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November 6, 2024

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NYISO Braces for the Coming Winter

Winter Operating Study Report

NYISO’s Operating Committee on Nov. 16 approved the winter 2023/24 operating study report, which found New York’s bulk power system can operate reliably this winter based on calculated transfer capabilities.

The report by the ISO’s Operating Studies Task Force estimates internal and external thermal transfer capabilities for the upcoming winter season based on forecast load and dispatch assumptions, as well as any generation or transmission changes since last year. The external analysis covers NYISO’s adjacent balance areas of ISO-NE, PJM and Ontario’s IESO.

The task force reported an increase in internal thermal transfer limits for the Total East (1,525 MW) and Central East (1,825 MW) interfaces due to Segments A and B of the Alternating Current transmission project, which was designed  to increase the deliveries of renewable power to downstate New York.

Changes in cross-state and inter-state winter thermal transfer limits for 2022/23 | NYISO

Changes to external transfer limits also were seen. The ISO-NE-to-NYISO interface saw a decrease of 225 MW due to the reactivation of the Sprainbrook-East Garden City (Y49) 345-kV line. Meanwhile, the NYISO-to-PJM interface increased by 250 MW due to changes in PJM’s dispatch assumptions and the PJM-to-NYISO interface increased by 75 MW due to the redistribution of flows from the Segment A and B project.

NYISO reported that 639 MW of fossil-fuel based generating capacity was deactivated and that 336 MW of renewable generation was added since last year’s study. The appendices are posted online.

Winter Capacity Assessment

Aaron Markham, NYISO vice president of operations, informed the OC that while NYISO expects sufficient capacity for 50/50 peak forecast winter conditions, there is a risk of shortfalls during extreme weather events if non-firm fuel resources become unavailable.

The assessment projects winter generation capacity of 39,668 MW, approximately 750 MW lower than last year’s assessment, due primarily to the retirement of peaker units.

“Over the last approximately five years, we’ve seen about a 2,400-MW reduction in the margin as a result of retirements,” Markham said. “Continued reductions in winter capacity, disruptions in fuel supply or other concerns might result in operational challenges, especially during extreme cold weather events.”

2022 and 2023 winter capacity assessment and comparison | NYISO

Projected winter capacity margins for normal and extreme weather conditions with only firm fuel resources available:

    • 2,641-MW surplus capacity margin for 50-50 peak forecast conditions
    • -161-MW deficit capacity margin for 99-1 peak forecast conditions

Projected winter capacity margins for normal and extreme weather conditions with non-firm fuel available:

    • 9,135-MW capacity margin for 50-50 peak forecast conditions
    • 6,333-MW capacity margin for 99-1 peak forecast conditions

Projected firm fuel generation potentially unavailable at high load or temperature conditions (NYISO 2023 Gold Book, Table I-20):

    • 114 MW lost for 90-10 daily average temperature (5 F)
    • 707 MW lost for 99-1 daily average temperature (-2 F)
    • 707 MW lost for 90-10 daily minimum temperature (0 F)
    • 3,441 MW Lost for 99-1 daily minimum temperature (-8 F)

Markham said NYISO will continue monitoring winter conditions and communicate any emergencies to stakeholders. The ISO is continuing to review the 11 recommendations from the FERC and NERC joint inquiry into the electric outages caused by Winter Storm Elliott. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.)

Matt Cinadr, a power systems operations specialist with The E Cubed Co., revisited a stakeholder concern regarding the treatment of special case resources by NYISO, saying the assessment’s findings highlight that these resources should not be overlooked. (See Providers See ‘Mixed Signals’ on Demand Response in NYISO.) “I don’t think anything should be done to push SCRs further out of the market,” he said, “there is value in the [802 MW of SCRs] being shown in your assessment.”

OC Election

The OC elected James Kane, senior energy market adviser with the New York Power Authority, as the committee’s new vice chair. Kane co-chaired the Electric System Planning Working Group in 2021.

October Operations

Markham also told the OC that October’s load peaked at 21,735 MW on Oct. 4, recorded its minimum load of 11,890 MW on Oct. 8, and added 73 MW of behind-the-meter solar since the previous month.

He added that the Oct. 14 annual solar eclipse had a minor impact on BTM production, affecting only 100 MW, significantly less than the anticipated 700 MW. (See “Eclipse Preparation,” NYISO Business Issues Committee Briefs: Sept. 14, 2023.)

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DOE Offers $3.5B for Domestic Battery Manufacturing, $444M for Carbon Storage

The U.S. Department of Energy this week announced it will funnel up to $3.5 billion to strengthen domestic production of batteries and more than $444 million to help fund 16 carbon storage projects in the works. 

Both initiatives are funded through the Infrastructure Investment and Jobs Act. 

The battery funding opportunity is the second stage of the total $6 billion set aside for the advancement of battery manufacturing and materials processing. In the first phase last year, DOE selected 15 companies to receive awards. 

Concept papers for projects seeking grants are due Jan. 9, 2024; full applications are due March 19 for a shot at receiving a minimum federal award of $50 million and a maximum of $300 million. Projects should focus on battery-grade processed critical minerals, battery precursor materials, battery components, and cell and pack manufacturing, DOE said. The process is being administered by the department’s Office of Manufacturing and Energy Supply Chains. 

The department said advanced batteries are “critical to national competitiveness” and will spur grid storage, increasingly resilient homes, and business and transportation electrification. The U.S. is aiming for electric vehicles to make up half of all new light-duty vehicle sales by 2030. 

Meanwhile the 16 CO2 storage project recipients across 12 states will “significantly and responsibly” reduce emissions, DOE said. Carbon management technologies are key to meeting the Biden administration’s goal of achieving net-zero emissions across all industries by 2050, it said. 

The carbon storage projects received funding under the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Initiative, managed by DOE’s Office of Fossil Energy and Carbon Management. Since the beginning of 2021, the office has released more than $816 million to advance carbon transport and storage. 

The U.S. needs a “concerted effort to build out the infrastructure” to store hundreds of millions of tons of CO2 each year in geologic storage facilities, DOE said. 

According to DOE, nine of the 16 carbon storage projects were selected for CarbonSAFE Phase II: Storage Complex Feasibility and will enter a feasibility study process. Those include potential CO2 storage reservoirs in regions that lack facilities in the Southeastern Illinois Basin, Virginia, California, Texas, South Florida, Mississippi, Alaska and Wyoming. Most projects in the feasibility study stage were awarded about $9 million apiece from the department. 

The other seven projects are in the planning and permitting stages and were recipients of CarbonSAFE Phase III: Site Characterization and Permitting. They received substantially more from the department. 

BP Carbon Solutions’ planned Project Crossroads, meant to decarbonize Northwestern Indiana through a storage hub at Whiting Refinery and wells in Indiana, Illinois and Michigan, received the most at $98 million. Tampa Electric received $88 million to perform a site characterization study for the proposed Polk Carbon Storage Complex located near an existing natural gas power station in Polk County, Fla. And the Southern States Energy Board of Georgia now has $55 million to work with to conduct a site characterization study of four geologic carbon storage systems for the Tri-State Carbon Capture and Storage Hub serving Ohio, Pennsylvania and West Virginia. 

Other projects intended for New Mexico, the Permian Basin and Louisiana received between $21 million and $41 million. 

Energy Secretary Jennifer Granholm said that the battery investments will give a “boost needed to build a robust domestic battery supply chain that is Made-in-America,” and the carbon storage projects will “help slow the harmful effects of climate change all while revitalizing local economies and delivering cleaner air to the American people.” 

US, China Vow More Climate Action

The pair of funding announcements coincided with the U.S. and China refreshing a pledge to build up renewable energy and oust planet-warming fossil fuel resources. 

The two countries agreed to redouble climate mitigation efforts and resume a working group on climate cooperation ahead of a Nov. 15 meeting of U.S. President Joe Biden and Chinese President Xi Jinping. The leaders’ first face-to-face meeting in a year occurred at an estate near San Francisco and corresponded with the Asia-Pacific Economic Cooperation summit. 

In a joint statement released Nov. 14 by the U.S. State Department, the two countries reaffirmed their commitment to meet the Paris Agreement’s target of holding global average temperature increase to “well below” 2 degrees Celsius and to pursue efforts to “keep 1.5 degrees Celsius within reach.” 

The two largest carbon-emitting countries promised to ramp up renewable energy deployment through 2030, develop at least five large-scale carbon capture and storage projects apiece by 2030, and pursue reforestation. They expressed support for G20 leaders’ pact in September to triple global renewable energy capacity by 2030. 

They also promised to restart the U.S.-China Energy Efficiency Forum “to deepen policy exchanges on energy-saving and carbon-reducing solutions in key areas including industry, buildings, transportation and equipment.” The U.S. and China vowed to “rise up to one of the greatest challenges of our time for present and future generations of humankind.” 

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MISO’s More Stringent Interconnection Queue Rules Go Before FERC

CARMEL, Ind. — MISO this month put its package of changes meant to downsize its crammed interconnection queue before FERC and plans to conduct a survey of its interconnection customers to gauge how many projects it should expect.

MISO split its package of stiffer interconnection rules into two filings at FERC. One tackles the increases to milestone payments and tighter land requirements, while the other proposes an annual megawatt cap on project submissions according to a feasibility formula (ER24-340 and ER24-341). MISO has determined there’s only so many potential generation projects it can simultaneously consider and still achieve accurate interconnection studies. (See MISO Relaxes Proposal on Stricter Queue Ruleset.)

To estimate how many submissions it might be facing when it finally opens its project application window in early 2024, MISO will conduct a survey of its interconnection customers on the number, size and type of projects they plan to submit.

During a Nov. 15 Planning Advisory Committee meeting, Director of Resource Utilization Andy Witmeier said MISO won’t publicly share the volume of projects it expects based off survey results. He said the idea is for MISO to have an idea internally of how many projects to prepare for.

Witmeier said MISO will publish a megawatt cap before it opens the 2023 cycle. He said even though applications have been pushed into the first quarter of 2024, MISO still will administer a 2024 queue cycle later in the year.

MISO delayed opening a queue application window this year because it wants the new queue rules in place first to deter another unmanageably large number of gigawatts from joining the queue.

Witmeier said the exact launch of the 2023 application window is contingent on FERC’s decisions on MISO’s pair of filings. MISO asked for a Jan. 22 FERC effective date. Stakeholders can comment on the filings at FERC through Dec. 4.

MISO has proposed that its megawatt cap be based on its ability to develop a reasonable dispatch based on the existing system with existing interconnection requests and the regional and subregional peak load in the study model.

A few weeks before it put its filings to FERC, MISO said a yearly megawatt cap on interconnection requests would be beneficial, incentivizing interconnection customers to submit their project request as soon as possible, instead of at deadline when the application window closes. MISO said that in turn would produce an earlier evaluation of the application, better coordination with transmission owners on selected points of interconnection and a public posting of accepted applications, allowing other developers to make more informed decisions regarding their own projects.

Witmeier said the package of stepped-up requirements would yield higher-quality projects, while the cap would allow a more viable study process for MISO.

“We do believe we need a backstop to limit the size of the queue study,” Witmeier said at an Oct. 11 Planning Advisory Committee meeting. He said scaled-back study cycles would result in more realistic modeling of potential system overloads and voltage support assumptions.

“I realize the package is not what everyone wants,” Witmeier said. But he said he views the more strict rules as becoming a “permanent fixture” of MISO’s interconnection queue.

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New England Transmission Owners Issue Draft Asset Condition Forecast Database

The New England Transmission Owners (NETOs) released a draft asset condition forecast database for the ISO-NE Planning Advisory Committee Nov. 15 and outlined updates to the asset condition project stakeholder review process.  

As the New England grid ages, the region has faced rising costs associated with asset condition upgrades needed to replace old, degraded or defunct transmission infrastructure. On multiple occasions earlier this year, the New England States Committee on Electricity pressed the NETOs for reforms and greater transparency to the asset condition planning process. (See States Press New England TOs on Asset Condition Projects.) 

The NETOs’ draft database includes information on the issue targeted by the project and the proposed solution, along with the estimated project cost, in-service date, location and primary equipment owner. It includes projects that are under construction, proposed and in the planning stages. The total combined cost estimate for all projects in the draft database is about $4.5 billion.  

Dave Burnham, representing the NETOs (Avangrid, Eversource, National Grid, Rhode Island Energy, Vermont Electric Power and Versant Power), said that the transmission owners plan to provide the forecast annually.  

Burnham also outlined a series of updates to how asset condition projects are presented to the PAC, following feedback from stakeholders responding to the NETOs’ proposed changes.   

While the current standard requires that a project is presented to the PAC before construction begins, it has no defined stakeholder comment period.  

Under the new proposal, for projects with an anticipated cost greater than $50 million, transmission owners would present potential solutions to the PAC at least six months prior to the start of major construction. Stakeholders would have a chance to give feedback, and three months later the transmission owner would present to the PAC responding to any stakeholder feedback and detailing the preferred solution.  

For projects expected to cost less than $50 million, a presentation would be required three months prior to the start of construction detailing the preferred solution and soliciting stakeholder feedback.  

Proposed changes to the PAC asset condition stakeholder review process. | ISO-NE

Burnham said the proposal is aiming to “balance the need for increased notice and increased transparency but is also … something that we could commit to, given our own internal priorities and internal project development lifecycles.” 

If presentations to the PAC are required too far ahead of the beginning of construction, “sometimes we just don’t have the detailed information that’s necessary to really give stakeholders the full picture of a project,” Burnham added.  

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NECA Conference Focuses on Changes to ISO-NE Capacity Market

WALTHAM, Mass. — Representatives from ISO-NE, Massachusetts and industry groups met on Nov. 13 to discuss major changes to the RTO’s capacity market and the effects they could have on the region’s clean energy transition at the Northeast Energy and Commerce Association’s 2023 Power Markets Conference. 

The potential changes include significant updates to ISO-NE’s resource capacity accreditation (RCA) methodology, along with prompt and seasonal capacity market formats. A prompt auction format would reduce the time between the Forward Capacity Auction (FCA) and the capacity commitment period (CCP) from more than three years to just a few months, while a seasonal market would break the yearlong CCP into distinct seasons with separate auctions. 

ISO-NE recently filed for a one-year delay of FCA 19, which applies to the 2028/29 CCP. The RTO is planning to use the delay to finalize its RCA updates and consider the different formats. (See NEPOOL Votes to Delay FCA 19.) 

Chris Geissler of ISO-NE said the RCA updates are a key component of preparing for increasing amounts of variable resources and higher winter peak loads. 

“The concerns are no longer really about just the summer peak, but about a much broader set of cases,” Geissler said. “Because of that, we think it’s important to try to align how we credit resources for their contributions with what we actually expect them to deliver when we need it.” 

Bruce Anderson of the New England Power Generators Association said the RCA changes are “an effort to create a capacity product that is substitutable across all resource types,” and that updating the accreditation methodology “makes a lot of sense” at a broad level. Anderson added that the current methodology may improperly value certain resource types. 

The specific effects of the RCA changes on different resource types are not yet clear. Preliminary results released in April indicated that the updates would increase accreditation values for wind and passive demand response (such as energy efficiency), while significantly reducing the values for energy storage, solar and active DR. However, ISO-NE has stressed that the RCA project is ongoing, and the results are subject to change. 

Anderson noted that peaking resources like many oil generators have a greater reliance on the capacity revenues than resources with a greater reliance on energy markets. 

“For different resource types, these changes are more critical for their viability,” Anderson said. “Overall, the design creates a set of revenue opportunities where those resources can be viable.” 

Jeff Bentz of the New England States Committee on Electricity said ISO-NE and its stakeholders need to strike a difficult balance between states’ requirements for renewable resources and the need to preserve reliability. 

“I’m sure we’re going to find out with the new modeling that some of this may not be as favorable to the type of resources that the states want to see grow,” Bentz told the conference. He said that while the RCA changes might hurt the accreditation values of short-duration batteries, it could provide an incentive for longer-duration batteries with greater reliability benefits.  

“If that incentive is out there, innovation grows and we get to longer-duration batteries for example, and they’re rated highly in the new program, that will be good,” Bentz said, noting there is a lot of work left to understand all the tradeoffs of the changes. 

Prompt and Seasonal Implications

A seasonal market could be a way to differentiate between distinct reliability risks in the winter and summer periods, especially with the anticipated increase in winter risks, Geissler said, noting that ISO-NE has yet to make a recommendation on the potential move to prompt and seasonal formats. 

Geissler added that a seasonal approach is a way to “be more granular in the capacity that we procure, so we’re making sure we’re meeting both the summer peak as well as extended winter cold spells.” 

Regarding a prompt market, Bentz said the current Forward Capacity Market has faced issues stemming from new resources that clear the market but do not reach operations on time or at all. 

“Moving to a prompt market — from a consumer standpoint — you’re going to get what you pay for on the day you pay for it,” Bentz said. 

Anderson said these “ghost projects” bring down the market price in subsequent auctions. He added that delayed projects force ISO-NE to decide to either grant the resource an extension or file with FERC to terminate the contract. 

“Any resource coming into the market on a prompt basis, assuming it’s going to be something in the order of say three, or even six months ahead of its delivery period, that’s a resource that’s built and ready to go,” Anderson said. 

In contrast, Anderson said moving to a prompt market could hurt price formation by failing to give enough advance notice that a resource is retiring compared to the current three-year forward market. This dynamic would limit the time available to address any reliability or resource adequacy issues created by the retirement and could lead to an increase in reliability-must-run agreements to keep resources online. 

“You see the same issue of price formation in the market, it’s dragging the price down for a resource that’s being retained outside of the market, not pricing itself in the market,” Anderson said. 

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MISO to Focus on LRTP, Congestion for MTEP 24

CARMEL, Ind. — MISO this week said the bulk of its 2024 Transmission Expansion Plan (MTEP 24) will look much the same as last year’s, with an emphasis on long-range transmission planning and near-term congestion studies in addition to its usual round of annual studies.

MISO took stakeholder suggestions in early fall on what additional planning studies it may undertake as part of MTEP 24. However, planning staff warned that MISO is limited next year in what it can accomplish because it’s performing extensive analysis under its ongoing long-range transmission plan.

The Municipals, Co-ops and Transmission-Dependent Utilities Sector requested MISO perform a study centered around the potential effects of widespread energy storage additions and analyze grid-enhancing technologies’ ability to provide flow control.

MISO said it will consider energy storage and grid-enhancing technologies over the course of its regular MTEP studies, but not under a dedicated analysis. The RTO said it’s always open to considering non-transmission alternatives to projects.

“We don’t see the need for a standalone study. We see where the annual MTEP process can address that,” MISO’s Jeremiah Doner said at a Nov. 15 Planning Advisory Committee meeting.

However, MISO said a continuation of this year’s near-term congestion study is on the table as part of MTEP 24. (See MISO May Use Inaugural Near-term Congestion Study to Plan Smaller Tx Upgrades.)

Doner said MISO hasn’t settled on a scope for the near-term congestion study.

“It’s too early to say what that study is going to produce,” he said.

MISO previously said the study again will be exploratory and likely won’t result in project recommendations.

Some members of MISO’s Environmental Sector have expressed disappointment that MISO will take another year of hypothetical testing before it recommends small projects that alleviate congestion.

MISO said it needs more time to refine its transmission planning model to solve congestion on a five-year horizon instead of in the long run. Planners said they are open to tweaking the scope and study assumptions based on stakeholder requests.

Some stakeholders have said MISO already has a template for studying regional congestion and cost allocation with its Targeted Market Efficiency Projects with PJM. But MISO said the MTEP interregional process is materially different.

MISO planners have said that if any market participant is concerned about congestion in the near term, they can pursue a market participant-funded transmission project.

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Winter is Coming; SPP Says It Has No Concerns

SPP says it has not identified any concerns within its 14-state footprint this winter that it is not capable of resolving. 

Bruce Rew, senior vice president of operations, told stakeholders Nov. 13 the RTO also does not expect any fuel-supply or resource issues across its fleet. 

“We are, however, continually performing studies to assess system changes and to develop ways to mitigate problems should any study indicate the potential for those to occur,” Rew said during SPP’s annual winter preparedness workshop. “Extreme weather can and has stressed our system from a capacity perspective, but we have procedures in place to ensure the grid remains stable.” 

He said SPP will take preemptive actions to prepare for worst-case scenarios should extreme weather occur, as has happened in each of the two previous winters. In February 2021, Winter Storm Uri forced the grid operator to shed load for the first time in its 80-year history. (See ERCOT, MISO, SPP Slough Load in Wintry Blast.) 

Rew said this year’s winter assessment forecasts a peak load of 46 GW, just below last December’s record peak of just over 47 GW. The assessment looked at typical load levels with normal expected outages. 

SPP staff are forecasting near-normal temperatures in the central and southern portions of its region and above-normal temperatures in the North. They say a strong Arctic outbreak is less likely but that there is an increased chance of winter precipitation in the South, thanks to the El Niño weather pattern’s strong subtropical jet stream. 

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MISO Says Overloads and Congestion Loom Without 2nd Long-range Tx Portfolio

CARMEL, Ind. — After completing its initial economic and reliability analysis, MISO has found that numerous overloads and congestion await its system if it doesn’t recommend a second long-range transmission plan (LRTP) portfolio.

“Keep in mind this is the start of the analysis. There’s much more work to do to translate these studies into transmission lines. So, expect to hear overloads today, not transmission projects,” Executive Director of Transmission Planning Laura Rauch told a Nov. 15 Planning Advisory Committee meeting.

That said, MISO found “significant” overloads and congestion on the system when it applies its envisioned 2042 resource mix in studies. Rauch said she expected the study results to show problems in the system.

Rauch said the second LRTP portfolio likely will shape up to be a “more complex solution” than the first, $10 billion LRTP portfolio. She said MISO’s analysis by 2042 found lines reach stability limits instead of just thermal limits and foresees a greater need for reactive power.

Rauch said MISO may have an idea of some projects by early spring.

“I would say at this point, all solutions are still on the table,” Rauch said of project sizes and voltages.

Rauch said MISO’s West Region — Minnesota, Iowa, Wisconsin, North Dakota and portions of South Dakota, Montana and Michigan’s Upper Peninsula — showed a need for higher-voltage transmission facilities to “support large power transfers and enable generation resources from remote areas to be delivered to load centers.”

By 2042, MISO found 20% of the facilities in the West Region will be overloaded, with annual generation curtailments exceeding 15%.

On the other hand, MISO said its Central Region — most of Illinois and Indiana and portions of Kentucky and Missouri — will be instrumental to supporting system transfers. It said about 10% of the Central Region’s facilities will be overloaded by 2042 without significant transmission expansion.

Rauch also said she expects MISO will have “additional challenges to solve” in the Central Region based on anticipated weather patterns and expanded transfer needs.

Finally, MISO’s East Region —most of Michigan’s Lower Peninsula — will need increased import and export capabilities by 2042. By then, MISO said about 10% of the East Region’s facilities will be overloaded, with annual curtailments surpassing 15%.

Rauch said the overloads and binding constraint hours uncovered in MISO’s initial studies will form the foundation of its list of transmission needs for the second LRTP portfolio.

“We may not solve all of them, but all of them will be considered,” Rauch said.

Rauch also said MISO has been sharing the results of its LRTP analyses with the Independent Market Monitor, who has voiced concerns with the future energy mix MISO predicts by 2042. (See MISO Promises Analyses on Long-range Tx; Stakeholders Divided on IMM Involvement.)

The second LRTP cycle again zeroes in on MISO Midwest; the third portfolio will pay attention to MISO South needs, and the fourth will address power exchange limits between the Midwest and South regions. MISO has said while the first, $10 billion portfolio is an “important start, further work is needed to ensure reliability.”

Meanwhile, the Organization of MISO States again has hired RLC Engineering to independently assess future projects in the second LRTP portfolio. For the first portfolio, RLC arrived at a 1.4:1 benefit-to-cost ratio for projects, smaller than MISO’s overall projection of 2.6:1.

MISO will hold an LRTP workshop Dec. 1 to dedicate more discussion to its initial findings.

“We’re just getting started and looking forward to the journey,” Rauch said.

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NERC Expecting Packed 2024 for Standards Actions

NERC’s Standards Committee can expect a packed year of reliability standards development in 2024, Vice President of Engineering and Standards Soo Jin Kim said at the committee’s monthly meeting Nov. 15.

Updating members on NERC’s Reliability Standards Development Plan (RSDP), Kim said there are 11 standards development projects the ERO considers high-priority — meaning they must be adopted by NERC’s Board of Trustees by the end of 2024. These include the following projects, some of which are targeting earlier approval dates:

    • 2021-07 (Extreme cold weather grid operations, preparedness and coordination) — to be approved by February
    • 2016-02 (Modifications to CIP standards) — February
    • 2023-03 (Internal Network Security Monitoring) — May
    • 2023-02 (Performance of inverter-based resources) — October
    • 2023-07 (Transmission system planning performance requirements for extreme weather) — December
    • 2020-02 (Modifications to PRC-024 (Generator ride-through)) — December
    • 2021-04 (Modifications to PRC-002 (Data sharing)) — December
    • 2021-03 (Modifications to CIP-002) — December
    • 2023-04 (Modifications to CIP-003) — December
    • 2023-06 (Physical security) — December
    • 2022-03 (Energy assurance with energy-constrained resources) — December

An additional 14 medium- and low-priority projects are targeting board adoption in 2025 and beyond, Kim said, and will not be posted for formal comment or ballot periods in the first half of 2024 in order to allow industry stakeholders who are part of the ballot body to focus on the most pressing projects. Kim clarified that these projects will still move forward during this time and be allowed to hold informal postings to solicit industry feedback on their progress.

NERC also considers FERC’s order last month that the ERO develop standards on the reliability of inverter-based resources (IBR) a high priority, Kim said, adding that the commission’s mandate “threw us for a loop” because it meant revising the draft RSDP to account for it. (See FERC Orders Reliability Rules for Inverter-Based Resources.) While no standard authorization requests (SAR) have been created yet for the order, NERC’s Engineering department is working with other groups in the organization to create a plan for tackling FERC’s directive.

Standards Actions Approved

Later in the meeting, the committee voted to move forward with two standards projects.

First, members agreed to post proposed revisions to NERC’s glossary for the terms “IBR” and “IBR unit” for a 45-day formal comment period. The changes were suggested by the standards development team for Project 2020-06 (Verifications of models and data for generators) after it received stakeholder requests to provide clearer definitions for terms used in its proposed standards.

The changes would define an IBR unit as a device or group of devices that use a power electronic interface such as an inverter or converter, capable of exporting real power from a primary energy source or energy storage system. An IBR would be defined as a source of electric power connected to the transmission, sub-transmission or distribution system and that consists of one or more IBR units operated as a single resource at a common point of interconnection.

Both definitions finished an informal comment period last month. The formal comment period, as approved by the committee, will begin Nov. 16 and conclude Jan. 4, 2024.

Committee members also accepted a SAR proposed by the SDT for Project 2023-07, meant to address FERC’s June order directing NERC to update its rules to require responsible entities to plan for extreme heat and cold weather events (RM22-10). (See FERC Approves More Extreme Weather Rules.) The new SAR will allow the Project 2023-07 team to decide whether to draft a new standard or revise TPL-001-5.1 (Transmission system planning performance requirements).

The committee deferred action on accepting another SAR intended to address risks posed by extreme weather, electric-natural gas interdependencies and disturbances impacting distributed energy resources. Members agreed to delay a vote on the SAR until the committee’s December meeting, to be held at NERC headquarters in Atlanta, after several attendees noted that the proposed SAR would also assign this effort to the 2023-07 team and expressed concern about the possibility of overloading the project.

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NJ Commits Millions for EV Vans, College Campus Decarbonization

New Jersey’s mass transit agency, NJ Transit, will spend $3.8 million on 19 electric vans, and the Board of Public Utilities (BPU) is offering grants of up to $5 million to entice colleges to launch decarbonization programs as the state seeks to push deeper emission reductions. 

The transit agency’s purchase, which the board approved on Nov. 8, is part of its slow but steady foray into electrification. The vans will be used to help seniors and disabled residents and an on-demand shuttle service that will link Route 9, a main artery through Central Jersey, to residential areas. 

The BPU’s campus initiative, which the agency opened on Nov. 1, creates a pilot program to reimburse colleges, universities and higher education institutions for up to 100% of the cost of putting together a plan to cut carbon emissions through energy efficiency, electrification, EV chargers and storage, among other methods. 

To be eligible, institutions must have multiple buildings and produce a plan that covers the entire campus. The program also offers $1,000/ton of carbon dioxide equivalent reduced. 

“Unlike traditional energy-efficiency programs, the decarbonization pilot is designed to explicitly target [greenhouse gas] emissions reductions,” the program participation guidelines said. 

Together, the initiatives address two of the state’s largest sources of emissions: transportation and buildings. The program is “designed to encourage colleges, universities and educational institutions to support New Jersey’s clean energy future by taking actionable steps toward decarbonization,” the BPU said in announcing the pilot. 

“We all have a role in protecting the environment and reducing carbon emissions,” the BPU said. “This program assists educational institutions in achieving their decarbonization goals.” 

Sustainability Goals

NJ Transit President Kevin Corbett said the purchase of EVs and their integration into the mass transit system will be critical to modernizing the agency. 

“This purchase not only helps our local communities transition to electric vehicles to support the state’s sustainability goals, but it also advances our mission to provide accessible transportation for all New Jerseyans,” he said. 

The agency will use eight of the vans to provide community services in Essex, Middlesex and Somerset counties so that it can offer transportation for populations including seniors, people with disabilities, veterans, job seekers and rural residents. “This type of service can potentially serve residential customers at lower cost, with more operational and customer flexibility than is provided by limited, fixed-route “branch” services,” NJ Transit said in a release. 

Another eight vans will be used for an on-demand shuttle service that will “test the feasibility” of creating an on-demand microtransit shuttle to connect mainline commuter bus corridors to lower-demand residential areas, the release said. 

The state’s 2019 Energy Master Plan included directives for NJ Transit to implement an electric bus program and introduce a battery-electric train prototype by 2025. The state’s Global Warming Response Act (GWRA) report, which outlined legislative and policy initiatives to confront global warming, called for 10% of NJ Transit’s new buses to be zero-emission by Dec. 31, 2024, and all new bus purchases to be zero-emission by 2032. 

But a second vote at the NJ Transit board of directors’ monthly meeting last week highlighted the difficulty of electrifying an agency that operates 263 bus routes, three light rail lines and 12 commuter rail lines. NJ Transit calls itself the “nation’s largest statewide public transportation system.” 

Before the board backed the purchase of the 19 electric vans, it approved the purchase of 550, 40-foot diesel buses and 200, 60-foot diesel buses for a cost of $686 million. The buses will replace vehicles in the agency’s existing fleet, which has more than 1,300 buses, many of which are “over age and due for replacement,” according to the board’s purchase resolution. 

The resolution said NJ Transit expects the purchase of the new buses will be the “last diesel bus procurement contingent on the successful advancement of the bus modernization program to completely convert to a zero-emission bus fleet.” The new buses, although they are not fueled by clean energy, will be fitted with “the latest technology to significantly reduce vehicle exhaust emissions,” the resolution says. 

The purchase approval comes just over a year after the agency put into service its first electric bus. The bus is part of a pilot program that will put eight electric buses costing $9.5 million into service from the Newton Avenue Bus Garage in Camden. The agency converted the South Jersey garage to handle electric buses at a cost of $9.5 million. (See NJ Transit Advances with EV Bus, Sustainability Plans.) 

The agency in October approved additional design work for the conversion of the Hilton Garage in Maplewood. The agency also is assessing the condition of two other garages in Westwood and Newark for possible conversion to handle EVs.