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November 5, 2024

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DOE Proposes Expanding NEPA Exclusions for Clean Energy, Transmission

The U.S. Department of Energy Thursday proposed revisions to its regulations under the National Environmental Policy Act that would expand the scope of “categorical exclusions” for transmission and clean energy. 

The exclusions would apply to projects that are shown to not have a significant environmental effect. It would create a new exclusion for energy storage projects within previously disturbed or developed areas, while changing exclusions for solar energy and transmission. 

DOE reasoned that upgrading lines can prevent the construction of new ones, with the Notice of Proposed Rulemaking (NOPR) highlighting reconductoring as a means of capacity expansion, which can increase the amount of renewable energy on the grid. 

“Improvements to capacity and efficiency can help to ensure reliability, reduce costs to consumers and reduce [greenhouse gas] emissions associated with electricity generation, transmission and distribution,” said the notice in the Federal Register. 

Rebuilding transmission lines is currently exempted, but only up to 20 miles. The proposal would remove that mile limit. The department reasoned that the environmental impact of a line is not related to its length. 

It also would expand the exclusion for relocating segments of a line to existing rights of way or previously disturbed or developed lands. Regulations currently include language limiting relocation exemptions to “minor” relocations of small segments; the proposal would remove the word “minor.” 

The storage exemption applies to electrochemical batteries and flywheels within previously disturbed or developed areas, or within small sites near such areas.  

The current categorical exclusion for solar is limited to projects of 10 acres or below, but DOE said acreage is not a reliable indicator of environmental impact and would remove that limit in the proposal. Projects larger than 1,000 acres on previously disturbed or developed land have not had significant environmental impacts, it said. 

DOE expects that the new exclusions will save it money and time, while improving the reliability and resilience of the electric grid. Expanded electricity generation that helps to reduce greenhouse gas emissions is another benefit. 

The department is taking comments on the proposal through Jan. 2. 

Speaking after FERC’s open meeting Thursday, Chair Willie Phillips said that the proposal would have more impact on DOE’s transmission siting authority. The commission has its own pending NOPR implementing its backstop siting authority granted by the Infrastructure Investment and Jobs Act. (See FERC Backstop Siting Authority Runs into Opposition from States.) 

DOE’s proposal was welcomed by American Council on Renewable Energy President Gregory Wetstone in a statement. 

“A dramatic increase in renewable energy and transmission infrastructure is needed to enhance reliability, lower energy costs and maximize the benefits of the Inflation Reduction Act,” Wetstone said. “A key barrier is the often lengthy siting and permitting process. ACORE supports the use of categorical exclusions for projects that will produce a cleaner grid and not adversely impact the environment. This mechanism improves siting and permitting while maintaining NEPA’s core environmental provisions.” 

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Popular Incentive Dropped from CARB’s $624M EV Funding Package

California regulators approved a $624 million clean transportation incentive funding package on Thursday but said goodbye to a flagship program that helped consumers in the state buy more than 500,000 zero-emission or hybrid light-duty vehicles. 

The California Air Resources Board (CARB) approved a funding plan for 2023/24 that includes $455 million in incentives for zero-emission drayage trucks and school buses.  

Another $28 million will go to the Clean Cars 4 All program, which pays lower-income consumers to scrap their old cars and buy a cleaner vehicle. An e-bike incentive program will receive $18 million, and $14 million will go to the Clean Off-Road Equipment incentive program. 

But the plan does not include money for the Clean Vehicle Rebate Project (CVRP), which has received $1.61 billion since its launch in 2010 and provided incentives for the purchase of about 533,000 vehicles. 

CVRP ran out of money and closed to new applications effective Nov. 8. The program offered incentives of up to $7,500 for the purchase of new battery-electric, plug-in hybrid and fuel cell vehicles. The program included income caps, but they were less restrictive than those of Clean Cars 4 All. 

Stephanie Parent with CARB’s Mobile Source Control Division said CVRP had been “a huge success story.” 

“CVRP achieved its goal of accelerating the deployment of ZEVs in California and provided highly useful ZEV market information to stakeholders in California and beyond,” Parent told the CARB board on Thursday. 

According to the California Energy Commission’s ZEV dashboard, 1.7 million light-duty ZEVs have been sold in California. So far this year, ZEVs accounted for 25% of new car sales. 

Rather than providing purchase incentives for the broader ZEV market, CARB will now shift its focus to lower-income consumers through its Clean Cars 4 All and finance assistance programs. 

Smaller Package

The $624 million incentive package that CARB approved on Thursday is substantially smaller than the $2.6 billion approved last year for 2022/23. That was the agency’s largest budget yet for the incentives. (See CARB Approves $2.6B in Clean Vehicle Incentives.) 

The current package includes $455 million in incentives for zero-emission heavy-duty vehicles: $80 million for drayage trucks and $375 million for public school buses. Those incentives will be available through the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP). 

The drayage truck incentives will help fleets meet the requirements of CARB’s Advanced Clean Fleets (ACF) regulation adopted in April. Under ACF, all new trucks added to drayage fleets must be zero-emission starting in 2024, and all drayage trucks must be ZEVs by 2035. (See CARB Adopts Clean Fleets Rule Despite Broad Skepticism.) 

The state budget didn’t give CARB funding for other types of heavy-duty vehicles that are eligible for HVIP incentives. But HVIP received $1.8 billion in the 2022/23 funding plan, and the program reports that incentives are still available. 

On the light-duty side, the $28 million going to Clean Cars 4 All will be split into two parts. Half will go to air districts that have been administering the program since its launch. The other half will go to a new statewide expansion of the program. 

CARB’s incentive funding plan also includes the addition of zero-emission motorcycles (ZEMs) as an eligible vehicle in Clean Cars 4 All. Incentives for ZEMs were previously only available through CVRP. 

The Tesla Effect

CVRP received a $515 million allocation for 2021/22 that was intended to fund the project through June 2024. But earlier this year, CARB estimated the project would run out of money as soon as October of this year. 

That’s because Tesla in February reduced the price of two of its models — Model 3 and Model Y — making them again eligible for the CVRP incentive after losing eligibility in 2022. Starting in March, CVRP applications surged to about 12,000 per month. (See California EV Rebate Program Expected to Run Empty Ahead of Plan.) 

Following the board’s approval of the incentive funding package on Thursday, CARB Executive Officer Steven Cliff read a resolution expressing appreciation to the Center for Sustainable Energy, which ran the CVRP program for nearly 14 years. 

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FERC Enforcement Report Details One Closed Probe into Winter Storm Uri

WASHINGTON — FERC on Thursday released its 17th Annual Report on Enforcement, which showed that it has closed down one market manipulation probe into the events around February 2021’s Winter Storm Uri.

The commission still has open, nonpublic investigations into the events around Uri, which led to massive blackouts in Texas where hundreds died and roiled natural gas markets around the country, leading to billions in extra costs for consumers.

“I cannot talk about them,” FERC Chair Willie Phillips said at his post-meeting press conference. “But hear me: For those people who had market manipulation, who committed market manipulation, or if there was any fraud that was imposed upon our consumers — the Federal Energy Regulatory Commission, the Office of Enforcement … will find you, we will punish you, and you will pay the price.”

The investigation FERC closed without action came from a referral of Enforcement’s own Division of Analytics and Surveillance about a gas marketing company that curtailed supply to customers to whom it had delivery obligations by citing force majeure and then sold gas to a different customer at a higher price, the report said.

Enforcement staff reviewed documents and took sworn testimony from employees and determined it lacked evidence to move forward. The firm’s decision to sell gas to a different customer appeared to have been made during a small window of time when the marketing company believed its curtailments would be less substantial.

“Enforcement staff also did not find evidence that the marketing company actively sought out buyers to sell gas to at an elevated price,” the report said. “To the contrary, the purchaser unilaterally reached out to the marketing company requesting gas.”

DAS is regularly watching the electric and natural gas markets that FERC polices, with the report saying in fiscal 2023, its surveillance led to 567,000 screen trips in the electric markets, leading to 43 surveillance inquiries and six referrals for investigation. On the gas side, it had 24,000 screen trips on the year, leading to 27 surveillance inquiries and three referrals for investigation.

The division engaged in enhanced surveillance during “disruptive market events” related to December 2022’s Winter Storm Elliott and a period of high energy prices in the West during the winter of 2022/23. It is continuing to analyze both market events and has already referred some matters related to last winter’s weather events to investigative staff.

Overall, Enforcement opened 19 new investigations and closed nine pending probes without further action. Staff also negotiated 12 settlements that were approved by FERC for a total of $33.4 million: $11.7 million in civil penalties and $21.7 million in disgorgement.

Three other settlements resolved litigation in federal District Court for $4 million in disgorgement, one order to show cause for $4.4 million in civil penalties, and one U.S. Court of Appeals matter for a $10.75 million civil penalty.

Enforcement staff also completed nine audits of public utility, natural gas and oil companies that resulted in 68 findings of noncompliance and 332 recommendations for corrective action. They directed $33 million in refunds and other recoveries.

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Washington’s 2nd Cap-and-trade Reserve Auction Raises $259.5M

The state of Washington’s second cap-and-trade Allowance Price Containment Reserve (APCR) auction raised almost $259.5 million, the state’s Ecology Department said Nov. 15. 

The auction held on Nov. 8 cleared all 5 million carbon emissions allowances put up for bid at a Tier 1 price of $51.90, which represents the soft cap price that triggers the need for the secondary APCR auction. August’s quarterly auction blew through the cap when it cleared at $63.03. (See Wash. Allowance Prices Surge Again in 3rd Cap-and-trade Auction.) 

The APCR auction is a mechanism intended to keep carbon prices in check by releasing a reserve of allowances only to “compliance” entities — those organizations that need to cover direct emissions. The APCR is not available to financial traders of allowances.  

Thirty entities participated in the second APCR auction, including oil refiners, natural gas companies, electric utilities and the state’s two largest public universities. 

The state’s first APCR auction took place in August, raising $62.5 million. (See Wash. Raises $62.5M from Cap-and-trade Reserve Auction.) 

That take from the latest auction translates into more than $1.72 billion collected so far in 2023, the first year of Washington’s cap-and-invest program. Most of the money will go to climate change-related projects. 

The state legislature last spring appropriated roughly $300 million from the state’s first auction in February. Gov. Jay Inslee (D) next month likely will unveil his proposals for the funds in preparation for the 2024 legislative session scheduled to begin in January.  

Washington has one auction left to conduct for 2023, which will occur in December.  

Conservative critics of Washington’s cap-and-trade program have blamed it for the state’s high gasoline prices. When the program was approved in 2021, Inslee’s administration contended it would add only a few pennies per gallon to prices at the pump. This has prompted intense criticism from Republicans. 

Washington this month said it tentatively will seek to link its cap-and-trade system with the California-Quebec market in an effort to reduce the impact on gas prices. (See Wash. Looks to Join California-Quebec Cap-and-Trade Market.) In its last auction, the California-Quebec program cleared allowances at roughly $36.  

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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.