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November 14, 2024

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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. 

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Nevada Geothermal Auction Fetches $1M for BLM

As part of its efforts to lease land for renewable energy production, the Bureau of Land Management (BLM) auctioned leases for 33 geothermal parcels in Nevada on Nov. 14, fetching just over $1 million.

The sale offered 45 parcels totaling 134,866 acres in 12 counties. Bids were received for 33 parcels, covering 96,605 acres.

The leases went to eight bidders, according to results published by BLM. TLS Geothermics Corp. won leases for eight parcels. The French company also won leases for five Nevada parcels in a geothermal auction last year.

Zanskar Geothermal and Minerals won leases for six parcels. Zanskar’s mission is to discover geothermal energy faster using big data, the Utah-based company’s website states.

Ormat Technologies and Photosol US each won five leases. Norte Geothermal won leases for four parcels, and FLHN 1 LLC won three.

Rodatherm Energy Corp. and Baseload Power U.S. won leases for one parcel each.

BLM issues geothermal leases for 10 years. Following the auction, the winning bidders must submit site-specific proposals before energy development can begin.

Nov. 14’s auction, which earned $1.025 million, was smaller in scope than BLM’s Nevada geothermal lease auction last year. The bureau’s competitive auction in August 2022 brought in $3.3 million for 66 Nevada geothermal parcels totaling 192,912 acres.

And those results are a far cry from a BLM auction in June that raised a record-breaking $105 million. That auction was for four parcels in the Amargosa Desert in southern Nevada for solar development. (See BLM Holds Record-breaking Solar Auction in Nevada.)

Still, Nov. 14’s auction will help meet the Biden administration’s goal of permitting 25 GW of solar, wind and geothermal production on public lands by 2025, BLM said in a release.

“Issuing geothermal leases is an important piece of the dynamic energy portfolio in Nevada,” Justin Abernathy, BLM Nevada deputy state director of energy and minerals, said in a statement. “BLM carefully analyzed these parcels, and this successful lease sale is the initial phase to developing new, clean energy sources.”

BLM has tentatively scheduled its next competitive geothermal lease sale for October 2024.

Nevada has 26 geothermal power plants in 17 locations, and the state’s geothermal generation capacity of 827 MW is second only to California, according to the Nevada Division of Minerals.

Ormat has several geothermal power plants operating in Nevada. The Reno-based company submitted the highest per-acre bid in Nov. 14’s auction of $130 for a 2,494-acre parcel in Mineral County.

Ormat’s projects include a geothermal power plant in North Valley, Nev., whose completion was announced in May. The project included construction of a 58-mile transmission line in addition to the 25-MW power plant.

But another project Ormat is planning in Nevada has hit a roadblock: A group of plaintiffs filed a complaint in U.S. District Court in January challenging BLM’s approval of Ormat’s geothermal exploration project near the town of Gerlach.

The town is a gateway to the annual Burning Man festival, and plaintiffs in the case include the Burning Man Project, which runs the annual event, as well as the Summit Lake Paiute Tribe of Nevada and Friends of Nevada Wilderness.

The plaintiffs said BLM didn’t consider in its environmental review the potential impacts to “inimitable” hot springs in the area. The defendants also failed to consider impacts of “the future but inevitable large-scale geothermal production project,” the complaint said.

In addition to BLM, the Department of the Interior and Interior Secretary Deb Haaland are named as defendants. The federal defendants have denied the allegations. Parties in the case continue to file briefs.

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NYISO Stakeholders Advance Rules on Ambient Ratings, Internal Controllable Lines

RENSSELAER, N.Y. — NYISO’s Business Issues Committee on Wednesday approved tariff revisions to align day-ahead market (DAM) congestion settlement procedures with ambient-adjusted ratings (AARs). 

FERC Order 881, issued in December 2021, mandated transmission providers evaluate their transmission capacity based on real-time environmental conditions, such as air temperature, wind speed and solar radiation (RM20-16). The order requires transmission providers to use AARs for short-term transmission requests — 10 days or less — for all lines impacted by air temperature. Seasonal ratings will be required for long-term service. (See FERC Orders End to Static Tx Line Ratings.) 

NYISO’s proposed revisions aim to resolve inconsistencies between AAR rating limits used in the DAM and those assumed in transmission congestion contract (TCC) auctions.  

This included changes to calculations of the congestion rent impacts of uprates and derates and the creation of a new category of qualifying events resulting from differences in the DAM ratings required by Order 881 and those assumed in TCC auctions.  

FERC partially rejected NYISO’s initial July 2022 compliance filing, saying that some of the ISO’s revisions fell outside Order 881’s scope, certain terms were inadequately defined and the ISO was non-compliant with the timeline requirements of the order. (See FERC Approves Batch of Line Ratings Compliance Filings.) NYISO is awaiting a decision on its second compliance filing, submitted in June 2023. 

NYISO’s ability to adjust its transmission line ratings in real time has become increasingly important to maintaining grid stability and efficiency, especially as the grid integrates more intermittent energy sources and climate change leads to more variable weather patterns. 

The proposed changes now move to the Nov. 29 Management Committee for final approval. The ISO plans to implement the changes alongside its compliance proposals already accepted by FERC.  

Internal Controllable Lines

The BIC also voted Nov. 15 to recommend the MC’s approval of energy market, capacity market and market mitigation rules for new “internal controllable lines” (ICLs).  

Clean Path New York (CPNY), a 175-mile, 1,300-MW HVDC line, will be the first ICL in the New York control area. CPNY, which was selected under the New York State Energy Research and Development Authority’s Tier 4 renewable energy certificates program, will deliver renewable power generated upstate into New York City. 

The ISO’s revisions will optimize ICL flows based on economic dispatch to serve loads at the least as-bid cost. Bilateral energy market transactions will not be permitted to source to or sink from an ICL. 

The lines will be eligible for day-ahead bid production cost guarantee (BPCG) payments and for real-time BPCGs only if they are dispatched out-of-merit for reliability. They also will be eligible for day-ahead margin assurance payments when scheduled out-of-merit or derated for system security or to permit the ISO to produce additional operating reserves. 

ICL bids will include an operating range and up to an 11-step dollar/MWh curve based on CPNY’s willingness to be paid or to pay to transmit energy between its two terminals. They will be limited to a maximum bid of $1,000/MWh and a minimum bid of -$1,000/MWh. 

Both day-ahead and real-time settlements will be based on the price differentials between the injection and withdrawal buses, and line losses. 

The ISO said it is proposing a flexible capacity market design without tying supply to specific generators. An ICL must hold unforced capacity delivery rights to be a capacity supplier; it would transmit pooled capacity, sourcing in the NYCA and sinking in a locality. 

Because HVDC lines can ramp up and down as fast as 1,000 MW per second — versus the 10-20 MW per minute averaged by a typical 1,000-MW generator — ICLs’ ramp rates may be subject to limits to protect system stability. 

No new market mitigation measures will be required for ICL’s functionality but the ISO will develop a new conduct test for uneconomic production.  

Mark Younger, president of Hudson Energy Economics, asked about NYISO’s proposal to set ICL deviation charges — fees assessed to market participants for differences between their scheduled and actual energy generation or consumption — at 1.5% of the ICL’s upper operating limit. 

Michael Swider, senior market design specialist at NYISO, explained that the deviation tolerance was reduced from 3% because the operations team determined the lower threshold to be more appropriate.  

Assuming approval by the MC, NYISO plans to file its revisions with FERC in early 2024. 

BIC Election

The BIC elected Timothy Lundin, transmission regulatory policy manager for LS Power Grid NY, as the committee’s new vice chair.  

Lundin currently chairs the Electric System Planning Working Group’s but will leave that position at year’s end.  

October Market Operations

NYISO Senior Principal Economist Nicole Bouchez presented the October market operations report, noting significant declines in natural gas and distillate prices and average monthly energy costs. 

October’s average energy cost was 56% lower than the previous year, falling from $89.47/MWh to $39.44/MWh. Natural gas and distillate prices saw year-over-year reductions of 72.2% and 27.2%, respectively. The month’s LBMP also decreased to $28.10/MWh, lower than September’s $36.92/MWh and last October’s $53.11/MWh. 

Bouchez mentioned the delayed development of an operating protocol for the Long Mountain phase angle regulator (PAR) installation, also known as the Dover PAR, due to ongoing court challenges (2023-50796). The timeline to complete an agreement for this 345-kV intertie between NYISO and ISO-NE remains uncertain. 

Project Prioritization Proposal

At the Nov. 15 Budget & Priorities Working Group meeting, Kevin Lang, partner at Couch White representing the City of New York and Multiple Intervenors, proposed major changes to NYISO’s project prioritization process that seek to shorten the process, improve stakeholder coordination and enhance overall efficiency. 

Lang suggested shifting project prioritization to later in the year to allow for more accurate assessments of project costs and resource availability and facilitate a smooth transition into the subsequent year’s work. He acknowledged this could increase NYISO staff workloads but said the benefits would outweigh the extra effort 

The proposal was well received, with both Younger and Anthony Abate, lead energy market advisor for the New York Power Authority, commending Couch White for striving to improve these processes. They agreed that more information would enable better decision-making.  

Lang encouraged stakeholders to send comments or suggestions to klang@couchwhite.com. He said he plans to present an updated proposal that incorporates submitted feedback in January 2024.