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November 5, 2024

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MISO Stakeholders Insist on Consistency in Capacity Accreditations

Stakeholders told MISO Wednesday it should use a consistent capacity accreditation process for both its conventional and non-thermal generators.

The request comes as MISO is evaluating new accreditation options for non-thermal generation. The RTO filed with FERC late last year to change its accreditation for conventional resources to a seasonal value based on a unit’s past performance during tight conditions. The new accreditation is contained in a larger filing to create four seasonal capacity auctions (ER22-495). (See Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid.)

At the time, MISO elected to wait to propose a new accreditation for its other, intermittent generating units.

Now, MISO is evaluating three accreditation options for non-thermal resources:

  • Expanding its effective load carrying capability (ELCC) calculation, currently in use for wind generation, to include solar generation and other intermittent resources;
  • Using an availability-based accreditation based on generator performance during “resource adequacy hours” — tight margin and emergency periods — over four historical planning years. That accreditation style is pending before FERC for MISO’s conventional resources; or
  • Employing a blend of ELCC and an availability-based accreditation.  

The blended approach would have MISO identifying seasonal risky hours in addition to running a loss of load expectation (LOLE) analysis to identify possible shortfall events. MISO said it will “develop windows of risk for each season by combining resource adequacy hours and LOLE events.” Capacity credits would be issued based on generator performance during the combined risk periods.

Stakeholders attending an April 20 Resource Adequacy Subcommittee (RASC) teleconference said they want comparability across accreditation of thermal and non-thermal resources. They said if thermal resources are going to be valued based on their historical contributions during times of system need, non-thermal resources need to be as well.

WEC Energy Group’s Chris Plante questioned why MISO considers ELCC “good enough” for intermittent resources but not for conventional resources.

“Why are we making a distinction between intermittent and conventional resources when, at the end of the day, we’re trying to determine the same thing?” he asked.

“We don’t need to have apples-to-apples, but we at least need a fruit salad. We can’t be throwing onions in,” Clean Grid Alliance’s Natalie McIntire said.

MISO staff said they’re still considering accreditation designs. The RTO plans to hold a special workshop sometime in June and set a direction on a new accreditation in July. It said it will work on a design with stakeholders through the end of the year.

During the March RASC, McIntire encouraged MISO to pursue an entire rethink of its resource adequacy construct instead of developing a new capacity accreditation for intermittent resources. Other stakeholders have also asked MISO to assess the entirety of its resource adequacy construct.

MISO’s Scott Wright told stakeholders the accreditation redesign for non-thermal resources is only a piece of the reforms MISO envisions needing as the resource mix transitions away from centralized, baseload generation.

“This is not the end or a destination,” Wright said.

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New York TOs Again Defend Local Tx Project Rights

New York transmission owners on Wednesday again rejected challenges to their new public policy category of local transmission development for purposes of cost sharing and recovery (Case No. 20-E-0197).

The NYTOs, including state investor-owned utilities, the New York Power Authority (NYPA) and the Long Island Power Authority, told state regulators that LS Power, the Alliance for Clean Energy (ACE-NY), and New York City were mistaken in their concern with the NYTOs’ proposed cost sharing and recovery agreement (CSRA) for so-called phase 2 projects.

Phase 1 projects are traditional utility investments that address system reliability or resilience issues, while phase 2 projects are investments made primarily to satisfy requirements of the Climate Leadership and Community Protection Act (CLCPA).

The NYTOs in January had urged the Public Service Commission to reject LS Power’s argument that costs of local transmission can only be allocated under the NYISO tariff’s Order No. 1000 processes and that any regional cost allocation is preempted by FERC’s exclusive jurisdiction over transmission. (See New York TOs Defend New Public Policy Tx Category.)

This month, the NYTOs rejected LS Power’s insistence that phase 2 projects must go through NYISO’s public policy transmission planning process: “Transmission projects identified through each NYTO’s local planning process have never been subject to the NYISO PPTPP or its competitive solicitation process and are properly within each NYTO’s planning authority.”

Forcing project development through the ISO would only serve to address bulk power transmission facility needs, not local system capacity shortfalls, the NYTOs said.

Under Order No. 1000, regional transmission facilities are those that must be regionally planned, competitively selected and eligible for regional cost allocation.

ACE-NY and the City

ACE-NY asked the PSC to establish a cost containment mechanism for phase 2 projects, a request the NYTOs said should be rejected as being outside the scope of the proceeding.

The NYTOs said they balanced competing interests in developing a voluntary CSRA under the basic premise that incurred costs of projects approved by the commission would be recoverable.

Regulators will use the cost recovery mechanism for only those projects approved as meeting the statutory objectives under the CLCPA, including a pre-determined rate of return and capital structure, the NYTOs said. The CSRA, they added, does not provide for pre-approval of all project costs. In addition, the PSC and all interested parties reserve the right to contest project costs incurred by the sponsoring NYTO, and therefore it would be inappropriate to impose generic involuntary cost caps.

New York said it is concerned about inconsistency between the CSRA and the rate schedule, according to the city’s Feb. 8 comments in the proceeding. Regarding cost recovery for NYPA customers, the NYTOs contend that under the CSRA, NYPA “will be allocated costs of approved transmission projects in the same manner as other [load serving entities] under rate schedule 18,” and that the rate schedule does not apply to NYPA, the city noted in its comments.

The CSRA and rate schedule, however, are correct, according to the NYTOs.

A provision of the CSRA relating to NYPA as a load-serving entity “recognizes NYPA’s customers will be responsible for CSRA-related costs to the same extent as other end-use customers in New York served by a load serving entity,” the NYTOs said.

NYPA said it will not use the CSRA or accompanying rate schedule to recover the costs of its transmission projects for the following reasons:

  • NYPA does not have a retail service area or local transmission and distribution system and therefore, under the Accelerated Renewables Act, will not be developing phase 2 projects for inclusion in the utilities’ capital plans, and
  • NYPA uses the NYPA transmission adjustment charge, which already allocates those costs state-wide, to recover its transmission embedded costs.
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Washington Looks to Boost Prospects for Winning Hydrogen Hub

Washington officials are seeking to bolster the state’s case to land one of the nation’s federally funded hydrogen hubs.

Gov. Jay Inslee and Lisa Brown, director of the Washington Department of Commerce, have been working in recent months to coordinate the state’s activities in seeking a piece of an $8 billion U.S. Department of Energy fund to create regional hydrogen hubs to produce and distribute the fuel for industrial and transportation applications.

“This is a ruthless competition nationwide. It’ll be political malpractice not to leave everything on the field,” state Sen. Reuven Carlyle (D) said at the Future of Carbon Policy Forum held at Seattle’s Space Needle last week.

Speaking at the forum, Rep. Kim Schrier (D-Wash.) said roughly 80 proposals will likely be whittled down to four to eight regional hubs, translating into $1 billion to $2 billion for each.

On Feb. 24, Inslee sent a letter to dozens of state agencies, utilities and private companies saying that Washington stands a good chance to host one of the hubs, citing the state’s extensive efforts in in combating greenhouse gas emissions.

“Washington has the lowest carbon intensive grid in the United States. The opportunity to develop truly green hydrogen and understand how it fits into a modern decarbonized economy is possible today in the state of Washington. No other region is as advanced in this area,” Inslee wrote.

He pointed to several utilities and private companies in Washington that are already delving into hydrogen production reduction or use. These include Microsoft, Amazon, PACCAR — which is building hydrogen-fueled semi-trucks — and the Port of Tacoma and Douglas County Public Utility District, which are exploring manufacturing hydrogen. Washington State University and the Pacific Northwest National Laboratory are also conducting hydrogen-related research.

The Douglas County PUD is the farthest along, building a $25 million hydrogen plant expected to go online in late 2022 or early 2023. (See Wash. PUD Breaks Ground on Hydrogen Plant.)

In an interview with NetZero Insider, the PUD’s General Manager Gary Ivory said that while no contracts have yet been signed for the output from the plant, potential customers have expressed interest in more hydrogen than the planned facility would be able to produce. Douglas County has more land set aside to expand the operation after construction of the original plant is complete.

In an April 4 letter to the same organizations addressed by Inslee’s letter, Brown wrote that the state, utilities and private companies recently created the Pacific Northwest Hydrogen Association, which is expected to coordinate hub-related efforts starting in May. In its 2022 session, the state legislature allocated $2 million to those efforts.

Lawmakers this year also passed a bill (SB 5910) establishing the Office of Renewable Fuels within the Commerce Department to support the development of renewable fuel and electrolytic hydrogen projects. (See Green Hydrogen Bill Passes Wash. Legislature.)

In her letter, Brown noted that the legislature also recently expanded the responsibilities of the state’s Energy Facilities Site Evaluation Council, giving the agency siting authority over renewable fuel projects. Lawmakers also created tax breaks for renewable energy projects if they met specific labor hiring standards, Brown wrote.

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54 GWh EV Battery Plant Proposed for Lithium Valley

Controlled Thermal Resources, a company developing a geothermal energy and lithium production facility in Southern California, has a new potential partnership with a business that plans to build an EV battery factory nearby.

A newly launched company called Statevolt intends to build a 54 GWh EV battery factory in Imperial Valley, California, according to an announcement Tuesday from company founder Lars Carlstrom. Carlstrom is founder and CEO of Italvolt, a company that’s developing an EV battery factory in Italy.

Statevolt has signed a letter of intent with Controlled Thermal Resources (CTR) in which CTR will provide lithium and geothermal power from the company’s Hell’s Kitchen Lithium and Power project, which is now under development in Imperial Valley.

Statevolt said in a release that it’s performing due diligence to find the best site for its Imperial Valley battery factory. The factory will be one of the largest in North America, the company said, with a production capacity of 54 GWh, enough for about 650,000 electric vehicles a year at full capacity.

The project is expected to cost around $4 billion. The announcement didn’t include details on project financing.

A CTR spokeswoman said Statevolt expects to start producing lithium-ion batteries at scale by 2025. She said there are no further details on lithium or power offtake at this time.

Lithium from Brine

California’s Imperial Valley is home to the Salton Sea Geothermal Field, where a number of geothermal power stations are located.

The area is also a rich source of lithium, which is in growing demand as a component of electric vehicle batteries. CTR plans to extract lithium from the geothermal brine it uses to produce renewable energy.

CTR announced in November that it had started drilling wells at the Hell’s Kitchen site. CEO Rod Colwell said at the time that CTR was on track to deliver the project’s first 50 MW of baseload renewable power in late 2023 and an estimated 20,000 tons of lithium hydroxide in 2024.

In July, General Motors (NYSE: GM) announced it will invest millions of dollars in CTR’s lithium production project, a deal that will give GM first rights to lithium produced in the first stage of the Hell’s Kitchen project. (See GM Invests Big in Calif. ‘Near Zero’ Lithium Project.)

‘Hyper-local’ Model

At Statevolt, Carlstrom described the planned partnership with CTR as a “hyper-local” sustainable business model, in which lithium and power come from local sources. The approach minimizes the environmental impact of battery production and produces a more secure supply chain, he said.

“We believe this model will offer Statevolt a significant advantage in producing lithium-ion batteries at scale, to meet booming consumer demand,” Carlstrom said in a statement.

Carlstrom’s other company, Italvolt, announced in September that it had signed a binding agreement to buy land in the municipality of Scarmagno, Italy for a 45 GWh lithium-ion battery factory.

The company said it expects to obtain building permits and start construction in the second half of this year.

Carlstrom also co-founded Britishvolt, a company aiming to build a battery factory in England. He stepped down as company chairman in late 2020 after details emerged of his tax fraud conviction in Sweden more than 20 years previously, according to news reports.

Carlstrom said at the time that he didn’t want to be a “distraction” for the company and that he had planned all along to pass on Britishvolt’s chairmanship.

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DOE Wants 60 GW of Dispatchable Geothermal Power on US Grid

The U.S. Department of Energy wants geothermal energy to provide 60 GW of firm, flexible clean energy to the U.S. grid by 2050, and it’s putting up $84 million from the Infrastructure Investment and Jobs Act (IIJA) to develop a range of nontraditional, “enhanced” geothermal systems (EGS), according to a request for information (RFI) released Tuesday.

Hitting that target would mean a 26-fold increase in the geothermal generation online in the U.S. today, DOE said.

“The U.S. has incredible, untapped geothermal potential beneath our very feet, which can be harnessed to meet our energy demands with a round-the-clock, clean renewable resource available across the country,” Energy Secretary Jennifer Granholm said in Tuesday’s announcement of the RFI. The funds from the IIJA will help “incentivize access to that resource nationwide while helping fossil communities and workers leverage existing infrastructure and skills to seamlessly transition to producing clean energy.”

The IIJA calls for the funds to be used to “demonstrate EGS in different geological settings, using a variety of development techniques and well orientations, at sites where subsurface characterization or geothermal energy integration analysis has been conducted,” the RFI says.

Following those provisions, DOE lays out four specific types of EGS projects it is looking to fund:

  • a “proximal” demonstration that is located near an existing geothermal project and uses existing infrastructure (one to four awards, of $5 million to $15 million each);
  • a “greenfield” demo on a site “with no existing geothermal development” and the potential for tapping geothermal resources closer to Earth’s surface (one to three awards of $5 million to $25 million each);
  • a super-hot, supercritical EGS project drilling potentially several miles into the ground to tap into high-pressure water over 700 degrees Fahrenheit (one to two awards of $5 million to $25 million each); and
  • an East Coast EGS project located at a site with existing wells, such as old oil or gas drilling sites (one award of $5 million to $9 million).

All the projects would have immediate or near-term potential to produce electricity or heat. The RFI envisions having an open application process for the funds, with rolling submissions stretching out over two years, and project reviews every six months.

It also asks stakeholders — developers, researchers, tribes, and community and labor groups — to provide feedback on how federal funding can have the greatest impact on covering upfront development costs, building out an inclusive workforce, and benefiting low-income and disadvantaged communities.

Two questions also focus in on supply chain issues, asking what incentives or programs might be needed to “encourage and foster U.S. manufacturing” and what key construction materials — such as iron, steel or other manufactured goods — might not be available domestically.

The RFI also notes that under federal regulations, the applicants for the DOE funding would have to match the amount of the grant, for a 50/50 split. However, DOE is hoping to reset that equation, with the department picking up 80% and awardees providing 20%, in recognition of the cost and complexity of the projects.

The deadline for responding to the RFI is May 13.

500,000 MW

The U.S. is the world leader in geothermal energy, but the country’s 93 geothermal plants located in seven Western states account for only 0.4% of national power generation, according to the Energy Information Administration.

At the same time, as Granholm stressed, geothermal represents a huge potential source of clean, dispatchable power that could balance the U.S. grid as more variable renewable energy projects come online. The U.S. Geological Survey estimates that more than 500,000 MW of EGS resources are available in the Western — about half of the current installed electric power generating capacity in the U.S.

The challenge that the DOE funding hopes to unlock is how to access those resources. While traditional geothermal produces energy by drilling into the ground to tap superheated geothermal brine through existing fractures or permeability in subsurface rock, “enhanced” geothermal uses engineered, manmade systems to tap into reservoirs located below rocks with “limited permeability,” said Lauren Boyd, DOE’s EGS program manager.

Speaking at a March webinar on DOE’s geothermal program plan for 2022-2026, Boyd said EGS requires specialized materials and tools that can be used in “very high temperature, very caustic environments. Commercializing EGS requires the manipulation of the subsurface in these environments; and so, we have the challenge of not only repeatedly controlling and enhancing permeability in general, but just doing that also at super high temperatures and depth, in corrosive environments.”

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NERC Standards Committee Moves Projects Forward

NERC’s Standards Committee agreed to advance several standards development projects in a relatively smooth meeting on Wednesday, with Vice Chair Todd Bennett of Associated Electric Cooperative Inc. filling in for the absent Chair Amy Casuscelli.

First up was Project 2020-02 (Transmission-connected dynamic reactive resources), which began after NERC’s 2017 Long-term Reliability Assessment raised concerns about the replacement of retiring synchronous generators by nonsynchronous sources such as wind and solar facilities. The committee approved the project in March 2020. (See “Approvals,” NERC Standards Committee Briefs: March 18, 2020.) Wednesday’s action was to accept the standard authorization request (SAR) proposed by the SAR drafting team and to appoint the SAR drafting team as the standard drafting team (SDT).

While the motion was approved without objection, Philip Winston, formerly of Southern Co., worried that because the SAR drafting team was approved nearly two years ago, committee members may have forgotten who was on the team. Winston suggested that when such actions are before the committee in the future, members “have an opportunity to go into the records and see” the roster of the SAR drafting team to refresh their memories. Latrice Harkness, NERC’s manager of standards development, said the ERO “can accommodate” the request.

The committee next turned to Project 2021-08 (Modifications to FAC-008) and the accompanying proposal to appoint members of the SAR drafting team for the project, intended to clarify a definition in the standard and the types of equipment to which it applies. Members voted to approve all 11 candidates recommended by NERC, including the chair, vide chair and team members.

Another SAR drafting team nomination prompted more debate, with Robert Blohm of Keen Resources asking for an explanation as to why NERC only recommended six candidates for Project 2022-01 (Reporting area control error definition and associated terms) out of the seven nominations received from industry earlier this year. In keeping with the committee’s practice, candidates were not identified by name, and attendees attempted to keep identifying information to a minimum.

Harkness responded that the nominee who was not recommended “did not meet the criteria” for SAR drafting team membership; NERC’s guidelines for nominee selection specify that either ERO staff or a registered entity must attest to the nominee’s expertise in the subject matter. However, Blohm said that requirement appeared to be “well addressed” based on the information about the nominee.

In addition, Blohm pointed out that the unrecommended nominee was the only one of the slate from Canada; while he acknowledged that this might be “overstepping the identification barrier,” he wondered if the team could afford to lose this perspective. Blohm moved that NERC’s recommended slate be approved, but with the addition of the seventh nominee. This proposal passed without objection.

The committee’s next action passed more quickly, as members voted unanimously to approve the SAR for Project 2021-06 (Modifications to IRO-010 and TOP-003) and appoint the SAR drafting team as the project’s SDT.

Also unanimous was the approval of the SAR drafting team for Project 2022-02 (Modifications to TPL-001-5.1 and MOD-032-1) as recommended by NERC, although Marty Hostler of Northern California Power Agency pointed out that the candidate list did not include any candidates belonging to distribution providers. He wondered if some had been identified as load-serving entities by mistake. Harkness said this could have been because of “a checkbox that needs to be deleted on the form” and promised to look into it.

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Consumers to End Coal by 2025 in IRP Deal with Mich. AG

Consumers Energy will stop using coal-fired generation in 2025 under a settlement announced Wednesday over its integrated resource plan.

CMS Energy’s (NYSE: CMS) Consumers filed its IRP with the Michigan Public Service Commission last June (Case No. U-21090).

Under the agreement with Michigan Attorney General Dana Nessel, the Citizens Utility Board of Michigan and the Sierra Club, Consumers agreed to close all three units at the J.H. Campbell coal plant in West Olive (1,388 MW) in 2025 in addition to two units it previously agreed to close at the D.E. Karn coal plant in 2023 (487 MW).

The deal makes Consumers, which got almost 35% of its power from coal last year, “among the first utilities in the nation to go coal-free by 2025,” the company said. The IRP would ensure its use of “90% clean energy resources by 2040.”

Under the IRP, Consumers, which provides natural gas or electricity to 6.8 million of the Michigan’s 10 million residents, will also:

  • retire Karn units 3 and 4, gas peaking plants totaling 934 MW, by May 31, 2031, unless they are needed for reliability;
  • acquire the 1,176-MW Covert natural gas generating plant in Van Buren County. The company agreed to drop its request to purchase three other gas-fired units: Dearborn Industrial Generation in Wayne County; Kalamazoo River Generating Station in Kalamazoo County; and Livingston Generating Station in Otsego County.
  • add nearly 8,000 MW of solar generation by 2040;
  • accelerate energy storage deployment, with 75 MW of energy storage by 2027, rising to 550 MW by 2040;
  • conduct a one-time competitive solicitation to provide the company with capacity credit in MISO Zone 7 starting in the 2025 planning year.

“Consumers Energy is committed to a just transition away from coal as a fuel source for electricity,” Brandon Hofmeister, senior vice president for governmental, regulatory and public affairs, said in a statement last June when the company announced its plan to end coal use. “We supported employees and communities impacted by our 2016 coal retirements by finding new roles for workers who wanted to stay, fulfilling our environmental responsibilities at the sites and helping local leaders pursue new economic possibilities. We plan to follow the same philosophy to help those affected by the proposed Campbell and Karn retirements.”

The deal must be approved by the PSC.

“The Michigan Public Service Commission should approve this settlement so Consumers Energy can get to work moving beyond coal by 2025, planning for worker transitions and building out a remarkable amount of clean energy,” said Mike Berkowitz, senior Michigan representative for the Sierra Club’s Beyond Coal Campaign. “This is a groundbreaking agreement that ensures Consumers Energy is meeting the urgency demanded by the climate crisis while creating homegrown green jobs. West Michiganders can breathe easier knowing the J.H. Campbell coal plant will soon stop polluting their air as well as Pigeon Lake, a tributary to Lake Michigan.”

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Federal Aid Likely Too Late to Save Palisades, Diablo Canyon Nukes

LANSING, Mich. — The U.S. Department of Energy’s lifeline to struggling nuclear generators appears unlikely to save the next three units scheduled to retire.

Entergy (NYSE:ETR) officials said Wednesday they are unlikely to seek federal aid to prevent the Palisades Nuclear Plant from closing as scheduled on May 31, despite entreaties from Michigan Gov. Gretchen Whitmer (D). And Pacific Gas and Electric (NYSE:PCG) said Diablo Canyon 1 and 2 are still scheduled for retirement in 2024 and 2025.

Whitmer sent a letter Wednesday to Energy Secretary Jennifer Granholm — her predecessor as governor — urging the department to use $363 million from the Civil Nuclear Credit (CNC) Program created by the Infrastructure Investment and Jobs Act (IIJA) to keep Palisades open. (See DOE Launches $6B Nuke Credit Program.) DOE opened applications for the $6 billion CNC program Tuesday.

Whitmer said saving the 800-MW nuclear plant, which employs 600 and is one of the state’s largest sources of carbon-free electricity, “is a top priority.”

Merchant Power Exit

But Entergy spokesman Nick Culp told RTO Insider the company would only reconsider its plans to close Palisades — part of the company’s broader exit from the merchant power business — if it received a purchase offer from a “credible formal buyer.”

In December, the Nuclear Regulatory Commission approved Entergy’s request to transfer Palisades, its nuclear trust fund and its spent fuel to Holtec Decommissioning International.

“Our focus at Palisades power plant remains on the safe and orderly shutdown of the facility in May,” the company said in a statement. “We acknowledge having recently been contacted by government officials about the facility potentially operating beyond May 2022. In addition to these conversations, we have and will continue to entertain discussions with qualified nuclear merchant plant owner/operators who may want to purchase and continue operating Palisades. However, it is important to note that no formal proposal to acquire Palisades has been made that provides an opportunity for continued operations and that eliminates the substantial financial and operational risks associated with unwinding the existing contract with Holtec.”

Entergy has been preparing to shutter Palisades since 2017 and has not refueled the plant since 2020.

“There are challenges that make continued operation of the facility beyond May 2022 difficult, including the pending transfer of more than 130 employees to other parts of Entergy’s business and planned employee retirements post-shutdown,” the company added. “Additionally, the plant is unable to operate beyond the target closure date due to the diminished power of its nuclear fuel as it reaches the end of its two-year operating cycle.”

Holtec issued a statement saying it was aware of Whitmer’s effort to keep Palisades operating. “We remain ready, should these efforts to keep the plant operational not be successful, to transition ownership to Holtec after the plant ceases operations for a safe, efficient decommissioning process,” it said.

Keeping Palisades open until at least the end of its current operating license, which expires in 2031, has split the state’s environmental community. While a number of environmentalists have called for keeping the plant open to aid decarbonization efforts, others oppose nuclear generation.

During public testimony on developing the MI Healthy Climate Plan — the final version of which is due to Whitmer by Friday, Earth Day — keeping Palisades open drew comments from supporters across the nation. The first version of the plan to make Michigan carbon neutral by 2050 did not discuss the plant.

Expiring PPA

CMS Energy’s (NYSE:CMS) Consumers Energy, which put Palisades into service in 1971, sold the plant to Entergy in 2015 while purchasing most of its output under a power purchase agreement scheduled to expire this year.

Entergy and Consumers agreed to end the PPA early and close Palisades in 2018, but they canceled those plans under pressure from the Michigan Public Service Commission. Prices under the PPA ranged from $43.50/MWh in 2007 to $61.50/MWh in 2022, with an average of $51/MWh.

A CMS spokesperson said the utility would not oppose continued operation of the plant, located in Covert Township on Lake Michigan. “If the power from the plant could provide competitively priced and reliable energy for our customers, we would consider working with our partners to keep the plant open,” CMS’ Katie Carey said.

Whitmer’s letter said that “Michigan has already had numerous conversations with the plant owner and leading nuclear operators who may be interested in purchasing the plant and keeping it operational through its 2031 [NRC] licensure date.”

“If another buyer does not materialize and Entergy maintains its stance, Gov. Whitmer might look to other sources of leverage to keep the plant in service, and Secretary Granholm could prove a valuable ally in this respect,” ClearView Energy Partners said Wednesday, citing two options: invoking the Defense Production Act to prevent plant closures, or seeking relief from the NRC.

The commission’s December 2021 press release announcing its license transfer approval said it was “subject to [the NRC’s] authority to rescind, modify or condition the transfer based on the outcome of any subsequent hearing on the application.”

In February 2021, Michigan Attorney General Dana Nessel requested a hearing on whether Holtec has sufficient financial strength to decommission Palisades. “If the NRC were to grant that request, it could delay the transfer (and perhaps even ‘rescind, modify or condition’ it),” ClearView said.

No Takers for First Round of CNC Program?

DOE says 12 commercial reactors have closed early since 2013 because of economic pressures. Illinois, New Jersey, Connecticut, Ohio and New York have approved subsidies to keep plants operating within their borders.

DOE’s CNC program will allow owners of commercial nuclear reactors at risk of closure to competitively bid on credits to keep them in operation. The IIJA requires applicants to prove their reactor will close for economic reasons and that the closure will result in increased air pollution. Credits would be allocated over a four-year period.

The department will accept applications for its first round of CNC funding through May 19. While the first cycle will be open to reactors that have already announced their intention to cease operations, future cycles — beginning with the second cycle in the first quarter in FY2023 — will “not be limited to nuclear reactors that have publicly announced their intentions to retire,” DOE said.

According to the Nuclear Energy Institute, Palisades and PG&E’s Diablo Canyon 1 and 2 are the only operating nuclear units that have announced retirement plans.

“PG&E is committed to California’s clean energy future, and as a regulated utility, we are required to follow the energy policies of the state,” PG&E spokesperson Suzanne Hosn told RTO Insider. “At this time, the state has not changed its position regarding the future of nuclear energy in California. The plan to retire Diablo Canyon Power Plant was introduced in 2016 and approved by the California Public Utilities Commission, the State Legislature and Gov. [Jerry] Brown in 2018.”

Matt Crozat, executive director of policy development at NEI, said his group “will work with our members to ensure this program [CNC] is as effective as possible and continue to advocate for a production tax credit, which will offer greater certainty for owners to make long-term investments in their carbon-free nuclear plants.”

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New York Utilities Report Slow Start to EV Fast Charging

New York’s investor-owned utilities have seen a slow rollout of EV fast-charging stations under the state’s $701 million incentive program to build 50,000 such stations by 2025, according to reports filed with state regulators this month (18-E-0138).

Con Edison (NYSE: ED) reported 34 EV charging sites participating in its incentivized infrastructure program last year, including 25 Level 2 (L2) charging stations and nine direct current fast charging (DCFC) stations, collectively representing just 2% of the total 1,492 site applications received by the utility.

Con Edison 2021 EV (Con Edison) Content.jpgEV Make-Ready Program 2021 participation in Con Edison territory, including for disadvantaged communities (DACs). | Con Edison

 

The company’s Orange and Rockland (O&R) subsidiary reported three charging sites operating, or nearly 10% of the 31 total site applications received.

The New York Public Service Commission’s DC fast charger order of 2019 established a per-plug incentive program to encourage development of DCFC stations and directed the state’s utilities to file detailed annual reports on the buildout. Similarly, the PSC’s make-ready order of 2020 established a program to encourage development of L2 and DC fast chargers throughout the state, providing incentives to offset the utility and customer capital costs of eligible charging infrastructure.

Customer Benefits

The commission last November issued its EV infrastructure order approving tariff changes to fund the make-ready program that incentivizes utilities and charging port developers to site EV charging infrastructure in places that best benefit drivers.

The PSC allocated a minimum of $206 million toward equitable access and benefits for low-income and disadvantaged communities, where EV charging ports are eligible for an incentive supporting up to 100% of site preparation costs.

The commission also directed the utilities to file detailed annual reports on these programs and to combine their make-ready program reports with their DC fast charger reports. The joint utilities hired Atlas Public Policy to serve as their common third-party contractor to help prepare the annual reports.

The New York Power Authority is dedicating $250 million through 2025 to its related EVolve NY program, which is installing fast chargers throughout the state, including a recently completed 10-charger site at JFK Airport.

EV Charging JFK (NYPA) Content.jpgThe New York Power Authority is spending $250 million through 2025 on the EVolve NY program to install fast chargers throughout the state, including a 10-charger site at JFK Airport. | NYPA

 

In announcing a state-sponsored EV test track at the New York International Auto Show in April, NYPA Interim CEO Justin E. Driscoll said, “We will soon have 100 fast chargers strategically located throughout the state, including at airports, municipal and private parking lots and convenience store locations.”

Con Edison and O&R filed participants’ charging customer fee structures, charging revenue and operating cost data as collected by third-party data aggregator Atlas Public Policy, but confidentially, with relevant parts redacted.

Con Edison said 19 sites did not report their fee structure after at least four outreach attempts by Atlas and Con Edison to collect data, and four sites did not report valid operating costs after at least four outreach attempts.

Con Edison said it will continue to work with participants who are not currently reporting some or all data to bring them into compliance with the reporting requirements of the PSC’s order.

Central Hudson reported 5% of applications having matured into operational stations, with 16 L2 chargers and 21 DCFC stations working as of Dec. 31, 2021.

National Grid (NYSE: NGG) reported 431 applications received for its Niagara Mohawk Power subsidiary, of which 108 (25%) matured into operating stations, or paid projects, in 2021, including a total of four DCFC stations.

Avangrid (NYSE: AGR) subsidiaries New York State Electric and Gas (NYSEG) and Rochester Gas and Electric (RG&E) reported separately, with NYSEG reporting 21 charging stations operating out of 81 applications, including one DCFC station. RG&E reported no DCFC stations operating and 18 L2 stations operating out of a total of 78 applications.

Billing Details

As directed by the commission, all IOUs exempt from the EV surcharge the portion of load served under the Excelsior Jobs Program, which provides a state tax credit of 6.85% of wages per new job created.

Central Hudson includes cost recovery for the EV infrastructure surcharge from non-demand customers under the category of “miscellaneous charges,” with the combined amount shown as one line item on both regular and demand-billed customers’ bills.

According to NYSERDA, the demand charge is a monthly fee that customers pay as part of the cost of maintaining the electric utility’s infrastructure required to deliver electricity to the building or site. For large commercial or industrial customers, demand charges make up a sizable portion of their utility bill, with the amount based on peak energy use measured in kilowatts.

Con Edison is including its EV surcharge in the “monthly adjustment clause” line item on customers’ bills and collecting the surcharge $1/month basis for NYPA customers. O&R includes the surcharge in its “energy cost adjustment” line item.

National Grid includes the EV surcharge in the delivery rate line item on customer bills, while NYSEG and RG&E add it to their respective “transition charge surcharge” line items on customer bills.

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Midwest Energy Policy Series Addresses JTIQ Projects

MISO and SPP planners discussed the prospects of the Joint Targeted Interconnection Queue (JTIQ) projects during a Tuesday infrastructure session of the Missouri Energy Initiative’s Midwest Energy Policy Series.

The seven projects in the $1.65-billion JTIQ portfolio are projected to resolve 48 reliability constraints and enable 11.1 GW of generation projects on SPP’s side of the RTOs’ seam and 17.5 GW of projects on the MISO side. The grid operators are hoping to receive the portfolio’s approval by the second half of 2023, but they first must hammer out a cost-allocation methodology for the projects. (See Now, the Hard Part: MISO, SPP Tackle JTIQ Cost Allocation.)

“Unfortunately, we’re not quite over the hump just yet. … We still have to figure the cost allocation to get these projects built,” MISO Director of Resource Utilization Andy Witmeier told attendees.

But both he and SPP’s Neil Robertson, senior engineer of interregional relations, agreed that the study has been a success so far.

Robertson said planners were given a “free hand” in developing the study, “unique” among their interregional planning, which is usually scripted according to their joint operating agreement.

Witmeier agreed that planners were given a “blank page” to study the transmission needs of multiple generator interconnection cycles in the RTOs’ queues.

Robertson said staff are trying to distribute costs based on the projects’ beneficiaries, including MISO load, SPP load, and interconnection customers on either side of the seam whose generation will flow between the footprints.

“We continue the theme of the free hand in developing innovative solutions here,” Robertson said of a cost-sharing design.

Witmeier said the grid operators’ “guiding principle” of cost allocation will underscore the study’s aim to maximize capacity additions. He said while the two might consider assigning costs based on added benefits like increased flows or more economic dispatch, they will be secondary and fleshed out later.

Witmeier also said project duplicates between the JTIQ and MISO’s regional long-range transmission plan (LRTP) emphasize the projects’ necessity. MISO has decided that it will independently pursue 345-kV LRTP projects in North Dakota and Minnesota before they are included in the JTIQ study. With the two projects, the JTIQ portfolio would be reduced to about $1 billion. (See MISO Stakeholders Uneasy Over Long-range Tx, JTIQ Overlap.)

“It certainly means that it’s transmission that needs to be built now,” Witmeier said of the LRTP projects. He said MISO has decided it needs the lines now, rather than later, to reliably serve load, support new generation, and keep pace with members’ changing resource portfolios.

“We see benefits to these projects now,” he said, noting that MISO already has worked out a cost-allocation design for the LRTP.

The planners acknowledged that the RTOs’ results differ in how much new generation the JTIQ portfolio can facilitate. They said they used their respective planning models and generation dispatch assumptions to estimate gigawatt amounts.

“This was not what in the planning world we would call a common model study,” Robertson said. “We did not collectively develop a single model that both organizations performed analyses on. We levered our regional model processes.”

Had the RTOs tried to develop a common model, Witmeier said, “we’d still be doing the analysis today.” He said creating a common model would be too time-consuming to meet their 18-month study timetable.

The planners also said the JTIQ study forced them to pivot from a “first-come, first-served” queue priority approach to a “first-ready, first-served” method.

Witmeier said MISO is still processing applications that were submitted in 2019 and 2020, while SPP is working on interconnection requests submitted in 2017. In some cases, MISO interconnection customers that entered the queue in 2018 are already signing generator interconnection agreements, the final step before grid access.

“It doesn’t make sense for our projects to be held up by the projects in SPP’s queue that still haven’t been sited yet,” Witmeier said. Robertson agreed that the grid operators must “evolve” beyond the instinct that whoever lines up first must finish first.

Panel moderator and RTO Insider Editor-in-Chief Rich Heidorn asked whether MISO and SPP are worried about state commissions opposing JTIQ transmission projects.

“I feel like MISO and SPP have both been very successful in recent years in getting a significant amount of transmission expansion projects built,” Roberston said. “I can’t necessarily say it hasn’t been without its bumps in the road, but we have shown a consistent track record of success over the last, let’s say, decade or so.”

Robertson acknowledged that MISO’s and SPP’s footprints contain multiple states with right-of-first-refusal laws and the RTOs “will have to account for that.”

“We have a number of conversations ahead of us in getting to a complete cost-allocation methodology and accounting for the nuances around actually getting these facilities sited and constructed is certainly going to be a prominent component,” he said.

Heidorn also asked whether MISO was considering speeding up plans for a project that could increase MISO’s transfer capability between its Midwest and South region. He noted MISO Midwest came up short on supply in last week’s capacity auction. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Witmeier said MISO is discussing the potential of accelerating the study of potential projects. The RTO is not planning to address Midwest-South transfer projects until the final cycle of its four-part LRTP. (See MISO Seeking New Tx Cost Allocation for Major Buildout.)

MISO may “pull that trigger and move that forward,” Witmeier said.

However, he said, any approved transmission project is years away from allowing increased flows between the regions.

“That’s not going to be an immediate fix,” he said.

Experts Expect Carbon Capture, Storage, Renewables

Other series panelists predicted a raft of renewable generation, carbon capture and energy storage ubiquity in the Midwest, but they worried that lengthy interconnection queues will hold up necessary capacity.

Evergy’s Kayla Messamore said renewable technologies can’t singlehandedly meet all capacity needs. She predicted carbon capture, some nuclear generation and hydrogen generation will make up “that last 20%” of fuel resources that need to be “a little more firm.”

When asked what she would spend $1 billion on over the next five to 10 years to accelerate the energy transition, Messamore said she’d invest in a combination of wind and solar, longer-duration storage, and demand side management.

Anna Sommer of the Energy Futures Group said spiking energy prices should have more utilities focusing on demand response to control rates.

Messamore also noted that prohibitively high IC costs are limiting the generation that could interconnect to the system. She said new transmission is needed to integrate renewable generation and prevent energy price separation between regions that can’t access low-cost renewable energy.

Great Plains Institute’s (GPI) Patrice Lahlum said carbon capture and sequestration is poised for major growth.

She said that currently, 12 commercial-scale U.S. facilities capture about 25 million metric tons of CO2 annually. She said the nation’s growing carbon-management industry could deliver a 13-fold increase in CCS capacity by 2035, resulting in 210-250 million metric tons of annual emissions reductions.

Lahlum said GPI has tracked nearly 90 announced projects since 2018, with more than 50 announcements in 2021 alone.

She noted that the Infrastructure Investment and Jobs Act contains more than $12 billion in funding for carbon management. She said it’s up to the industry to work together and create successful projects that capture emissions as intended.

Consortium for Battery Innovation’s Matthew Raiford predicted a flourishing market for lead acid batteries. He said the advanced batteries are easily recyclable, keeping materials in a stable supply chain.

Some panelists worried about the hostility that existing renewable technology faces in the Midwest.

Renew Missouri’s James Owen said some Midwestern communities are still anxious about wind development and mount opposition campaigns over noise levels, turbine height and blinking lights.

“We still think there’s a lot of people that have a lot of misinformation,” he said.

Owen said social media is a hotbed for false narratives that influence the public and lead to restrictive ordinances.

Enel North America’s Gina Mace said combatting misinformation in communities is a major task for her company. She also agreed backlogged and time-consuming queues remain an obstacle to getting new generation built.

Mace also said though it appears transmission can support new generation, transmission construction can take the better part of a decade. She said it’s unclear how near-term generation will come online.

Owens added that he remains concerned that a state public service commission can effectively veto multistate transmission projects.