocha Garrido said 70% of the loss-of-load expectation (LOLE) is concentrated in the summer and 30% in the winter under the PRISM modeling, while the hourly modeling has an 80/20 balance between the summer and winter. Past modeling is now believed to have understated extreme loads, especially in the summer, he said.

“The previous load forecast model was producing values that were understated … whereas the new model that is more granular looks at every hour of the year and the weather in that hour” and the corresponding intermittent output, Rocha Garrido said.

Minimal coincidence between the PJM peak load period and the “World” peak — which is defined as MISO, NYISO, TVA and VACAR — led to the capacity benefit of ties (CBOT) value more than doubling to 2.2% from the 1% value in the 2022 study. To reduce volatility, PJM elected to average the CBOT values from 2017 to 2022 and use that figure, which landed at 1.5% instead.

Transmission Expansion Advisory Committee

PJM Updates Stakeholders on RTEP Windows

Project proposals for the first window of PJM’s 2023 Regional Transmission Expansion Plan (RTEP) are being accepted through Sept. 22, with the goal of resolving 266 flowgates, 130 of which are competitive. The window opened on July 24, and PJM is targeting receiving approval from the Board of Managers in February, PJM’s Sami Abdulsalam said during last week’s meeting.

PJM is also conducting scenario evaluations on the 72 proposals submitted in the third window of its 2022 RTEP, which opened in May to solicit solutions to load growth centered on the northern Virginia region, which is experiencing high data center load growth. Staff plans to walk stakeholders through the window evaluation results during the Oct. 3 TEAC meeting, which will be followed by a first read Oct. 31.

Several ratepayers expressed concerns about land use and cost allocation to regions they argued would not be benefited by the projects, and they urged PJM to consider historical opposition similar projects have received.

Supplemental Projects

FirstEnergy presented a project to replace a 230/34.5-kV transformer nearing its end of life and associated relays at its Windsor substation in the JCPL zone at a $6.3 million price tag. The replacement is underway and is expected to be completed in November.

FirstEnergy presented a $2.2 million project to replace circuit switcher and limiting substation conductor at its Damascus substation and a wave trap, disconnect switches and limiting substation conductor at its Mount Airy facility, which are connected by the 230-kV Damascus-Mount Airy line in its APS zone. The equipment at the two sites has a history of misoperation and cannot be repaired due to lacking spare parts and limited expertise in the technology.

The Public Service Enterprise Group presented two projects to add substations in the South Edison and Perth Amboy area to address rising loads and aging equipment at its existing local infrastructure. The 230/13-kV South Edison substation would be built at a $56.1 million cost adjacent to the existing Meadow Road facility, which has a contingency overload of 124%. A new 69-kV line would be built from South Edison to a new 69/13-kV substation, which would be built adjacent to the Keasby facility. The $220.9 million project would support the Keasby substation, which is nearing 100 years old and in need of repairs, and the Pierson Avenue substation, which has a contingency overload of 123.3%.

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PJM OC Briefs: Sept. 7, 2023

PJM Delays Vote on Quick Fix to Information Sharing Requirements

VALLEY FORGE, Pa. — PJM on Thursday opted to hold off from seeking stakeholder endorsement of a quick-fix issue charge and proposed manual revisions aimed at reducing the circumstances under which the RTO would be compelled to provide advance notice of when it will be sharing confidential member information with third parties. (See “PJM Brings Quick Fix Issue on Data Sharing,” PJM OC Briefs: Aug. 10, 2023.)

PJM’s Becky Davis told the Operating Committee that confidential information is regularly shared with reliability coordinators, transmission owners and NERC in the course of normal business, and a notification five days before the information is shared has become “inefficient and impractical” and slowed down coordination with those parties.

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned why the change was being sought as a quick-fix change to Manual 33, rather than as a change to the Operating Agreement with a corresponding FERC filing, which he believes would be a “slam dunk” before the commission.

PJM Assistant General Counsel Thomas DeVita said the RTO considered removing the notification entirely through changes to the OA but came to the conclusion that members may prefer notification in some circumstances, such as the NERC inquiry into the December 2022 winter storm.

East Kentucky Power Cooperative’s Denise Foster Cronin suggested explicitly including the advance notice exceptions envisioned by the draft manual revisions in the OA (rather than the manual) and including a retroactive notification requirement when advance notice is not provided to allow members to remain informed about when their information has been shared without slowing down PJM’s coordination with third parties.

PJM said it will defer seeking a vote on the quick fix until the October OC meeting to work with stakeholders to incorporate their feedback into the proposal.

Stakeholders Endorse Quick Fix on Synchronized Reserve Dispatch

The OC unanimously endorsed a quick fix issue charge and manual revisions to clarify that generation owners should respond to a synchronized reserve deployment when they receive notification through any of the existing Energy Management System (EMS) datalinks. (See “PJM Proposes Synchronized Reserve Deployment Language,” PJM OC Briefs: Aug. 10, 2023.)

PJM’s Frank Hartman said the status quo language has resulted in many reserve resources waiting until they have received the all-call message from dispatchers, which takes longer to reach generators. When reserve resources receive a signal to respond, Hartman said their default is to provide the full amount they’re committed to in the market. For a resource with a 50-MW reserve obligation, he said that is the amount it should provide unless it receives instructions otherwise from dispatchers.

The quick fix is one of several solutions PJM has proposed to address a decline in response rate since the reserve market was overhauled in October. (See “PJM Seeks Stakeholder Process on Reserve Certainty,” PJM MRC/MC Briefs: July 26, 2023.)

Sotkiewicz said he finds the issue charge problematic as it does not address the possibility that there may be underlying issues with the reserve market structure that may be leading to the decline in response rates.

PJM’s Donnie Bielak said the quick fix is meant to clarify existing instructions to generators, and there are other forums where the RTO intends to address the issues that Sotkiewicz raised.

“All of your comments are well taken; it is on our radar, and it is something we collectively want to address as well,” Bielak said.

Stakeholders Endorse Manual Revisions Related to Communication Failures

The OC unanimously endorsed revisions to Manual 1 that detail when TOs would be required to notify PJM that interpersonal communication capabilities have been disrupted.

The revisions state that PJM is required to be notified when only alternative communication systems are available and a loss of portions of a TO’s interpersonal communication capability, such as a radio failure, does not require a notification so long as other voice communications detailed within the TO’s communication capability remain available. (See “PJM Proposes Manual Revisions Related to Communication Failures,” PJM OC Briefs: Aug. 10, 2023.)

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PJM MIC Briefs: Sept 6, 2023

Voltus Withdraws Issue Charge on DR Offer Parameters

VALLEY FORGE, Pa. — Voltus on Wednesday withdrew an issue charge at the PJM Market Implementation Committee addressing the parameters that demand response resources can include in their energy market offers after several stakeholders stated their opposition to using the “CBIR Lite” (Consensus Based Issue Resolution) process.

The MIC was to vote on adopting the issue charge during Wednesday’s meeting. (See “Voltus Brings Economic Demand Response Parameter Issue Charge,” PJM MIC Briefs: Aug. 9, 2023.)

David Aitoro, Voltus senior energy markets manager, said the company would further consider whether it wanted to continue to seek the CBIR Lite pathway or switch to the standard CBIR process before bringing the subject before the committee again.

Paul Sotkiewicz, representing J-Power, said the use of the CBIR Lite process prevents him from being able to support the issue charge, which he would otherwise likely support in concept.

The problem statement and issue charge say DR providers lack the ability to automatically specify a maximum run time or to set a minimum amount of time between being dispatched.

Because the documents were first brought for a first read in August, Aitoro said they were revised to make clear that the issue charge would preclude discussion of capacity market offers and is instead intended to focus on the two parameters outlined.

“We’re not touching any broad status quo rules; we’re not touching load management,” he said. DR participating in the capacity market is referred to as load management.

Monitoring Analytics President Joe Bowring | © RTO Insider LLC

Independent Market Monitor Joe Bowring said the narrow scope of the issue charge would prevent stakeholders from engaging in discussions about DR that need to be had, including interactions between DR’s participation in the capacity and energy markets. He also opposed using CBIR Lite, saying the potential impacts warrant the full stakeholder process.

“This is not a trivial thing; it has potentially significant impacts on how DR works,” he said.

AEP Energy’s Brock Ondayko raised the possibility of requiring DR resources to document when they make a change to their parameters.

Aitoro said he intends to keep the scope of the issue charge narrow, and if a broader discussion is sought by stakeholders, an additional issue charge would be the best way to initiate that.

Providing education on the status quo rules for DR, PJM’s Peter Langbein said there is about 8,451 MW of DR participating in the capacity market, the “vast majority” of which does not have an energy market offer. About 2,449 MW of DR is in the energy market.

A DR resource can participate both as load management, with a capacity and energy market offer, as well as a separate economic DR resource, with an energy-only offer. Langbein said the parameters included in the capacity offer would override any energy offer parameters.

There are numerous ways in which the energy market rules differ for DR resources, including their ability to manually change the availability of their offer into the market, which Langbein said is because of the lack of market power concerns.

Sotkiewicz said the differences, particularly the ability to switch availability on and off, have the potential to be discriminatory treatment.

“Why do we have different rules for economic DR than generation?” he asked.

AEP, Dominion Proposal on Capacity Obligations for Concentrated Loads

An issue charge and problem statement proposed by American Electric Power and Dominion Energy would address how capacity obligations are assigned to load-serving entities when large amounts of load are added to concentrated areas.

AEP’s Josh Burkholder said that when a large amount of load is added to a single zone, such as clusters of data centers, it can lead to the capacity obligation being dispersed broadly across the zone. For fixed resources requirement (FRR) entities, he said that can also result in the amount of capacity they’re required to procure being above what’s needed to serve their internal demand.

The issue charge also ran into questions about whether it should progress under CBIR Lite, as is currently proposed, or if it should instead use the standard CBIR process.

Discussion Continues on Multischedule Clearing in The Market Clearing Engine

Deputy Monitor Catherine Tyler presented a new joint proposal with the GT Power Group to address the computational barriers to introducing multischedule clearing in the market clearing engine (MCE). (See “First Reads on Proposals Addressing Multi-schedule Modeling in MCE,” PJM MIC Briefs: Aug. 9, 2023.)

The package is an alternative to GT Power Group’s original joint proposal with PJM, which would select resources’ cost-based offers when they fail the three-pivotal-supplier (TPS) test and their parameter-limited offers during emergency conditions, but would allow resources to choose the most cost-effective offer to send to the MCE when they have multiple valid offers, such as in the case of dual-fuel generators.

Catherine Tyler, IMM | © RTO Insider LLC

Tyler said a shortfall of the previous proposals was that dual-fuel generators may be dispatched based on schedules that would not match the most efficient fuel.

“We don’t want to commit a unit to run on a more expensive oil offer when [gas] fuel is more efficient,” she said.

Under the new proposal, if a unit with multiple offers fails the TPS test, PJM will commit the unit to operate based on the fuel the generation owner expects to use in each hour of the day. The PJM solutions would also not resolve issues that allow generators with market power to raise energy prices by using high markups and to extract uplift using inflexible parameters.

Tyler said any generators not submitting the most efficient offer may be considered to be engaging in market manipulation.

The joint package adds a fifth option to resolve an issue identified in the development of the Next Generation Markets (nGEM) overhaul of the MCE, where the number of offers the engine would have to analyze when clearing combined cycle and storage resources would cause an untenable increase in computational times. PJM’s proposal would create a formula for selecting the offer that results in the lowest total dispatch cost, which would be entered into the engine.

The first Monitor proposal would combine the lowest offer points and most flexible parameters from resources price and cost-based offers under certain scenarios, impose offer capping and parameter limits to all resources that fail the TPS test and apply parameter limits to capacity resources during emergencies.

The Monitor’s second package would do the same as above but would use the status quo rules for resources with multiple cost-based offers.

Sotkiewicz questioned if PJM would consider the proposal to be temporary until a technological solution that reduces computational times is found.

PJM’s Keyur Patel said if the technology improves, staff would be open to reverting to the status quo. Tyler, however, said the Monitor’s perspective is that the status quo would be improved by resolving the market power issues.

Competing Proposals Addressing Local Factors on Net CONE Merged

E-Cubed Policy Associates, PJM and the Monitor have merged competing proposals centered on how to account for local or state factors, such as climate legislation, which could affect the cost of new entry (CONE) for generators in that region. The new package would add a fifth CONE area for the Commonwealth Edison region but would not codify a new pathway for adding new areas in the future. (See “Stakeholders Discuss Proposals to Include Local Factors in Net CONE,” PJM MIC Briefs: Aug. 9, 2023.)

Both the original PJM and E-Cubed packages would have broken ComEd out as a new CONE area, but the E-Cubed proposal also would have automatically created new areas when local factors shortened asset lifespans or would imply a different reference resource from what is used by PJM in its calculation of CONE. Sotkiewicz, president of E-Cubed, has argued that the impact of the Illinois Climate and Equitable Jobs Act (CEJA) would shorten the lifespan of many generators, including the reference resource, located in the state. The merged proposal would include an amortization period reflecting CEJA in the fifth CONE area.

Sotkiewicz said streamlining the process to create new CONE areas in the future was his primary rationale for creating a second proposal, but that he believes the existing tariff language has been demonstrated to be adequate. He said PJM was concerned about creating an automatic process for adding CONE areas, believing it should be done on a case-by-case basis with stakeholder consideration of the variability on the ground.