Search
`
November 16, 2024

Posted on

FERC Opens Probes on Western Transmission Rate Protocols

FERC on Thursday ordered show cause proceedings on the transmission formula rate protocols of five Western utilities, saying they do not appear to provide customers and regulators the ability to challenge rates resulting from the formulas.

The commission opened proceedings under Section 206 of the Federal Power Act on the formula rate protocols of PacifiCorp (EL22-38), Idaho Power (EL22-37), Puget Sound Energy (EL22-41), Public Service Company of New Mexico (EL22-40) and Public Service Company of Colorado (EL22-39) (NASDAQ: XEL).

The commission said the companies’ rate protocols did not meet the standards it has required since a 2012 order regarding MISO’s transmission owners.

Under formula rates, the commission does not require transmission owners to make FPA Section 205 filings to update their annual transmission revenue requirements. Instead the utilities update the input data in the formulas.

“Safeguards need to be in place to ensure that the input data is correct, that calculations are performed consistent with the formula, that the costs to be recovered in the formula rate are reasonable and were prudently incurred, and that the resulting rates are just and reasonable,” FERC said.

“Formula rate protocols provide the parties paying for transmission service specific procedures for notice of, review of, and challenges to the rates that they will be charged. In order to fulfill this purpose, formula rate protocols must afford adequate transparency to affected customers, state regulators or other interested parties, as well as provide mechanisms for resolving potential disputes.”

The commission’s orders Thursday found that each of the five utilities’ protocols fell short on one or more of the following:  “(1) the scope of participation (i.e., who can participate in the information exchange); (2) the transparency of the information exchange (i.e., what information is exchanged); and (3) the ability of customers to challenge transmission owners’ implementation of the formula rate as a result of the information exchange (i.e., how the parties may resolve their potential disputes).”

In the 2012 MISO order, the commission ruled that the MISO’s protocols inappropriately limited who could participate in the review processes and directed MISO and the transmission owners to revise them to include all interested parties, including customers under the MISO tariff, state utility regulatory commissions, consumer advocacy agencies and state attorneys general (143 FERC ¶ 61,149).

Similarly, the commission said Thursday that PacifiCorp’s protocols do not define the term “interested party” to identify who is eligible to participate. “Without such a definition, PacifiCorp’s formula rate protocols may not provide sufficient clarity and may provide PacifiCorp with the discretion to determine who is an interested party, and therefore appear to be unjust and unreasonable,” the commission said.

In the Puget Sound order, the commission said the utility’s protocols regarding challenge procedures lacked “straightforward and defined procedures” or “the level of specificity required” in the MISO standard.

It ordered each of the utilities to respond within 60 days to either show cause as to why its protocols remain just and reasonable or explain what changes it will make to remedy the commission’s concerns.

Posted on

FERC Fines NY Hydro Operator $600K for Safety Violations

FERC on Thursday ordered the former operator of an upstate New York dam to pay $600,000 in civil penalties for failing to make needed repairs over six years and retain possession of all property needed to access the facility (P-9685-034).

Ampersand Cranberry Lake Hydro has 60 days to pay the fine for violating its hydroelectric license for the Cranberry Lake Project, located in St. Lawrence County, N.Y.

The project is owned by the Oswegatchie River-Cranberry Reservoir Regulating District Corp. (OR-CRRDC), a state municipal corporation. It includes a 57,400-acre-foot reservoir contained by dam that is 195 feet long and 19 feet high.

“The dam has a high hazard potential rating, which means that a failure of the project works would result in a probable loss of human life or economic or environmental losses,” FERC said.

Under FERC rules, hydro licensees are required to maintain property rights to their projects to provide access to the land associated with a dam in order to make repairs when necessary.

“In this particular case, Ampersand didn’t maintain those access rights. And thus, if something does go wrong or might go wrong, they don’t have the ability to access the site to make repairs that are necessary,” FERC Chairman Richard Glick said in a statement Thursday. “And this particular dam is classified as having a high hazard potential, so that’s something that we take very seriously.”

Thursday’s order follows an October 2021 commission issuance directing Ampersand Cranberry Lake to explain why it should not be assessed a civil penalty for violating its hydroelectric license and a November response by the company acknowledging that it failed to retain possession of all project property, in violation of its license. (See FERC Hits NY Hydro Plant for Delayed Repairs.)

FERC granted Ampersand Cranberry a license for the project in 2015 after the company promised to complete safety work related to the facility’s fuse plug spillway in the dam’s embankment and to raise the earthen embankment crest. The company notified the commission last July that it had agreed to terminate its lease and give up access rights to the project site to settle litigation with OR-CRRDC, which sued the company in 2019 over its failure to make rent payments.

FERC said the settlement came despite its repeated warnings that terminating the lease would violate the company’s license and would not relieve it of its responsibility to complete the outstanding work on the dam.

Posted on

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.

Posted on

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.
Posted on

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.

Posted on

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.

Posted on

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.”

Posted on

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.

Posted on

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.”

Posted on

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.”