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November 1, 2024

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Solar Developers Sing Mid-Atlantic Interconnection Blues

BALTIMORE, Md. ― Some solar companies in the Mid-Atlantic have stopped looking for sites for utility-scale installations in the region due to the current backlog of renewable energy projects in PJM’s interconnection queue, according to Steve Swern, senior director for generator interconnection at Sol Systems, a Washington, D.C.-based developer. 

The RTO is not expected to clear that backlog and start reviewing new applications possibly until 2026, Swern said Nov. 16 during a panel discussion on interconnection at the Solar Focus conference hosted by the Chesapeake Solar and Storage Association (CHESSA). “So how do I tell a corporate off-taker that, sure, we can site a project for you to deliver renewable energy in PJM. Is a [commercial operation date] by 2030 OK?” 

A regional trade association, CHESSA’s members primarily are solar and storage developers in D.C., Maryland and Virginia — all in PJM’s 13-state service territory. When looking to site solar projects in the PJM footprint, Swern said, multiple strategies are considered, including bypassing the queue by approaching utilities to connect to their distribution grids.

The company intends to move ahead with projects it already has in the PJM queue but “is approaching utilities — transmission utilities, distribution utilities — to really push the envelope of how big can we build, what clients can we connect to, without involving the scrutiny, the oversight and the jurisdiction from the RTO,” Swern said. 

Getting more solar on the grid is a critical issue in D.C., Maryland and Virginia, each of which has set ambitious targets for running their respective electric systems on 100% clean power ― by 2032 in D.C., 2035 in Maryland and 2050 for Virginia. 

But reaching those goals likely will mean being able to import clean power from PJM. The nation’s capital, for example, has minimal generation within its 68 square miles, seven of which are water. PJM has warned Maryland of potential rolling blackouts if one of the state’s remaining coal plants, the 1,238-MW Brandon Shores generating station, is taken offline in 2025, as currently planned. 

According to figures from PJM, its power mix is still more than 60% fossil fuels. On the carbon-free side, in 2022, nuclear accounted for about one-third of the RTO’s generation fuel mix, but wind and solar together stood at 4.9%. At the same time, solar, wind and storage make up almost all of the over 300 GW of projects in PJM’s interconnection queue, as reported by the Lawrence Berkeley Laboratory.  

The grid operator is working on a Regional Transmission Expansion Plan aimed at adding the capacity needed for new renewables or other power that will replace retiring coal plants.

Like Swern, James Mirabile, the principal engineer for interconnection at Baltimore Gas and Electric (BGE), said getting renewables interconnected on distribution systems is an easier lift. In 2022, BGE had 91 projects totaling 139 MW in its interconnection queue, 35 MW of which went online that year. This year, to date, the queue has 87 projects totaling 165 MW and has interconnected 27 GW, he said. 

For BGE and other Maryland utilities, the process for getting those projects online is “very highly regulated,” Mirabile said, and the state’s Public Service Commission has set up an interconnection working group charged with updating the rules.  

The most recent update will go into effect Jan. 1, 2024, when all renewable projects will be required to use smart inverters with settings “that include a volt-var curve instead of a fixed power factor,” said Mirabile, who is a member of the working group. Such updated settings provide a flexible way for inverters to react dynamically to variations in voltage on the system, which can occur as more renewables come online, Mirabile said in an email to RTO Insider.  

BGE and four other utilities have submitted the smart inverter settings they will require for projects to the PSC, which approved the proposed settings on Nov. 21.  

The working group also has sent recommendations to the commission to reform cost allocation for distribution system upgrades, Mirabile said. Traditionally, when a project requires a distribution system upgrade for interconnection, the project developer carries the full cost. 

The working group is proposing a model where the project developer is allocated part of the cost, with the remainder “spread across future interconnecting customers,” he said. If approved, the proposed update would be “a major change in the way we price jobs.” 

The Aggregation Work-around

The backed-up interconnection queues at PJM and other RTOs and ISOs across the country are rooted in the wave of renewable projects seeking interconnection on systems that were “set up in such a way to not handle a large influx,” Swern said.  

Approved in July, FERC’s Order 2023 (RM22-14) is aimed at pushing grid operators toward some basic structural changes, such as doing cluster studies of projects seeking interconnection rather than on a case-by-case basis and attempting to weed out speculative projects by upping financial requirements for developers. (See FERC Updates Interconnection Queue Process with Order 2023.) 

But implementation of the order is on hold as FERC considers multiple requests for a rehearing on the rule. 

FERC previously approved reforms PJM had proposed to its interconnection process, similar to Order 2023 — cluster studies and stricter financial requirements — which the RTO rolled out in July. According to Susan Buehler, PJM’s chief communications officer, 40,000 MW of projects have been approved but not yet built.

Bahaa Seireg, senior director of energy storage at the American Clean Power (ACP) Association, said utility-scale energy storage projects are caught in the same slow interconnection queues. While an increasing number of states, including Maryland, have set targets for adding energy storage projects to the grid, Seireg said, it can take five years to work through transmission-level interconnection processes at an RTO or ISO.  

In May, Gov. Wes Moore (D) signed a law setting a goal for the state to have 3,000 MW of storage online by the end of 2033.  

Seireg sees a possible workaround for the interconnection problem in aggregation that breaks down the traditional divide between distribution and transmission. “Now, you can actually interconnect [solar and storage] to the distribution grid and aggregate resources … add them to distribution substations, aggregate them and bid them into the wholesale market,” he said. 

“That allows for some temporary reprieve from PJM,” he said.  

Sol Systems sees another “prime opportunity” for getting projects interconnected quickly at municipal utilities and electric cooperatives. These smaller, nonprofit utilities often are unregulated and “have a lot of flexibility in the decisions they make, in the projects they move forward and how costs are allocated,” Swern said. 

He also pointed to grid-enhancing technologies — such as advanced conductors and dynamic line ratings — as another option for maximizing the capacity of existing lines. “These are very low-cost solutions that help give grid operators higher granularity to thermal capacity of wires in a very specific location, [which] allows projects to operate … at full bore without being curtailed,” he said. 

The Information Gap

But the panelists all see major gaps in the information developers need to site and design projects that can get interconnected as quickly as possible.  

“Where we see a major stumbling block for interconnection is the quality of data, the existence of the data and the ability to use that to make informed decisions,” Swern said. In some cases, just figuring out where transformers are located means sending out trucks to map an area, he said. 

Some utilities now have online “hosting capacity” maps, showing what lines in their service territories have excess capacity, but Swern said, not all maps are created equal. “Some of them just give you a color-coded map; some of them actually allow you to click on the feeder itself and see what’s the ability to connect [distributed energy resources]; some you can get a load profile … for the past two years,” he said. 

At BGE, the best way for a developer to check out the available capacity of distribution lines at a site is to contact Mirabile directly, and he will do a pre-application analysis, he said. It’s reliable but not self-service, he admitted. 

Swern sees a more fundamental obstacle to interconnection in the misalignment of “spheres of control … or jurisdiction.” Federal, state, county and local governments all “have specific targets, mandates, goals for deploying renewables or retiring fossil assets … and there isn’t a good way to align all of those different things.” 

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New Jersey Launches OSW Infrastructure Solicitation

New Jersey’s Board of Public Utilities launched a new solicitation for offshore wind coastal infrastructure Nov. 17 as the heads of the BPU and the Economic Development Authority reaffirmed the state’s commitment to developing OSW projects in the wake of Ørsted’s abandonment of its two projects.

The BPU board, with a 4-0 vote, opened a solicitation for proposals to build a link between future wind projects developed off the Jersey Shore and the onshore substation infrastructure backed at the conclusion of a State Agreement Approach (SAA) solicitation on Oct. 26, 2022. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)

The BPU vote opened the new infrastructure solicitation with a submission deadline of April 3, 2024. The agency set out a schedule in which favored proposals would be picked in the third quarter of 2024, with an expected project in-service date of January 2029.

Brushing off Ørsted’s withdrawal, BPU President Christine Guhl-Sadovy said at the meeting the agency is “looking forward” to the third solicitation for offshore wind developments and said it had been “our most competitive yet.”

“Offshore wind is, and continues to be, the economic development opportunity of a generation and remains a key tool in climate change mitigation,” she said. “We remain excited about the prospect for a future generation and transmission solicitations.”

Protecting Ratepayers

Gov. Phil Murphy (D) has set a state wind capacity target of 11 GW by 2040, of which the BPU so far has awarded 3,758 MW. The BPU approved its first OSW project, Ørsted’s 1,100-MW Ocean Wind 1, in the first solicitation in 2019, and two other projects — the 1,148-MW Ocean Wind 2 project and the 1,510-MW Atlantic Shores project — in the second solicitation, in 2021.

The Atlantic Shores project continues to move ahead. But Ørsted stunned New Jersey officials on Nov. 1 by cancelling its two Ocean Wind projects, saying that cost increases had made the projects untenable. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)

In the state’s third solicitation, the BPU initially required developers submitting bids to include plans for the construction of infrastructure — known as pre-build infrastructure or PBI — that could tie several projects to the on-land infrastructure. But the board on Oct. 25 split off the offshore infrastructure requirement, saying that such a plan would impose an “unreasonable burden” on ratepayers, and that separating the two elements would create greater competition for the infrastructure projects. (See NJ Revamps Third Solicitation OSW Connection Plans.)

Jim Ferris, deputy director of the BPU’s division of clean energy, told the board Nov. 17 that the agency’s initial strategy of bundling the project and PBI elements together would have meant the developers would be awarded incentives for the entire package in offshore wind Renewable Energy Certificates.

Staff reviewed the proposals and found they represented an unreasonable burden for New Jersey’s ratepayers, he said, and that separating the two has not affected the projects already submitted for the third solicitation.

Servicing Multiple Projects

Four bidders submitted plans for the third solicitation, which could add OSW capacity of between 1.2 GW and 4 GW, and perhaps more, according to the guidance document for the solicitation. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)

The solicitation, which the BPU released as an attachment to its order, seeks proposals for “all cable vaults, duct banks and related facilities for four (4) separate qualified projects, enabling qualified project developers to install their cables into the prebuild by pulling them through the completed prebuild infrastructure facilities.”

Unlike the first infrastructure solicitation, held under the SAA agreement, the BPU will conduct the new infrastructure solicitation solely with BPU staff rather than in partnership with PJM, but will get “support from PJM, as requested by staff,” according to the order. The solicitation adds that it is open to companies that are prequalified through “PJM’s planning process to be a Designated Entity.”

Optimism for the Future

The state’s commitment to offshore wind includes extensive investment in creating infrastructure to support the development of a supply chain and logistics services that can support the projects, including the development of the New Jersey Wind Port on the Delaware River.

Much of that work has been funded by the EDA, where Chairman Terence “Terry” O’Toole — speaking at the agency’s monthly meeting Nov. 16 — called Ørsted’s decision “very disappointing and frustrating news.” He said that “despite the setback, there continue to be massive opportunities for New Jersey in this new sector and making investments in infrastructure and the manufacturing capacity support.”

Tim Sullivan, EDA’s CEO, said the agency has “continued optimism” about the sector, in part because “there is so much private capital being invested in the US wind industry, there’s so many private sector interests.”

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PJM MRC/MC Briefs: Nov. 15, 2023

Markets and Reliability Committee

Vote to Close Clean Attribute Group Fails

VALLEY FORGE, Pa. — The Markets and Reliability Committee voted against sunsetting the Clean Attribute Procurement Senior Task Force (CAPSTF), instead putting the group on track to be on hiatus as a state-led working group continues discussions outside the PJM stakeholder process. (See “Stakeholders Mixed on Sunsetting Clean Attribute Procurement STF,” PJM MRC Briefs: Oct. 25, 2023.) 

Task force facilitator Scott Baker said PJM dropped its recommendation to sunset the CAPSTF given ongoing discussions the states are having with FERC staff to explore whether a forward clean energy market (FCEM) would fall under state or federal jurisdiction.  

If the issue is determined to fall under the commission’s purview, it would return to the PJM stakeholder process to determine what form it would take and how it would operate. After Baker said PJM would not pursue sunsetting the task force, Paul Sotkiewicz, president of E-cubed Policy Associates representing JPower USA, motioned to sunset, receiving 34% support. 

The FCEM design would allow clean energy attributes to be purchased and traded by states and entities with sustainability targets and provide a centralized platform for existing renewable energy credit (REC) sales. PJM currently administers a registry of RECs through the subsidiary PJM EIS (Environmental Information Services), but it does not facilitate the trading of credits. 

Constellation’s Juliet Anderson said that if a Forward Energy Attribute Market design was determined to be FERC-jurisdictional, it could be returned to PJM stakeholders for consideration most efficiently through the existing charter of the senior task force. 

Calpine’s David “Scarp” Scarpignato said PJM task forces are meant to address specific topics over a specific period of time and the work envisioned for the CAPSTF has been complete. He argued that a new stakeholder group with a scope or charter more specific to any future needs would be better than leaving the task force open in case it can be restarted. 

Endorsement of Multi-schedule Modeling Solution Deferred

Stakeholders opted to defer voting on two proposals to narrow the number of market seller offers entered into the market clearing engine (MCE) in order to allow multi-schedule modeling capability to be added to the engine without causing processing times to increase beyond the day-ahead market’s 2.5-hour clearing window. The introduction of multi-schedule modeling is part of a larger overhaul of the engine under PJM’s Next Generation Markets initiative. (See “Multiple Proposals Considered for Incorporation of Multi-schedule Modeling,” PJM MRC Briefs: Oct. 25, 2023) 

PJM Associate General Counsel Chen Lu recommended delaying the vote to the December meeting in the hope that an anticipated FERC order on parameter-limited offers and real-time values would provide more clarity on how the proposals would be viewed by the commission. However, the docket was pulled off the agenda for the Nov. 16 open meeting (EL21-78). 

Both proposals would allow the day-ahead market to adopt the formula currently used in the real-time market to select one schedule from a resource to be modeled by the MCE. The main motion, sponsored by PJM in the Market Implementation Committee, would consider all offers with the aim of producing a schedule with the lowest total dispatch cost. 

The alternate motion, jointly sponsored by GT Power and PJM, would use the same formula, but would mitigate resources that fail the three-pivotal-supplier test to their cost-based offers, disregarding any price-based offers. During emergency conditions, the proposal also would limit capacity resources to their price-based parameter-limited offers. 

GT Power’s Tom Hyzinski said the joint proposal would alleviate the potential “crossing curves” issue in PJM’s design, in which the RTO would consider offers only at their economic minimum (EcoMin) value even if that offer would be more expensive at higher outputs. Highlighting the topic during the Oct. 25 MRC meeting, Deputy Market Monitor Catherine Tyler gave an example of a resource where the price-based offer is cheapest at its 100-MW EcoMin but  jumps to the $1,000/MWh offer cap when the resource is dispatched above 120 MW. In such a case, she said the cost-based offer should be selected even if it’s more expensive at EcoMin. 

Tyler said both PJM proposals could run into an issue in which dual-fuel generators may be selected to run on a schedule using a fuel that is not economical for a portion of the day. The Market Monitor/GT Power Group joint proposal is identical to the PJM/GT Power Group proposal except that the Monitor proposal allows generators to select the fuel they want to use while the PJM proposal has PJM choose the fuel. 

Scarpignato said the proposals would go beyond fixing an issue identified by the Energy Management System vendor and would sacrifice some of the current flexibility in the day-ahead market. PJM’s Keyur Patel responded that the status quo has the most optimal schedule selection process and there would be trade-offs to meet the technical requirements of adding multi-schedule modeling capability to the MCE. 

Sotkiewicz urged PJM to explore whether hardware and software changes could resolve the computational limitations to allow the status quo schedule selection to be retained. 

“We’re sacrificing optimality on solutions because we’re unwilling to make a lot of the investments in hardware, software, parallel processing,” he said. “We’re drifting away from optimality, and we could pour more money into resources on this to get to the right answer.” 

Patel said PJM looks at upgrading its hardware every two to three years, but the benefits of replacing servers are limited as the software is integrated. He said solution times are expected to improve as the software is fine-tuned after being launched. 

New Winterization Requirements Endorsed

The committee endorsed revisions to Manual 14D, which details operational requirements for generators, to require that resources prepare for winter conditions by either developing their own winterization checklist or following the list produced by PJM, which itself was expanded under the proposal. (See “Generation Winterization Requirements Endorsed,” PJM OC Briefs: Nov. 2, 2023.) 

The revised checklist added guidance for combustion turbine intake preparation, drawing from NERC’s Lessons Learned. It prompts generation owners to assess safety hazards posed by snow and ice accumulation on wind and solar facilities, inspect commodities and resources that may be used in severe winter weather, and consider adding a “freeze protection operator” staff member to inspect critical equipment. 

The revisions also included clarifying changes such as replacing definitions with references to corresponding sections of the governing documents, specifying that the critical information and reporting requirements include a need to notify PJM dispatch by phone and several administrative changes. 

PJM Presents Regulation Market Rework

PJM’s Danielle Croop presented the proposal recommended by the Regulation Market Design Senior Task Force (RMDSTF) to redesign the regulation market to have one price signal and two products representing a resource’s ability to adjust its output up or down. The proposal carried 86% support at the RMDSTF during an August vote, with two competing proposals receiving 26% and 6%. 

The new price signal would be easier for market participants to follow and would result in all resources having the same settlement process, Croop said. Resources would be able to participate as being only regulation up (RegUp), regulation down (RegDn) or capable of doing both. The current market design has two price signals: Regulation D for resources that can modulate their output almost instantly and Regulation A for longer deployments. 

The proposal also would shift to a 30-minute clearing and commitment period, down from the hourly intervals used now; less testing required for new and returning regulation resources; a ramp-limited lost opportunity cost (LOC) calculation meant to avoid overestimating LOC; and a performance score based only on the precision of the response, rather than the average of the scoring of its response accuracy, delay and precision. The proposal would add an annual review of the market to consider if the changes the grid is experiencing during the clean energy transition necessitate any adjustment of the regulation requirement. 

Croop said the new scoring method would tend to be stricter, but still accurately capture resources’ performance when called upon. 

The market overhaul implementation would be split into two phases, with the first year introducing all the changes except the RegUp and RegDn products, which would be added in the second year. 

American Electric Power’s Brock Ondayko said the proposal may impact the ability for energy storage to provide regulation service, as those resources typically would be able to provide both RegUp and RegDn but would be able to move in one direction only if they are fully charged or depleted. 

Croop told RTO Insider that there wouldn’t be a change to how batteries participate in the market, and they would be able to remain in the market when fully charged or depleted. However, they may experience a reduction in their performance score if they are not able to follow the price signal. 

Carl Johnson, representing the PJM Public Power Coalition, said he was concerned the task force would work around the edges of an RTO proposal FERC rejected in 2018 and was glad to see an entirely new market design proposal came out of the group’s deliberations. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.) 

Independent Market Monitor Joe Bowring presented several concerns with the proposal, arguing the bidirectional price signal is not fully developed. He also argued against calculating LOC based on how a resource is dispatched over multiple regulation intervals, preferring it be reset for each half-hour period, and said PJM’s approach would result in significant overpayment of opportunity costs. 

“There is no good reason to approve a market design that has not been developed or tested. In addition, the joint optimization with the energy market would make the energy market less efficient,” Bowring said. 

PJM, Monitor Urge Participants to Complete Account Manager Migration

PJM’s Chidi Ofoegbu said the Dec. 13 deadline for eDART accounts to be migrated to the new Account Manager (AM) software is fast approaching with less than a fifth of users completing the transfer process. Of the 7,933 accounts in eDART across 758 companies, 1,433 have a corresponding account in AM, representing a completion rate of about 18%. (See “Migration of eDART Accounts to New Platform Underway,” PJM PC/TEAC Briefs: Aug. 8, 2023.) 

Once the deadline arrives, active eDART accounts will have their access revoked and users will not be able to access their accounts, rendering them unable to create generation or transmission tickers, respond to data requests or view reports in eDART. 

Bowring said it would be difficult to participate in PJM’s markets and complete required tasks without access to the online tools. 

“Key market functions depend on eDART. If you do not have access to eDART it’s hard to see how you could function in the markets. … The numbers now are frighteningly low given how close the deadline is,” he said. 

Members Committee

3 Revisions to Stakeholder Process Endorsed

The Members Committee endorsed revisions to Manual 34, which outlines the stakeholder process, to change the voting structure at the MRC and MC, clarify the relationship between the higher and lower committees, and set deadlines for adding items to committee agendas. (See “3 Changes to Stakeholder Process Proposed,” PJM MRC Briefs: Oct. 25, 2023.) 

Under language brought by Dayton Light and Power (DLP), the senior standing committees continue to vote on any main motions before considering alternates. Those alternates now would be voted on simultaneously, similar to the lower committees. 

One of the two proposals by Exelon clarifies that the MRC and MC hold final authority on topics considered by task forces and the lower committees, which have the role of setting the order of proposal votes at senior committees. The other revision requires that requests to add items to committee agendas must be made at least seven days in advance and include a summary of any action sought by the committee in order to be considered timely. Committee chairs would retain discretion to consider untimely items should they be time-sensitive or the result of unforeseen disruptions, or non-voting items such as informational reports. 

Several states objected to the two Exelon revisions and abstained from voting on the DLP proposal. Four industrial consumers also abstained on the DLP language. 

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North Carolina Regulators Combine Duke’s IRP with Carbon Plan

The North Carolina Utilities Commission issued an order Monday combining Duke Energy’s integrated resource plan with its carbon plan. 

The regulator approved the firm’s first carbon plan late last year, separately from the IRP process. (See North Carolina Regulators Approve Duke’s 1st Carbon Plan.) 

For regulatory efficiency, the two are going to be rolled into one process, with Duke filing a proposal earlier this year after consulting with the NCUC’s public staff for weeks. 

The utility will have to file a consolidated carbon plan and integrated resource plan (CPIRP) every two years for approval, which will have Duke continuing to meet its obligation to serve load in its territory while making long-term plans for carbon neutrality. State law requires a 70% cut in carbon emissions by 2030 and carbon neutrality by 2050. 

The plans will have to include several different resource portfolios so that a range of demand-side, supply-side, energy storage and other technologies can be fairly evaluated in the process. Those plans are required to either maintain or improve upon the adequacy and reliability of the existing grid. 

The NCUC agreed with the North Carolina Attorney General’s Office that at least one of the plans Duke submits needs to meet the 2030 carbon target. Legislation gave the commission the authority to delay that target, and it needs the planning data to make that decision, it said. 

The CPIRPs will require near-term action plans that identify specific investments in the demand and supply sides, procurements and retirement activities, and upgrades to the transmission system needed to interconnect new resources. The attorney general suggested that Duke be required to identify whether those near-term plans can support the resource portfolios in the CPIRP and, if not, any additional activities that would bring the company on track to meet longer-term carbon goals. The commission agreed. 

The NCUC declined to include transmission planning into the CPIRPs directly, but it agreed with some intervenors that the carbon plans should inform it. Duke will have to discuss how the most recently approved CPIRP was incorporated into its transmission planning process, the regulator said. 

The CPIRP process includes some stakeholder meetings before it is filed with the NCUC and that is meant to produce a report on what was discussed during that time. The NCUC said that the report will have to include a list of which stakeholder ideas Duke decided to adopt in its initial plan, which will give the commission some clarity on how well the early stakeholder discussions are working. 

The Clean Energy Buyers Association asked the NCUC to require Duke to include information on the costs and benefits of participating in the Southeast Energy Exchange Market (SEEM) and whether participating in an RTO, especially PJM (which neighbors Duke’s territory), would be cheaper overall. 

Duke opposed CEBA’s request, saying nothing in the relevant statutes on carbon plans and IRPs discusses wholesale market participation. The utility also said it would join an RTO only if state or federal legislation required that, which is not the case now. 

IRP modeling also is not capable of capturing the 15-minute granularity of SEEM transactions over a long planning period, Duke said. 

The current rules already are enough for Duke to consider wholesale issues, and requiring the kind of study CEBA wants would only add unnecessary costs given the lack of legislation requiring RTO membership. 

Duke filed its initial CPIRP in August, and said it followed the proposal that was pending at the NCUC at the time. The commission deemed that August filing in compliance with the order issued Monday. 

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NYISO to Keep Gas Peakers Online to Solve NYC Reliability Need

NYISO announced Nov. 20 it will keep two natural gas peaker plants in Brooklyn operational beyond their state-mandated retirement to address a generation shortfall in New York City.

The ISO’s Nov. 20 Short-Term Reliability Process Report said the Gowanus 2 & 3 and Narrows 1 & 2 barge-mounted power plants will remain online to help plug a 446-MW reliability deficit.

The deficit was identified in NYISO’s second quarter Short Term Assessment of Reliability, which said the city would be short for up to nine hours on the peak day in 2025 during expected weather conditions, assuming forecasted economic growth and policy-driven increases in demand. (See NYC to Fall 446 MW Short for 2025, NYISO Reports.)

The two facilities, owned by Astoria Generating Co., collectively can generate 564.9 MW and contribute 508 MW toward New York City’s transmission security margin.

The Gowanus facility has been operational since 1971 and compromises 32 simple-cycle combustion turbines, each with a nameplate value of 20 MW. The Narrows facility has been running 32 similar units since 1972, but with a nameplate value of 22 MW.

NYISO’s decision highlights the challenges New York faces in balancing reliability with environmental regulations and increasing energy demands under electrification.

NYISO Chief Operating Officer Emilie Nelson said the ISO is committed to a reliable transition to emissions-free resources and is aware of how fossil fuel plants — a source of ozone-contributing pollutants — affect surrounding communities. “This means running these units only when conditions require, and closing them when no longer necessary for reliability,” she said.

The ISO’s report says Gowanus and Narrows help New York City’s bulk power transmission system during unexpected facility outages or during extreme weather conditions like a heat wave when other power producers may become unavailable.

The units were set to retire May 1, 2025, to comply with the Department of Environmental Conservation’s 2019 Peaker Rule, which imposes nitrogen oxide emissions limits on fossil fuel plants. NYISO reports that 1,027 MW of peakers had ceased or limited their operation as of May 1, 2023, with an additional 590 MW scheduled to go offline by the 2025 deadline, all of them in New York City.

The peaker rule allows plants needed for reliability to remain operational until May 1, 2027, with a potential two-year extension to May 1, 2029.

NYISO anticipates improved generation margins in 2026 with completion of the 339-mile Champlain Hudson Power Express, which will carry up to 1,250 MW of hydropower from Quebec to New York City. If the project is delayed, or if more power plants are retired, or demand exceeds forecasts, the city could experience a reliability shortfall for up to 10 years.

Even with CHPE, “the margin gradually erodes through time thereafter as expected demand for electricity grows,” the ISO said. And it noted that while CHPE will help summer reliability, it is not expected to provide any capacity in the winter. New York’s winter electricity demand is forecast to increase over the next decade.

New York City transmission security margins with designated peakers | NYISO

The decision to keep the Gowanus and Narrows plants operational was a last resort, made after alternative proposals failed to present viable solutions that could address the 446-MW deficiency and be installed before 2025.

Con Edison proposed installing roughly 16 miles of 345-kV underground cables and associated stations. The ISO said the proposal was rejected because the project would not be completed until “well after” the CHPE’s anticipated in-service date.

Orenda, a renewable energy storage supplier, proposed a reliability must-run solution involving small battery storage projects interconnected with Con Ed’s distribution system. However, the ISO deemed this output — a maximum of 27 MW over four hours, or up to 12 MW over the nine-hour duration of the need — insufficient. “The total capability of the Orenda batteries is less than the output of the smallest Gowanus or Narrows peaker,” the ISO noted.

The ISO said it received no market-based proposals to solve the shortfall.

“NYISO is working very closely with the DEC, the Public Service Commission and NYSERDA [the New York State Research and Development Authority] as we address the reliability need in New York City and a reliable transition to renewable resources for the state,” Nelson said.

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NRG’s Gutierrez Steps down as CEO, Director

Mauricio Gutierrez stepped down Nov. 17 as NRG Energy’s CEO, an apparent victim of a push by activist investor Elliott Investment Management to reshape the organization’s leadership. 

NRG said that Gutierrez had resigned as CEO and as a member of the board of directors. In a filing with the U.S. Securities and Exchange Commission, NRG said the resignation “was not the result of any disagreement with the company” or any matter concerning its operations, policies or practices. 

However, Elliott, owner of more than 13% of NRG’s shares, has been openly critical of the company’s $5.2 billion acquisition of Vivint Smart Home earlier this year. Elliott has called the purchase “the worst deal of the decade” and called on the company to focus on returning capital to shareholders. 

Interim CEO Lawrence Coben, the board’s chair, said in NRG’s press release that Vivint’s integration is “well underway.” 

“As a differentiated company at the intersection of energy and smart home technology, NRG has clear upside-value creation opportunities,” he said. 

The board has begun seeking a permanent CEO and has retained a search firm to help. 

“Today, NRG is in a position of strength. The board is confident in NRG’s strategic direction,” Coben said. “We extend our appreciation to Mauricio for his contributions in helping to build NRG’s solid foundation as we prepare for the next generation of leadership.” 

Gutierrez joined NRG in 2004 and served in several leadership positions before being named CEO in December 2015. 

The Houston-based company has a large presence in Texas. Reliant Energy, its electric retailer, owns about 40% of ERCOT’s deregulated market, and NRG accounts for about 20% of the grid operator’s fleet, noted Stoic Energy CEO Doug Lewin. 

“This is big Texas energy news. [NRG has] been among the loudest voices for a capacity market, even though their power plants are often broken down when most needed,” he wrote on X, the social media platform formerly known as Twitter. 

NRG said it will also conduct a comprehensive review of its operations and cost structure to “further enhance capital return to shareholders” and to identify additional efficiency opportunities. 

Elliott partner John Pike and portfolio manager Bobby Xu said the fund invested in NRG “because we believed that a renewed focus on best-in-class operations and returns-driven capital allocation would strengthen NRG and enable it to deliver significant upside for shareholders.” 

NRG also said Monday that, pursuant to a cooperation agreement with Elliott, it has added four new independent directors to the board: 

    • Marwan Fawaz, former executive adviser for Google and its parent company, Alphabet, and former CEO of Nest and Motorola Home; 
    • Kevin Howell, former Dynegy COO and former regional president for NRG Texas; 
    • Alex Pourbaix, CEO of Cenovus Energy; and 
    • Marcie Zlotnik, co-founder and COO of Texas retailer StarTex Power. 

The four new directors were identified as part of NRG’s board “refreshment process” in collaboration with Elliott, the company said. They increase the board’s membership to 13, 12 of whom are independent. NRG said it expects to reduce the board’s size to 11 members in the second half of 2024. 

Howell and Pourbaix will join the board’s CEO search committee, with fellow independent Directors Lisa Donohue, (the chair), Antonio Carrillo and Heather Cox. Incumbent Director Anne Schaumburg was appointed lead independent director. 

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West-Wide Governance Pathway Group Digs into its Work

The committee tasked with laying the groundwork for an independent Western RTO confronts a complex set of challenges on an ambitious timeline as it seeks to help CAISO outpace SPP in the contest to organize the region’s electricity market.

Chief among the challenges: raising the money needed to finance the effort, which a group of Western state utility commissioners kicked off in July to boost the prospects of establishing a single RTO that pointedly includes California. The commissioners proposed the plan just as SPP’s Market+ day-ahead market offering began making headway against CAISO’s Extended Day-Ahead Market. (See Regulators Propose New Independent Western RTO.)

Members of the West-Wide Governance Pathway Initiative’s (WWGPI) Launch Committee described the work ahead during a virtual stakeholder update Nov. 17, just days after the group released its mission statement and charter.

“The real mission is that we’re looking to create an independent entity with independent governance that is capable of overseeing an expansive suite of West-wide wholesale electricity market activities and related functions,” said Launch Committee Co-chair Pam Sporborg, director of transmission and market services at Portland General Electric.

Sporborg described the “core principles” — set out in the mission statement — guiding the committee’s work:

    • Establish an entity with the largest possible footprint in the West — including California — while maximizing consumer benefits.
    • Ensure independent governance for all market operations.
    • Preserve and build on existing CAISO market structures, including the Western Energy Imbalance Market (WEIM) and EDAM.
    • Minimize duplication of costs for both the market operator and its participants.
    • Create a structure flexible enough to support a full complement of RTO services while not requiring participating organizations to join a full RTO if they choose not to.

Funding Needed

In the month since it began meeting, the Launch Committee has created work groups to address specific “focus areas” to tackle issues in establishing the independent entity.

Organizational structure and funding will be the key focus of the Administrative Work Group, according to Jim Shetler, the group’s co-chair. Shetler is general manager of the Balancing Authority of Northern California (BANC), which in August became the second organization to commit to joining CAISO’s EDAM. (See BANC Moving to Join CAISO’s EDAM.)

During the Nov. 17 meeting, Shetler said his group is evaluating whether the WWGPI should form a 501(c)(3) or “more of an informal association kind of structure.” It also will determine whether the effort requires an initial “fiscal sponsor.”

“We are stood up to do a lot of work and look at the governance structure alternatives for an independent oversight, but we don’t have any dollars to do that right this minute, so we are looking at where we would get funding, both in the near term and long term,” he said.

Near-term funding could come from “seed donations” by electric sector participants who’ve already expressed willingness to put up the money, Shetler said. The work group could also seek grants from foundations.

For the longer term, the group is working with Western state officials to file a grant request with the Department of Energy for federal funding, which likely would not materialize until the middle of 2024.

The group is examining the full scope of the WWGPI and the costs associated with administrative setup, outreach and communications, and legal analysis.

“I would anticipate we would have a better handle on what we think the dollars and cents would require … in the early to mid-December timeframe,” Shetler said.

Laura Trolese, director of Western markets and strategy at The Energy Authority, asked where the funding would be found for the entity’s foundational board of directors, which is slated to be seated in January.

“And maybe just a note that it could be problematic to have funding for that board that is either not or perceived not to be independent,” Trolese added.

Shetler said his group recognizes the need for any funding to be “unbiased and not influential.”

“Some of the federal dollars that might be coming our way [are] an option for that, but we have not had any detailed discussions yet on what that funding source may me, though we acknowledge and recognize we have to make sure that it’s viewed as being independent,” he said.

“We want the funding to really come from a broad and diverse set of entities,” said the Launch Committee’s other co-chair, Kathleen Staks, executive director of Western Freedom, an industry coalition that advocates for a single Western RTO.

Legal Questions

Examination of legal issues will fall to the Launch Committee’s Priority Functions and Scope Work Group.

The group is charged with identifying “concrete options” for a market structure that integrates California, said the group’s co-chair, Spencer Gray.

“Our goal is to define a range of solutions — or pathway options — that are related to tariff management for the markets and other services [and] what the governance structure looks like for a potential new regional entity,” said Gray, executive director of the Northwest & Intermountain Power Producers Coalition (NIPPC).

The group will address legal questions associated with creating a regional entity, including what is possible under existing law and what are any associated litigation risks. It also will investigate the minimum changes needed in California law to alter CAISO’s governance and operations to enable some of the options.

“And we want to be thorough in asking those questions without presenting a preferred solution yet; this can be viewed more like a solution set,” Gray said.

While the single tariff covering CAISO and the WEIM gives both the ISO Board of Governors and the WEIM Governing Body voting rights, only the ISO board has the right to file rule changes with FERC, noted work group member Jeff Nelson, manager of market design and analysis at Southern California Edison.

“So we’re starting with that place and sort of asking questions — what sort of things could move around? And what would require new tariffs?” Nelson said. The group also will explore what it would require for an independent entity to have “absolute rights” over market rules “without the ISO’s current board having any say in those.”

Gray said many stakeholders, including NIPPC, filed comments with the WWGPI asking for that kind of legal analysis “because there’s been so much thinking about what are the options for greater autonomy for a regional entity in the context of the Western EIM and EDAM.”

Communications, Outreach and Transparency

“Talking about markets to a general audience is quite challenging, as many of you know, so anyone who knows how to talk about this in an easily understandable way, we’re always looking to improve,” said the Northwest Energy Coalition’s Ben Otto, co-chair of the Launch Committee’s Communications and Outreach Work Group.

The group’s focus will be threefold, Otto said, including supporting the committee’s ability to communicate with WWGPI stakeholders; acting as a liaison between stakeholders and the work groups to “collect and share feedback”; and leading outreach with stakeholders, the media and others.

“Our goal here is just to be able to clearly communicate out to the public about what we’re doing — our goals, our processes and our timelines,” Otto said of the last point.

Launch Committee meetings currently are held in private. Allison Mace, manager of market policy and analysis at the Bonneville Power Administration, asked whether the committee plans to open future meetings to the public.

“We’re continuing to have these types of public forums where we are able to get the input and share the updates on the Launch Committee, but … there will be other times where the Launch Committee will need to be able to discuss and deliberate about the feedback received in these meetings amongst ourselves,” Sporborg said.

Staks said the committee is considering whether to hold additional topical public meetings, such as one to cover the legal analyses and scenarios outlined by Gray.

Shetler pointed out that the new charter states any decisions by the Launch Committee will be made in public session.

“We really are trying to make sure that this is a very transparent process,” Staks said.

The Launch Committee will hold its next public update Dec. 15.

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FERC Continues Deliberations on PJM Real-time Values

FERC on Thursday deferred making a decision on PJM’s proposal in response to a 2021 order directing the RTO to show cause as to why its rules regarding parameter-limited offers are just and reasonable (EL21-78). 

The docket was on the agenda for the commission’s monthly open meeting, but was struck. 

FERC had found that PJM’s tariff does not require that offers be selected to arrive at the lowest total costs based on parameter-limited offers, but instead requires that resources be committed based on the lowest-cost offers. It also found that the RTO’s governing documents did not appear to define what should happen if a generator fails to operate according to the parameters in its selected offer. (See FERC Issues Show-cause Order on PJM Parameter-limited Offers.) 

“PJM is disappointed that FERC did not act on this show-cause order today,” RTO spokesperson Jeffrey Shields said. “PJM will continue, in the meantime, to work with generation owners to ensure that unit operating parameters are being updated in an effective manner to inform PJM Dispatch of generator availability, particularly during periods of cold temperatures during the upcoming winter.” 

The RTO and its stakeholders have been eagerly awaiting a decision. On the day before the commission’s meeting, the PJM Markets and Reliability Committee opted to delay a vote on two competing proposals to define how offers will be selected under the multi-schedule modeling functionality the RTO is planning to add to its market clearing engine. PJM and its Independent Market Monitor had filed a joint motion for expedited action on Sept. 11, urging the commission to “issue an order as soon as practicable.” 

Shields said it’s still expected that the MRC will move forward with a vote in December. 

“PJM stakeholders voted to postpone the vote by one month, so a stakeholder vote is still scheduled to take place in December. While a FERC order in EL21-78 would have been informative, it is not necessary for stakeholders to proceed with a vote,” he said. 

During the Electric Gas Coordination Senior Task Force meeting Nov. 14, Paul Sotkiewicz, president of E-Cubed Policy Associates, said real-time values — which the Monitor and PJM proposed to replace with temporary exceptions in response to the commission’s show-cause order — could be the “linchpin” of addressing the incongruities between the gas and electric markets. 

The joint proposal would remove the deadline for submitting temporary exceptions by the close of the day-ahead market to allow them to be used in the real-time market as well. 

“The simple solution is to … permit real-time submissions for temporary exceptions,” the Monitor wrote. “This would let resources communicate to PJM their changed operational capability without delay, while maintaining the tariff requirements and standard for review that protect against withholding.” 

Monitor Joe Bowring told RTO Insider that real-time values would create a pathway for market sellers to notify and explain to PJM that they are unable to operate according to the schedule that they were dispatched and seek an exception from energy market penalties for not being able to do so. He said a similar capability already exists in the day-ahead market, but if a resource is affected by an issue affecting their performance in real time, no corresponding structure exists. 

“What we were asking for is to expand the existing process into the real-time [market],” Bowring said. 

The real-time values proposal would not interact with the capacity market and would not provide an exception from Capacity Performance penalties during a performance assessment interval, Bowring said. 

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Treasury Department NOPR Seeks to Clarify IRA’s ITC Rules

The Treasury Department on Nov. 17 released guidelines for the Inflation Reduction Act’s (IRA) investment tax credits (ITC) for clean energy projects, allowing developers to claim the credits for equipment used to connect a solar or wind project to the grid, as well as for standalone energy storage projects.

Under the IRA, both homeowners and commercial clean energy developers can qualify for a 30% ITC through 2032 or possibly 2033.

The department’s notice of proposed rulemaking (NOPR) specifically permits developers to claim the credit for equipment that is a “functionally interdependent” component of a system that generates clean energy, including inverters, converters, and wires and cables up to and including a transformer in a substation.

The 127-page NOPR defines system components as functionally interdependent “if the placing in service of each component is dependent upon the placing in service of each of the other components in order to generate or to store electricity, thermal energy or hydrogen.”

Examples in the proposed rule detail how interconnection equipment in a solar project or offshore wind project could be functionally interdependent and therefore included in the overall project costs for calculation of the ITC once a project has gone online.

The guidelines also provide a broad definition of the kinds of projects ― beyond solar and wind ― that will qualify for the ITC, including geothermal, hydrogen fuel cells, combined heat and power, and bioenergy.

The ITC for standalone storage is another major component of the new guidelines; it covers all technologies and chemistries ― lithium ion, vanadium flow and hydrogen ― as well as thermal energy storage technologies, such as geothermal heat pumps.

Prior to the IRA, the ITC could be claimed only for storage that was directly connected to and charged from a clean energy — solar or wind — project. Electric vehicle batteries and thermal storage used for heating swimming pools are not eligible for the credit.

At the same time, the guidelines include sections noting the proposed definitions of clean generation and storage may need to change as new technologies emerge.

The goal of these and other proposed rules in the guidelines is to provide “companies with clarity and certainty needed to secure financing and advance clean energy projects nationwide,” Deputy Secretary of the Treasury Wally Adeyemo said in a department press release.

The publication of the NOPR in the Federal Register, scheduled for Nov. 22, will begin a 60-day comment period, with a public hearing scheduled for Feb. 20, 2024.

Echoing Adeyemo, solar and renewable energy trade groups stressed the industry’s need for clear and stable tax incentives and, while welcoming the proposed guidelines, cautioned that further details may need to be hammered out for developers to take full advantage of the IRA’s incentives and increase renewable energy generation in the U.S.

“We remain impressed by the administration’s commitment to fully maximizing the economic and environmental benefits of [the IRA], and plan to continue working closely with Treasury in support of fair, timely and practicable final rules across all facets of the clean energy tax package,” said Gregory Wetstone, CEO of the American Council on Renewable Energy.

Abigail Ross Hopper, CEO of the Solar Energy Industries Association, hailed the inclusion of standalone storage in the ITC as a big win for the industry. The proposed guidelines are “good news for America’s clean energy economy. However, given the economic headwinds that many solar and storage companies are facing, we are continuing to fully evaluate the details in this guidance to guard against any potential unintended consequences that might undermine our ability to rapidly deploy clean energy projects of all sizes.”

A Developer’s View

When first passed, the ITC provisions of the IRA were seen as a potential bonanza for the solar industry, reinstating the full 30% ITC for a decade, as opposed to the gradual phaseout passed in the Energy Act of 2020. By August 2022, when President Biden signed the IRA into law, the ITC had been reduced to 26%,

The law also allows nonprofits, schools, and city and local governments ― which previously could not benefit from the ITC ― to receive a direct payment of the credits or transfer of them to third parties. Other provisions offer additional credits of 10% each for projects meeting domestic content requirements or located in low-income or “energy” communities ― areas that have lost jobs and tax revenues due to the closing of fossil fuel plants.

But the tax credits for commercial projects also come with requirements that developers pay prevailing wages and bring in registered apprenticeship programs. Any projects not meeting those requirements would be eligible for only a 6% ITC.

In addition, the prevailing wage and apprenticeship requirements apply to any workers employed for the operation, maintenance or repair of a project for a period of five years from the date it goes online.

The IRA has driven expansion in the clean energy sector, especially in domestic supply chains. Solar and storage companies have announced $100 billion in new investments across the U.S. since the law was passed, according to Hopper.

But while growing, the industry continues to be plagued by supply chain, interconnection and other delays. According to a recent report from the American Clean Power Association, more than 16 GW of clean energy projects have been delayed this year, about two-thirds of them solar.

The complexity and slow rollout of tax credit guidance from the Treasury Department — coupled with inflation and delays — have meant uncertainty for some developers as investors continue to wait on the sidelines.

In an interview with NetZero Insider, Mike Healy, CEO of New Columbia Solar, a residential and commercial installer based in Washington, D.C., said a major drawback of the ITC as structured is that it’s not available to developers or homeowners until a project comes online.

“When you’re developing a solar project, you’re underwriting the economics way before you get to interconnection,” said Healy, who also is president of the board of the Chesapeake Solar and Storage Association (CHESSA), the regional trade group for D.C., Maryland and Virginia.

“Yet, with the IRA, you can only submit at interconnection, and then you get told afterwards [if a project qualifies], so it’s not a great process,” he said, noting that his personal views are not CHESSA’s.

The IRA and ITC will be “transformative,” Healy said, but solar’s long development cycle and uncertainty about tax credits can result in fewer benefits for customers. Nailing down the ITC “as early as possible in the development cycle is the only real way to underwrite it to make sure that all parties involved in the solar process get the benefit,” he said.

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New Mexico Adopts California Standards for Clean Cars, Trucks

New Mexico regulators on Nov. 16 adopted zero-emission requirements for cars and trucks, a move that proponents say will improve air quality, fight climate change and increase consumers’ choice of vehicles. 

The state Environmental Improvement Board (EIB) voted to adopt California’s Advanced Clean Cars II rules — but with a twist. In California, ACC II will increase manufacturers’ supply of zero-emission cars each year through 2035, when the sale of gas-powered cars will be banned with the exception of a limited number of plug-in hybrids. (See California Adopts Rule Banning Gas-powered Car Sales in 2035.) 

In contrast, New Mexico has opted to follow ACC II through 2032, when 82% of cars that manufacturers deliver for sale must be zero-emission. Colorado took a similar approach: The state’s Air Quality Control Commission last month adopted ACC II with a maximum ZEV requirement of 82% in 2032. 

Clean Cars, Trucks

In New Mexico, the EIB also voted Nov. 16 to adopt California’s Advanced Clean Trucks (ACT), a rule that requires an increasing percentage of medium- and heavy-duty trucks sold in the state to be zero-emission. ACC II and ACT in New Mexico will begin with vehicle model year 2027. 

The rules package also includes more stringent emission standards for internal combustion vehicles. The package was adopted during a joint hearing of the EIB and the Albuquerque-Bernalillo County Air Quality Control Board, which governs air quality within Bernalillo County. 

Following the board votes, the New Mexico Environment Department (NMED) said the rules package “will significantly increase consumer choice for New Mexicans by assuring new and used zero-emission vehicles are available for lease or purchase.” 

The rules also reflect New Mexico Gov. Michelle Lujan Grisham’s commitment to a “cleaner, greener future,” NMED said. Lujan Grisham (D) announced in July that the state would enact the clean cars and trucks rules. 

Adoption of the rules was welcomed by a coalition of climate, environmental justice and business groups known as New Mexico Clean Air. 

“New Mexicans will be able to breathe easier, buy more clean, affordable vehicles and help put the brakes on climate change with the adoption of Clean Cars and Trucks Standards,” Alexis Mena, New Mexico policy director at the Natural Resources Defense Council, said in a statement. 

Opponents said the California rules are a poor fit for New Mexico. 

Nicholas Maxwell, a resident of rural Lea County, said New Mexico’s path must account for “the vast rural spaces and the spirit of independence that define us.” 

“The economic impact of these proposed standards shouldn’t be underestimated,” Maxwell told the EIB. “We should avoid speeding toward a future that our current infrastructure and economy are not ready to support.” 

Keeping Up with California

The federal Clean Air Act allows California to adopt its own vehicle emission standards if they are at least as stringent as the federal standards. The state must receive an EPA waiver before it can enforce its own emission rules. 

Other states may adopt California’s rules or stick with the federal emission standards. 

New Mexico adopted ACC II’s predecessor, Advanced Clean Cars, in May 2022. (See NM Adopts Calif. Advanced Clean Cars Rules.) Just a few months later, in August 2022, California updated its rules with the adoption of ACC II. 

As a result, New Mexico no longer will be able to enforce the first version of Advanced Clean Cars after California receives an EPA waiver for ACC II, according to Claudia Borchert, NMED’s climate change bureau chief. 

“Without these amendments, these rules as they exist today will be unenforceable — once EPA as anticipated grants a waiver for ACC II,” Borchert said during the EIB hearing. 

Under ACC II, automakers face a steep jump to deliver 43% ZEVs for sale in model year 2027. 

But Borchert said manufacturers have a number of ways to earn credits and reduce the actual number of ZEVs they must deliver in a particular year.  

They may apply early action credits earned from ZEVs supplied before model year 2027. Up to 20% of the ZEV requirement may be met with plug-in hybrid electric vehicles (PHEVs). Credits may be bought or sold from other automakers or banked for later.  

And manufacturers may help fill a deficit in one state with credits from oversupplying ZEVs in another ACC II state. 

In addition, extra credits may be earned by selling previously leased ZEVs through a financial assistance program, providing new ZEVs at a discount to community-based clean mobility programs or delivering less expensive new ZEVs or PHEVs. For the latter, the extra credit is available for zero-emission cars with a manufacturer’s suggested retail price of $20,250 or less and light trucks with an MSRP of $26,670 or less. 

If manufacturers take full advantage of the various credits, the minimum ZEV delivery requirements drop to as low as 8% in model year 2027, Borchert said in written testimony. 

“That 8% target for the first model year of compliance is not much greater than New Mexico’s projected 2023 market share of BEVs of 4.5%,” Borchert said.