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August 29, 2024

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CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS

CAISO scored a geographically small but symbolically significant victory in its contest with SPP on Aug. 28 with the announcement that two Black Hills Energy subsidiaries serving parts of Montana, Wyoming and South Dakota will move from SPP’s Western Energy Imbalance Service (WEIS) to the ISO’s Western Energy Imbalance Market (WEIM).

The decision by Black Hills Power and Cheyenne Light, Fuel and Power will expand the WEIM’s presence in Montana and Wyoming and extend its footprint eastward to take in a slice of South Dakota, which would become the twelfth state included in the market.

“The agreement with California ISO provides the company with options to support reliability and system balancing, while paving the way for Black Hills Energy to participate in California ISO’s Western Energy Imbalance Market, starting in 2026,” Black Hills Energy said in an email to RTO Insider.

“We are very pleased to begin this process with Black Hills Energy to deliver future economic and reliability benefits to its customers,” CAISO CEO Elliot Mainzer said in a statement.

But the decision might be most consequential as another development in the ongoing competition for participants between SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM), the latter of which builds on the WEIM.

In 2022, SPP said it would eventually phase out its real-time WEIS once its other Western market efforts gathered more momentum and members. (See SPP to Phase Out WEIS as New Market Offerings Expand.) At the time, SPP said it intended “to only provide one market offering in the West in order to provide maximum benefits for Western utilities” and that WEIS participants “will have the option to join the RTO or participate in Markets+.”

That projected outcome seems to have played a role in Black Hills’ decision to migrate to the WEIM.

“The planned formation of the SPP RTO West required us to assess our future market path, as it did not appear that the WEIS market status quo would remain an option after RTO West is operational,” the utility told RTO Insider. “We have found imbalance market participation to be beneficial for our customers, and the opportunity for our utilities to participate in the WEIM allows us to continue to optimize our generation operations while maintaining our high reliability and creating long-term value for the customers we are privileged to serve.”

Asked whether it is now considering joining the EDAM, Black Hills said it “will continue to monitor and be engaged in the development of markets in the Western Interconnection and will pursue future markets that provide additional value for the company and our customers.”

After joining the WEIS in 2023, both Black Hills subsidiaries participated in the extensive “Phase 1” effort to develop the tariff for Markets+, which SPP filed with FERC in March — and for which it received a deficiency notice last month. (See SPP Dispels Concerns over Markets+ Deficiency Letter.)

Black Hills offered an equivocal response to another question about whether it plans to continue funding Markets+ during the Phase 2 implementation process, reiterating that it will continue to “monitor and be engaged in” Western market developments.

An SPP document shows that Black Hills Power would be responsible for providing a 0.9% share of Phase 2 funding, while Cheyenne Light would be on the hook for 0.6%, amounts other funders would be required to cover if the two utilities withdraw from the effort. SPP estimates Phase 2 will cost about $150 million. (See BPA to Delay Day-ahead Market Decision, Sources Say.)

“SPP is aware of the announcement by Black Hills and continues to support each market participant’s ability to decide on a market choice that they consider best for their customers,” SPP spokesperson Meghan Sever said in an email. “The decision by Black Hills does not impact the viability of Markets+ or the RTO expansion in the West.”

Another Western BA

According to an integrated resource plan the utilities jointly filed with the South Dakota Public Utilities Commission in 2021, Cheyenne Light and Black Hills Power together serve more than 117,000 customers and operate 1,344 miles of transmission, most of which are maintained by the latter utility. That system interconnects with PacifiCorp and the Western Area Power Administration’s Rocky Mountain Region.

While both utilities sit within WAPA’s balancing authority area, the WEIM implementation agreement signed between CAISO and Black Hills Energy on July 31 stipulates that one of the utilities will be required to register a new BA to facilitate participation in the market.

The utilities’ 2021 IRP included a study by NAES that found they “are well situated to become a BA” but noted that maintaining it would cost between $5.77 million and $10.21 million annually, compared with costs of $3.54 million to $5.28 million a year for remaining in WAPA. Moving into PacifiCorp’s neighboring BA would cost the two utilities $3.10 million to $3.21 million annually, the study found.

“The implementation agreement supports our South Dakota and Wyoming electric utilities as they prepare to transition from the Western Area Power Authority, which currently provides balancing authority services, to a new BA in 2026,” Black Hills told RTO Insider.

That move would bring the number of Western BAs to 39.

The Black Hills announcement comes two days after the Bonneville Power Administration said it will delay its choice of a Western day-ahead market until next year. (See BPA Postpones Day-ahead Market Decision Until 2025.)

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Colorado PUC Adopts Rules for Utility Participation in Markets

Colorado’s investor-owned utilities must compare available alternatives when asking regulators for approval to participate in an RTO or ISO, under a decision by the Colorado Public Utilities Commission.

The comparison must include “sufficient modeling and other analytical support” showing the expected net benefits of participating in a particular RTO or ISO are similar to, or greater than, net benefits from other available options.

But such a comparison is not required when utilities seek approval to join a day-ahead market, the PUC said in its decision, issued Aug. 22.

The decision comes as CAISO’s extended day-ahead market (EDAM) and SPP’s Markets+ are in a heated battle for day-ahead market participants across the West. Colorado utilities have a choice among EDAM and Markets+, as well as SPP’s RTO West, a proposed extension of services offered in the Eastern Interconnection.

The PUC decision, which adopts rules regarding utility participation in organized electricity markets, was prompted in part by Senate Bill 21-072 from the state’s 2021 legislative session. The bill requires transmission utilities to join an organized wholesale market by Jan. 1, 2030.

The PUC’s new rules list factors the commission will consider in evaluating a utility’s request to join an RTO, ISO or day-ahead market.

PUC Chairman Eric Blank, who was the hearing commissioner in the case, issued a recommended decision in June.

Ten groups then filed a joint request to modify the decision to include a comparison of alternatives in evaluating a request from investor-owned utilities to join an RTO, ISO or day-ahead market. They asked that the comparison of benefits be based on “a nodal mapping of the Western Interconnection and at least three years of simulated market operations.”

“We believe that it is impossible for the commission to determine that utility participation is in the public interest without an analysis of the market options that are available to a utility,” the commenters said in their joint filing.

The groups that jointly commented include Advanced Energy United, Clean Energy Buyers Association, Interwest Energy Alliance, Western Grid Group and Western Resource Advocates.

Loss of Control

In explaining its decision, the commission said utility participation in RTOs or ISOs raises more concerns than participation in less-integrated offerings such as day-ahead markets.

In an RTO, utilities give up control of their transmission assets and much of their decision-making to a regional governance process, the PUC said. The PUC also cited the need for “timely review” of day-ahead market applications.

The PUC adopted the requirement for a comparison of alternatives in an RTO request but left out the need for nodal mapping that the commenters requested. That way, the commission said, utilities will have “more flexibility in the type of modeling or analytical support that may be used.”

In a statement after the decision, Western Resource Advocates said it was pleased with the commission’s decision to require a comparative analysis of options for joining an RTO, but disappointed the requirement didn’t extend to day-ahead market participation.

The joint request from WRA and other groups noted that “the landscape of Western market footprints is rapidly evolving” as utilities evaluate EDAM, Markets+ and SPP’s RTO.

“Because of the highly dynamic nature of market footprints, and the significant impact of these footprints on benefits and risks to Colorado consumers, neither the IOUs nor the commission can truly understand the potential costs and benefits without a comparative analysis of alternative market participation under different footprint scenarios,” the groups said in their filing.

Utility Requirements

The decision keeps in place other requirements from Blank’s recommended decision for utilities that want to join an RTO, ISO or day-ahead market.

The RTO, ISO, or day-ahead market that an investor-owned utility wants to join must have a greenhouse gas tracking and accounting system.

Detailed modeling must show that benefits of joining, such as production cost decreases, reliability improvements and emission reductions, will be greater than the expected costs.

And there must be a plan for efficient dispatch and exchange of energy if there is more than one regional market construct operating or proposed to operate in Colorado.

Additional requirements apply when the request is to join an RTO. For example, the RTO must have a regional resource adequacy construct and a plan for new transmission.

The requirements are simplified for a request from a cooperative electric generation and transmission association

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Report Quantifies Consumer Savings from Biden-era Efficiency Standards

The average household should save $107 on utility bills every year because of the efficiency standards crafted by the Biden administration, according to a new analysis released by the Appliance Standards Awareness Project (ASAP) and PIRG. 

The study calculates savings in each state as old appliances are replaced with new models that meet the standards. Impacts change by state based on energy prices and heating and cooling needs, among other factors. 

The study expects businesses around the country will save $2 billion annually. It also lays out the air pollution cuts (in nitrogen oxides and sulfur dioxide) that each state can expect from the standards. 

“Consumers are going to save money year after year thanks to efficiency standards set during the Biden administration,” ASAP Executive Director Andrew deLaski said in a statement. “Whether you’re replacing a water heater, a clothes dryer or another appliance, these standards are going to ensure you get a better product that doesn’t leave you with needlessly high utility bills.” 

The Department of Energy periodically updates efficiency standards for new products such as refrigerators, water heaters, air conditioners and electric motors. Since President Joe Biden took office in 2021, the department has issued about two dozen standards, which together offer savings in every state ranging from $67 in Utah to $285 in Hawaii. 

Most of the standards set during Biden’s term will only start taking effect between 2026 and 2029, with the study looking at how they will impact utility bills and other areas over the next two decades. 

The standards all offer net benefits in terms of bill savings, but a handful have more significant impacts, the report said. The biggest savings come from water heaters, light bulbs (“general service lamps”), washing machines, refrigerators, clothes dryers, pool pump motors and furnaces. 

“All the standards save consumers more money than they cost; we estimate that the total utility bill savings for household products outweigh any increases in purchase price by more than a factor of three,” the report said. 

The study quantifies how the new standards will cut NOx and SO2 pollutions, which are emitted by power plants and gas-fired appliances. The pollutants are harmful to the respiratory system and contribute to respiratory conditions, especially in children, the elderly and people with asthma. 

The study said the standards should cut NOx emissions annually by 11,700 tons and SO2 by 5,100 tons. 

“New standards for clothes washers and dishwashers will also reduce water waste, helping to reduce stresses on water supplies in drought-stricken areas,” the report said. 

Smaller states will save about 100 million gallons annually, while the most populated will save billions each year. Cumulatively the entire country will save more than 1 trillion gallons of water over the next two decades, the report said. 

“These updated standards will save consumers money and reduce air pollution for years to come, just by the use of more efficient appliances. It’s a clear win for Americans’ wallets,” PIRG Energy and Utilities Program Director Abe Scarr said in a statement. “For households and businesses across the country, the prospect of sustained annual utility bill savings and cleaner air is welcome news.” 

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NERC Examines Transfer Capability in Draft ITCS Installment

NERC has posted in draft form the first results from the Interregional Transfer Capability Study ordered by Congress in 2023, summing up the transfer capabilities between transmission planning regions in North America.  

The ERO Enterprise — including NERC, the regional entities and all North American transmitting utilities — has been working on the ITCS since Congress mandated the study in the Fiscal Responsibility Act. Under the FRA, NERC must file the finished report with FERC by December. The study includes “significant collaboration” with a host of additional stakeholders, including transmission planners, owners and operators; planning coordinators; state, provincial and federal partners; utilities; and trade groups. 

The Transfer Capability Analysis released Aug. 28 represents Part 1 of the ITCS, following the publication of NERC’s Overview of Study Need and Approach in July. (See NERC Promises 1st ITCS Results by August.) Results from this installment will be used for Part 2, a draft of which is scheduled to be released in November and will recommend prudent additions to transfer capability that could strengthen grid reliability.  

Part 3, laying out recommendations to meet and maintain total transfer capability, is expected to be released in draft form in November as well. A final installment focusing on Canada is to be published in the first quarter of 2025. 

The transfer capability analysis covered two different base cases: one based on summer 2024, the other on winter 2024/25. NERC used the transmission planning regions identified in FERC Order 1000 as a starting point for studying transfer capacity, as required in the FRA. The project team further subdivided these regions in some cases to account for the geographic variations and resulting internal transfer constraints in some areas. 

Performing the transfer analysis involved simulating unplanned outages of various system elements during transfer analysis to discover the point at which the grid could not maintain reliability. The last step prior to a reliability issue was labeled the first contingency incremental transfer capability. This was added to the base transfer level, derived from scheduled interchange tables for each study case, to arrive at the total transfer capability of each. 

The study found that transfer capability “varies seasonally and under different system conditions [and] cannot be represented by a single number.” A map shared by the team showed that winter and summer transfer capabilities are closely matched in some cases — such as Washington to Oregon, which shows just a 200-MW difference between seasons — while other cases exhibit a wide disparity. 

For the link between California South and the Wasatch Front, for example, the transfer capacity in summer was reported as 6 GW, as opposed to just 1 GW in winter. MISO West reportedly could transfer 8 GW to PJM West in winter, but just 2.5 GW in summer.  

Other areas indicated no transfer capabilities in one season at all. SERC Florida was recorded as having a capacity of 1.3 GW into SERC Southeast in summer and none in winter, while California North reported a transfer capability to Oregon of 2.5 GW in winter and nothing in summer. 

NERC said transfer capabilities tended to be higher in the West Coast, Great Lakes and Mid-Atlantic areas, and lower in the Rocky Mountain states, Great Plains, Southeast and Northeast. Limited transfer capability exists between interconnections. This installment includes transfer capabilities from Canada into the U.S., but not the other way around; Part 4 will cover transfer capabilities from the U.S. to Canada and between Canadian provinces. 

In a media release, NERC warned that Part 1 should not be taken as a measure of energy adequacy in itself, but rather as simply a statement of the “magnitude of transfer capability.” That will be examined when NERC explores prudent additions “based on a holistic view of transmission and resource availability” in Part 2. 

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DOE Awards $240M for City, State Building Performance Standards

The U.S. Department of Energy aims to help cities and states reduce emissions and improve the efficiency and resilience of existing commercial and multifamily buildings with more than $240 million in grants to promote the adoption of building performance standards (BPSs).

Funded by the Inflation Reduction Act, the 19 awards announced Aug. 27 include grants for statewide programs in Colorado, Hawaii and Washington, as well as local programs in Chula Vista, Calif., Evanston, Ill. and Montgomery County, Md.

For example, Cincinnati, Cleveland, Columbus and Dayton, Ohio, are joining forces on a $10 million grant to develop a BPS and create a High Performance Buildings Hub, which will be a one-stop shop for “connecting building owners to financing solutions and incentives along with the support, education and training needed to meet BPS targets.”

Colorado is up for three separate awards:

    • $20 million for a statewide program to provide technical assistance for upgrading buildings in low-income, disadvantaged communities.
    • $7.5 million for Denver to implement its existing BPS and start working on future, more rigorous standards.
    • $5 million for Lakewood, a Denver suburb, to develop and implement a local standard in line with the state BPS and launch “a significant workforce development effort to support covered buildings.”

These and other similar awards underline the need for building performance standards for existing buildings, as a supplement to building energy codes that cover new construction. The grants also are intended to help boost the local capacity and workforce development needed for successful adoption and implementation.

“State and local governments are taking on advanced, proven solutions that will help [cut] energy bills while making their communities more resilient in the face of climate change,” Energy Secretary Jennifer Granholm said in the funding announcement. The IRA dollars will help “jurisdictions move further and faster in implementing stronger codes that will provide Americans safer, healthier and more comfortable places to live, work and play.”

Building Codes vs. BPS

With buildings across the United States — including 60 billion square feet of commercial floor space — accounting for about 35% of the country’s greenhouse gas emissions, the Biden administration earlier this year set ambitious targets for reducing emissions from buildings 65% from 2005 levels by 2035 and 90% by 2050.

Getting there undoubtedly will be complicated. Building codes cover new construction and major renovations, and in general are updated every three years by industry standards-setting bodies. The International Energy Conservation Code covers residential buildings, and the American Society of Heating, Refrigerating and Air-conditioning Engineers (ASHRAE) provides standards for commercial buildings.

But states determine whether to adopt the most recent codes. ASHRAE’s latest update in 2022 was 14.4% more efficient than the code released in 2019, according to DOE. An ASHRAE fact sheet notes that only Alabama, Indiana, New Jersey, Oregon, West Virginia, New York and Washington, D.C., directly adopted the 2022 update.

Building performance standards have become another flashpoint for state and local policy makers. Only one state, Maryland, has enacted a BPS that sets standards for both energy efficiency and emissions reductions for commercial buildings of more than 35,000 square feet. The law is scheduled to go into effect in 2025.

The rest of the country is a patchwork. Washington state, Oregon and Colorado each have set a BPS for energy use but not emissions. Seattle, New York City and Cambridge, Mass., have passed standards for emissions but not energy.

The Biden administration launched the National Building Performance Standards Coalition in 2022, with 33 state and local members and an ambitious goal for all participants to have equitable BPS programs and policies in place by Earth Day 2024.

At the end of 2022, coalition members accounted for 25% of all commercial buildings in the U.S. and, if they had met their BPS commitments, would have cut emissions equivalent to the GHG pumped out by 5.4 million U.S. homes. The coalition now has 46 members.

The IRA provides $1 billion to help cities and states adopt model and updated energy codes. The Aug. 27 announcement is the first round of awards for this program. Applications are open for a second round of awards, with a deadline of Sept. 13.

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DOE Details Strong Job Growth in Clean Energy

The Department of Energy on Aug. 28 reported the U.S.’ clean energy workforce grew 4.2% in 2023, twice the rate of the rest of the energy sector and economy overall. 

Total energy jobs reached 8.35 million, and clean energy jobs accounted for 42% of that, DOE said in its “United States Energy & Employment Report 2024,” the latest in a series of annual assessments of the country’s energy workforce. 

The document also serves as a report card of sorts for the Biden administration’s climate agenda and a measure of return on investment for the hundreds of billions of tax dollars being committed to boosting the economy by helping the planet. 

“Our policies are working,” Energy Secretary Jennifer Granholm declared in the news release announcing the report “We are now starting to see the job impacts of investments made through the infrastructure and Inflation Reduction laws — first in construction, and as America builds more of these factories, we’ll see hundreds of thousands more.” 

Altogether, the report indicates, clean energy employment grew by 142,000 jobs in 2023, or nearly 5% of all new jobs in the U.S. economy. 

And its growth rate is outpacing the “traditional” energy sector: Since 2020, employment in clean energy has increased by 400,000 jobs, or 12.8%, compared with 427,000, or 9.7%, in the rest of the energy sector. 

The 2024 edition is based on survey responses from a record-high 42,100 businesses nationwide and on data from the U.S. Bureau of Labor Statistics. It is the first report to tally construction jobs associated with buildout of U.S. clean energy manufacturing, which accounted for an additional 28,000 jobs in 2023. 

Details 

The 2024 report fills 221 pages with granular details on the components of the energy industry; a companion report drills down on state-level data for 361 pages. 

It defines clean energy as renewables and other non-fossil technologies that enable a transition to net-zero emissions. This includes carbon capture, storage and utilization, but not technology that allows for more efficient use of fossil fuels, such as high-efficiency furnaces. 

Details specific to clean energy include: 

    • Clean vehicle employment grew 11.4%, not counting battery manufacturing and electric vehicle charging. 
    • Solar industry employment grew 5.3%, and wind 4.6%. 
    • Union representation in clean energy grew to 12.4%, exceeding both the sector as a whole (11%) and the U.S. private sector (7%). 
    • Employers reported adding relatively few jobs related to EV charging in 2023 — just 559 — but as it is a small, emerging sector, this constituted 25% growth. 
    • Energy efficiency added the most jobs of any category — 74,700 — but as it is a large, established industry, this translated to only 3.4% growth. 

energy

Recent sector-specific job growth | DOE

Details specific to the energy sector as a whole include: 

    • Electric power generation jobs showed the fastest growth of any energy technology in 2023, adding 36,458 jobs while shedding just 870. 
    • Industries involved in transportation of coal, petroleum and other fuels shed 11.6% of their workforce. 
    • Unionized and non-unionized employers alike reported less difficulty finding workers to hire in 2023 than in 2022, though 40% of non-union firms still reported it “very difficult,” compared with only 24% of unionized firms. 
    • Some demographics are underrepresented in the sector: Black workers are 13% of the U.S. workforce but hold 9% of sector jobs; women are 47% of the U.S. workforce but hold 26% of jobs. 
    • Other demographics are over-represented: Workers under 30 comprise 29% of the workforce but 22% of the national workforce; Hispanic or Latino workers landed 31% of new jobs in 2023 but are 19% of the national workforce; veterans make up 9% of the workforce but only 5% of the national workforce. 
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Holtec Confident on Late 2025 Restart of Palisades Nuclear Plant

No nuclear power plant in the nation has restarted operations after shutting down, and Holtec International is detailing how it expects to accomplish the feat at the mothballed Palisades Nuclear Generating Station in a little more than a year.

Holtec, which provides decommissioning services and equipment for reactors and waste, has completed all submittals necessary for the U.S. Nuclear Regulatory Commission to consider authorizing a repower of the dormant Michigan plant. The company has notified the NRC of its intent to file for and submit all necessary documentation to secure a 20-year license extension so Palisades can generate power into 2051. The NRC said it plans to issue a draft report in early 2025 and release a complete report by mid-2025.

In an interview with RTO Insider, Nick Culp, senior manager for government affairs and communications at Holtec, said although Holtec expects NRC staff to be “very thorough in their review and oversight processes, we remain confident in our approach to seek reauthorization of power operations within the NRC’s existing regulatory framework.”

Culp said Holtec is optimistic Palisades will be generating output in October 2025. The NRC has told Holtec it expects to dedicate a full-time inspector to the site by December, Culp added.

A Model for Other Mothballed Plants?

Although it hasn’t restarted the 53-year-old plant yet, Holtec isn’t foreclosing subsequent license renewals beyond the 2051 timeline, and Culp said Palisades could become a model for reopenings at other plants.

“This is something we believe could be replicated at other shuttered nuclear plants, both here in the U.S. and abroad. We’ve seen that when nuclear power goes offline … fossil fuels are often used to backfill the demand for reliable baseload generation,” he said. “And as states like Michigan and the country seek to transition away from fossil generation, there’s been a renewed focus on nuclear being an important part of our future generation mix.”

Culp said Holtec’s original intent when it acquired the plant from Entergy in 2022 was to apply its business model of “safe but accelerated nuclear decommissioning” on Palisades. The company determined at the time the plant’s approximately $570 million decommissioning trust was sufficient for it to tackle the process.

Three years ago, Michigan Attorney General Dana Nessel argued unsuccessfully before the NRC that Palisades’ trust was about $200 million short of full decommissioning cost needs.

Holtec is decommissioning three nuclear power plants on the East Coast: Oyster Creek Generating Station, Pilgrim Nuclear Power Station and Indian Point Energy Center.

Culp said Holtec rethought their tactic with Palisades once they heard a “strong desire” from the community and state government to keep it open, particularly from Michigan Gov. Gretchen Whitmer (D).

“Historically, the support for Palisades in the local community has been strong. Shortly before the plant was to shut down, there were calls from the local, state and federal levels to stay online,” Culp said. “Things changed before the plant closed, as there was a recognition that if we want to be serious about addressing climate change and keeping the lights on, nuclear is an essential part of the equation. When Holtec became owner, there was already talk of the plant reopening.”

Nevertheless, Holtec began doing some early-stage decommissioning work when it came into possession of the plant in 2022.

“Nothing done in the early stages of decommissioning was irreversible,” Culp said, adding that Holtec first focused on cleaning up some spent fuel and recycling old equipment but made sure plant systems and equipment were preserved.

Culp said Holtec stopped drawing from the decommissioning trust as soon as it was inclined toward a reopening.

“As we shifted to a restart, we stopped pulling from that trust fund,” he explained. “The decommissioning trust is very sacred and only used for decommissioning-related activities. It will stay bound with the site and continue to grow over the course of plant operations.”

Culp did not disclose the total cost of restarting the plant and only said Holtec is making a sizable investment. The company’s contribution — paired with a recent $1.5 billion conditional loan from the Department of Energy as part of the Inflation Reduction Act and the state of Michigan contributing $300 million in grant funding — means that decommissioning is the cheaper option by a long shot. (See LPO Announces $1.52B Loan to Restart Palisades Nuclear Plant.)

“We’re doing a lot of investment to prepare the plant for future operation. But it’s substantially cheaper to bring this plant back online than build new generation from a value proposition,” Culp said.

Culp said the federal government is doing its due diligence to make sure Palisades is a good choice for the loan, which is essential to restoring operations.

“I would say it’s a critical part of it. If it were not for the federal government, state of Michigan support, our long-term power purchase agreements and our own investment, if it weren’t for those four funding streams, this would not be possible.”

When Palisades comes online, Culp said 100% of its 800 MW output will be spoken for between Wolverine Power and Hoosier Energy Cooperative in power purchase agreements that will span “more than the next 20 years.” Culp declined to outline how many megawatts each utility has signed on for, but confirmed Wolverine is the primary offtaker.

Condition, Workforce, Fuel Contract

Todd Allen, chair of the University of Michigan’s nuclear engineering program, said the most crucial aspects of restarting the plant include the material condition of the plant, recruiting a trained workforce and a fuel contract. He said the “right number of trained staff to operate this plant” is imperative.

“They’re going to have to make a convincing argument to regulators that nothing has changed,” Allen said in an interview with RTO Insider. “If you stopped running your car for three years … you would want to know, ‘do I want to put in new lube oil?’ Those are the kinds of questions that they will have to answer.”

Allen said if all those pieces are in place and NRC Chairman Chris Hanson can deliver a review within the year as promised, Holtec “might” be able to pull off a restart in 2025.

Allen said when previous owner Entergy put the plant on a pathway to decommissioning, the company likely deferred some maintenance, stopped buying fuel and thinned or scattered staff to other worksites. He said in order to convince the NRC to reinstate a license, Holtec will have to prove the plant has recovered fully from inactivity.

Culp acknowledged that near the end of Palisades’ 50-year run, Entergy deferred some maintenance that otherwise would have occurred if the plant was intended to keep operating. He said Holtec is tackling some of the plant’s cobwebs and just finished a deep cleaning of its primary coolant system. He also said some components of the plant have been sent offsite for refurbishment for the first time ever, and modular trailers are parked on site to conduct cleaning and inspection of steam generator tubes.

Culp said before Palisades’ shutdown, it achieved record-breaking production runs and was operating at the highest safety ranking by the NRC, a testament to the “excellent shape Palisades is in.”

Holtec is devoting itself to making sure Palisades has a talented workforce at the ready, Culp said.

“When we shut down, we kept a little more than a third of our workforce,” he said. “Since we’ve started to rehire, we’ve had a number of previous employees return.”

Culp said since the beginning of the year, Holtec has hired about 260 employees, including many former plant employees, bringing Palisades’ workforce from 220 to 480. He said the plant is on track to be fully staffed with more than 600 people by spring.

“We’re also getting industry veterans, we’re getting people fresh from the Navy’s nuclear training program,” he said.

Holtec is approaching local colleges and skilled trade unions for new employees, Culp said, and emphasized that not every job opening at Palisades requires a college degree.

Culp said 26 former licensed operators have completed requalification of their operating licenses, and prospective operators have begun their 18-month training. He said Holtec in late 2023 rebuilt the plant’s training simulator, restaffed its training organization and began using an abandoned, onsite training building again.

Returning the plant to service will be “transformational” for the community in southwestern Michigan, Culp said.

“People understand that this is clean energy, this is reliable energy, these are jobs, this is millions of dollars in annual tax revenue. It’s a huge economic driver,” he said.

Holtec secured fuel early in its restart journey, Culp said. He said the nuclear industry and its vendors, suppliers and trade unions have provided “vital support” for restarting the plant.

Shifting Public Opinion and ‘Zombie’ Moniker

Allen said the move to clean energy has tipped the scales on nuclear power’s public image, citing in particular Michigan’s MI Healthy Climate Plan, which calls for 100% carbon-free electricity by 2050.

“I think that the overall context for nuclear both nationally and globally has shifted more in favor over the past five or so years,” Allen said.

A recent survey from the Pew Research Center backs that claim, finding that 56% of American adults favor erecting more nuclear power plants to generate electricity, up from 43% in 2016.

But Palisades’ journey to restore operation faces opposition.

Anti-nuclear nonprofit Beyond Nuclear refers to Palisades as a “zombie reactor,” conjuring images of an unsafe and rickety plant being raised from the dead. (See Beyond Nuclear Leads Protest of Palisades’ Potential Reopening.) The group, along with grassroots organizations Michigan Safe Energy Future and Don’t Waste Michigan filed a petition and request for hearing this week with the NRC on Holtec’s transfer request for a renewed facility operating license to fire up Palisades. The trio said they also intend to file another petition and hearing request against exemptions needed from the NRC for Holtec to convert its possession-only license into an operating license.

They have called the restart unsafe, expensive and unnecessary, arguing that renewable energy paired with energy storage can fill the need for the plant. They’ve also said Holtec is inexperienced because it’s never operated a nuclear plant before.

Beyond Nuclear argued in an Aug. 28 press release that Holtec has performed a “con job,” and pointed out that eight days after Holtec took possession of Palisades in 2022, it already had submitted an ultimately unsuccessful bid for funding to reopen the plant under the Department of Energy’s Civil Nuclear Credit program. The group has asked the NRC to revoke its original Entergy-to-Holtec license transfer from 2021 in its entirety.

Allen allowed that doubts over a restart of the plant likely come from those always suspicious of nuclear power.

“The same tension was there probably before they shut. I doubt people with very strong opinions have changed their mind since. If you were always skeptical, then you’re probably still skeptical. I don’t think you can avoid that tension; it just exists,” Allen said. “I can come up with a list of why nuclear power is really great and why it’s really limiting. I don’t think any single source of energy is perfect on its own. We end up balancing the benefits and the drawbacks.”

Allen said residents who live in and around Covert, Michigan, on the whole probably are more comfortable with the plant’s resumed operations. He also said the plant’s large workforce needs are attractive to the community.

Nationally, Holtec is not the only nuclear operator that aspires to run a plant beyond 75 years, Allen said. He noted that the NRC’s original, 40-year licenses weren’t based on the technical ability of nuclear plants, but modeled after coal plants, which were the closest analog comparison at the time. He said a few other nuclear plants in the country have set their sights on 80 years of operations or more.

“It could still be a good car. You’d just have to do some checks to make sure,” Allen said. “Is Holtec asking to do something unique in the aspiration to go to 75 years? The answer is no.”

Allen said when Entergy made the decision to shut down the plant, there was less awareness that getting to zero carbon emissions would be so challenging. He also said surging demand growth from data centers complicates the clean energy transformation.

“In retrospect, it might be a bad decision. But at the time, Entergy’s decision was really logical. The context is totally different. Today, you have a different economic perspective on your plant,” he said. “If you can extend the life of an existing plant, you’re financially better off than building new. If you can just change the oil of your car, you’re better off than spending $30,000 on a new car.”

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TVA Defends Rate Increase for New Gen while Nonprofit Blasts Utility’s ‘Broken Oversight’

The Tennessee Valley Authority insists its second rate increase in two years is necessary to build new generation despite the Southern Alliance for Clean Energy condemning the latest hike as clandestine and used to support fossil fuel investments. 

TVA’s Board of Directors on Aug. 22 approved a 5.25% base rate increase that will take effect Oct. 1. Last year, the board greenlit a 4.5% rise in rates. TVA said the latest increase will amount to an additional $4.35 each month for the average residential bill. 

“We don’t take this lightly; we know that customers pay bills, not rates. … We recognize that nobody likes increases,” TVA spokesperson Scott Fiedler said in an interview with RTO Insider. “But this is needed to address the tremendous growth that is happening across our region. We need to build capacity now to keep up with demand in the future.”  

Fiedler said TVA plans to spend $16 billion through 2027 to add new generation and build out infrastructure to address growth. He said the rate increase will go toward all forms of generation, including new natural gas, renewable energy and investments in the hydropower fleet. But he didn’t elaborate on how much will be spent on each category.  

Specific investments in TVA’s future fleet haven’t been revealed. TVA has yet to release its draft integrated resource plan, though Fiedler said the public can expect to see it in the fall. The draft plan was originally expected in the spring.  

Fiedler noted TVA went four consecutive years without a rate hike before 2023’s increase. He said TVA is emerging from a decade of virtually zero demand growth. 

“But now the growth we’re seeing isn’t stopping.” Fiedler said. 

Fiedler said the region’s population is growing three times faster than the national average and by 2050, the University of Tennessee’s Baker School of Public Policy and Public Affairs projects the region’s population will have grown by 22%. He said the region will gain in the long run from the economic boom in the form of additional tax revenues.  

“The benefits are there, but we understand it can be a hardship,” he said.  

“We have done everything possible to absorb costs as we invest in the reliability of our existing plants, construct new generation to keep up with growth and maximize solar to produce more carbon-free energy,” TVA CEO Jeff Lyash said in a press release after the board approved the increase. 

Fiedler said TVA is attempting to blunt the load growth by devoting $1.5 billion to its new energy efficiency program, TVA EnergyRight, which offers rebates for things like HVAC checks, new air conditioning units and attic insulation. 

He said TVA’s efficiency goal is to offset about 30% of the new load coming online over the next decade. He also said TVA has pledged to reduce its internal costs by $900 million over the next three years.  

Fiedler also noted that TVA has applied for a grant through the Department of Energy’s Grid Resilience and Innovation Partnerships to support a new transmission project to transport renewable energy from the Midwest into the Valley.  

By all appearances, TVA’s IRP will hinge on new natural gas generation. TVA has announced it will replace two coal units at its 2,470-MW Cumberland Fossil Plant with a 1,450-MW natural gas plant. Early this year, FERC approved a pipeline meant to feed the plant, although TVA has said its decision to build the gas plant isn’t final. (See FERC Approves Pipeline to Supply New TVA Cumberland Gas Plant and TVA’s Cumberland Coal-to-gas Plans Press on over Resistance.)  

Several clean energy organizations and two Tennessee congressmen have criticized TVA’s IRP process as secretive, with little public analysis and inadequate opportunities for public influence. (See Tenn. Congressmen Introduce Bill to Make TVA IRP Process More Public.) 

The Southern Alliance for Clean Energy (SACE) said TVA’s rate increase was likewise shadowy and emblematic of a “broken oversight process.” It said board members allowed the hike “without any public documentation showing why the increase is needed or how those additional revenues will be spent.”  

“Only in the Tennessee Valley could a major utility raise rates without public scrutiny of financial documents,” SACE said in a press release, speculating that an “expensive gas expansion is a likely culprit” behind the increase.  

The nonprofit said TVA’s rate increases this year and last are “strategically set just below a 10% threshold that would trigger renegotiation of hundreds of power supply agreements with local utilities.” It bemoaned the fact that the federal utility’s rate increase was not subject to independent regulatory rate reviews by an agency like a state public service commission.  

“People across the Tennessee Valley will see electric bills increase because their public power utility has spent their hard-earned money on plans that it refuses to release to the public. But what is perhaps most disappointing is the fact that the people of the Tennessee Valley have never known anything different. They do not know that most utilities must present a detailed case for public scrutiny before raising rates. TVA has a visage of public power as a federally owned utility but operates as an unregulated private monopoly,” SACE Research Director Maggie Shober said in a statement last week. 

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New IIJA Funding Seeks to Close Gaps in EV Charging Networks

Los Angeles County will use its $15 million Charging and Fueling Infrastructure (CFI) grant to install 1,263 Level 2 electric vehicle chargers at 15 community facilities, four park-and-ride transportation hubs, and 1,000 curbside light poles, according to the Federal Highway Administration’s Aug. 27 announcement of CFI grants totaling $521 million. 

The Los Angeles chargers are one of the 51 projects receiving federal funds from the Infrastructure Investment and Jobs Act (IIJA), with the goal of installing chargers and alternative fueling stations “in the places people live and work ― urban and rural areas alike,” the FHWA said.   

The projects are spread across 29 states, the District of Columbia and eight tribal communities and split between 41 community-focused projects, receiving $321 million, and 10 “corridor” projects, receiving $200 million to install DC fast chargers along major highways and other roads designated as “alternative fuel corridors.”  

California received the largest award, $102 million, to install DC fast chargers and hydrogen fueling stations for medium- and heavy-duty trucks along 2,500 miles of key freight corridors running through California, Oregon and Washington state. (See West Coast Truck Charging Corridor Wins $102M in Federal Funds.) 

The FHWA description notes that “the project will enable the emissions-free movement of goods connecting major ports, freight centers and agricultural regions between the U.S. borders with Mexico and Canada.”  

University City, Mo., a St. Louis suburb, got one of the smallest awards ― $500,000 ― to install its first EV chargers along the main street in a historically disadvantaged neighborhood.  

“As we build out the EV charging network on our highways, we are also investing in local communities, rural, urban and tribal alike,” Polly Trottenberg, deputy secretary of transportation, said in an FHWA announcement. “Today’s grants are a critical part of ensuring every American can find a charger as easily as a gas station, which will decrease pollution from our roadways, lower costs for families and help people get to where they need to go efficiently.”  

Borrowing a favorite line from President Joe Biden, Energy Secretary Jennifer Granholm said the CFI grants are “building infrastructure from the bottom up and the middle out. This investment puts public dollars in the hands of states, tribes and communities to build a more accessible national charging network.” 

The IIJA provided $2.5 billion for the competitive CFI program and an additional $5 billion for the National Electric Vehicle Infrastructure (NEVI) program, which allocates funds to each state based on a formula that accounts for factors like population, vehicle miles traveled and the number of registered EVs in the state. 

NEVI funds are aimed primarily at building out a network of DC fast chargers along U.S. highways, with the FHWA setting standards that require the federally funded charging stations to be located about every 50 miles along major routes and provide at least four 150-kW fast charging ports with 97% reliability. 

The competitive CFI grants are supposed to fill in gaps at the community level, where low-income and disadvantaged areas, and neighborhoods with multi-unit housing, may have few if any publicly available chargers.  

Other CFI grants include: 

    • $11.8 million to Atlanta, Ga., to build a hub of 50 DC fast chargers at the city’s Hartsfield-Jackson Atlanta International Airport. The hub will “provide critical charging for rental car companies, ride-share drivers, airport shuttles for hotels, employees … as well as regional and local EV drivers coming to the airport.”  
    • $2.8 million to Ann Arbor, Mich., to install 48 publicly available EV chargers to “close gaps” in the city’s charging networks. Key locations for the new chargers will include park-and-ride lots, multi-unit housing and large retail areas. 
    • $15 million to the Fort Independence Indian Community, also in California, to build a charging hub along U.S. Route 395, the only north-south corridor along the Eastern Sierra Nevada range. The hub will be powered by a solar microgrid with combined heat and power generation and battery backup.   

The first round of CFI funding, for $1.14 billion, was announced in March 2023; it drew 277 applications, seeking $2.1 billion in grants. A first round of awards, for $623 million, was announced in January. The current announcement covers grants for some of the applications that previously did not receive awards. 

A notice of funding opportunity for the second round of CFI grants totaling $1.3 billion was announced in May; the deadline for applications is Sept. 11.  

NEVI Rollout Blues

With the passage of the IIJA, and its NEVI and CFI programs, Biden set an ambitious goal to have 500,000 convenient, reliable and user-friendly chargers installed and online by 2030. 

According to the FHWA, the number of publicly available chargers has doubled since Biden took office. The national total now stands at 192,000, with an estimated 1,000 new chargers coming online each week. The newly announced CFI projects could add an additional 9,200 chargers to the total.  

But public perceptions of the U.S. charging network continue to be a significant roadblock to EV adoption. A January 2024 survey by McKinsey & Co. found that 80% of survey participants considering an EV purchase thought the existing charging system is inadequate. A majority said they would not buy an EV until public charging is as available as gas stations are at present.  

McKinsey estimated that as EV demand grows, the U.S. could need 9.5 million charging ports by 2025 and 28 million by 2030. 

In the face of such numbers, the NEVI program appears to have had little impact thus far. The Joint Office of Energy and Transportation, which has been tracking the NEVI rollout, reported that as of the end of May, eight NEVI-funded charging stations, with a total of 33 ports, had opened in six states: Hawaii, Maine, New York, Ohio, Pennsylvania and Vermont.  

Since that time, Rhode Island and Utah have also opened their first NEVI stations, and a growing number of states ― including Georgia, New Hampshire, Virginia, Indiana, Arkansas, Kansas and Wisconsin ― have awarded contracts for their first NEVI stations. 

Charger reliability also remains a major concern among prospective EV buyers. According to figures from the Joint Office, in July, about 7.4% of all publicly available Level 2 chargers were temporarily unavailable, compared with just 2% for DC fast chargers. 

The FWHA is addressing the reliability issue with another IIJA-funded initiative ― the Electric Vehicle Charger Reliability and Accessibility (EVC-RAA) program ― which is providing close to $150 million in grants for the repair, upgrading or replacement of older EV chargers. On Aug. 22, the Joint Office of Energy and Transportation joined with Washington, D.C., officials for a “ground re-breaking” at an inoperable charger in the city. Originally a 50-kW charger, the upgraded station will have four ports, all capable of charging at 150 kW. 

The EVC-RAA program is targeting repair and upgrading of 4,500 charging stations, according to the Joint Office. 

While seeking to respond to consumer concerns, Gabe Klein, executive director of the Joint Office, argued that the EV charging experience is significantly different from fueling up at a gas station, with consumers benefiting from the reduced costs of operation, reduced carbon emissions and improved public health.  

“Most EV charging will happen at homes, workplaces or other destinations while vehicles are already parked, providing a safe, reliable and vastly more convenient way for anyone to fuel,” Klein said. “[The CFI] investments in public community charging fill crucial gaps and provide the foundation for a zero-emission future where everyone can choose to ride or drive electric for greater individual convenience and reduced fueling costs, as well as cleaner air and lower healthcare costs for all Americans.” 

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Parties Argue for More Changes to Interconnection Rules from FERC

Even as it works to implement Order 2023, FERC is considering additional changes to its rules on generator interconnections, with a technical conference set for Sept. 10-11 that saw pre-conference comments filed this week (AD24-9).

Commenters argued for a more proactive transmission planning process that takes into account the future generation mix. Others argued for greater automation and certainty around planning.

Some pushed for a special “fast track” for shovel-ready generation that is needed as the grid continually sees generators retire that need to be replaced. The bulk of the new generation in queues is made up of renewable energy; National Grid said that has helped to overwhelm processes originally designed for a more limited volume of fossil fuel-fired plants.

“Unfortunately, the measures that have been relied on historically — e.g., increased deposits and fees, penalties, and prioritizing first-ready projects — have proven insufficient to address the challenges of a rapidly changing grid driven by unprecedented levels of investment in the energy transition,” National Grid said.

Fixing the situation will require new methods, such as a competitive, priority queue for projects that can readily address reliability needs and better coordination between long-term transmission planning and the generator interconnection process, the company said.

“While a capped queue provides an effective means of getting the GI queues under control and more aligned with realistic and effective grid administration, we cannot lose the value that competition in the generation sector has provided for system reliability and consumer costs,” National Grid said. “Accordingly, to populate the capped priority queue, our proposal would establish a competitive process based on identified needs to select the projects that would form the relevant queue.”

Constellation Energy also supported an expedited queue, noting that ISO and RTOs have increasingly warned that the trends of accelerating retirements and clogged queues could lead to reliability issues if not addressed in the coming years. Its comments argued for an “Expedited Reliability Process” for reliable, deployment-ready projects, such as uprates to its nuclear plants.

“Constellation has announced approximately 135 MW of planned uprates at our Braidwood and Byron generating stations in Illinois, the equivalent of adding 216 variable-output wind turbines to the grid,” the company said. “In total, nuclear operators across the nation are considering or preparing uprates with a cumulative capacity increase of approximately 2 GW.”

Such uprates and other shovel-ready projects can plug the reliability gap, but they have to sit in queues that have been gummed up with projects that often contribute far less to resource adequacy, Constellation said. Under its proposal, RTOs would be able to set up an expedited queue when they determine some projects would more effectively and quickly address identified reliability needs.

“RTOs concerned that reliability and/or resource adequacy is becoming an issue could, in these narrow circumstances, seek commission approval of an expedited interconnection study process that would prioritize the processing of interconnection requests likely to be responsive to the RTO’s reliability and/or resource adequacy need, and that can demonstrate a high degree of readiness,” Constellation said. “This subset of interconnection requests would be moved through the interconnection study process on an expedited basis so they can be put in place quickly in response to the RTO’s demonstrated reliability and/or resource adequacy need.”

Storage developer Gridstor cautioned FERC against doing damage to the concept of open access in attempting to speed up queues.

“The commission should look to solutions that least compromise open access and make prioritization criteria based as much as possible on the actions and decisions under the control of interconnection customers,” Gridstor said.

Rationing interconnection quests to determine advancement introduces a zero-sum process because only some projects would get into the priority queues. It could even lead to discrimination among similar projects, the company said.

In the past, FERC has limited exceptions to open access to new generators using retired units’ interconnection facilities and to surplus capacity available to existing generators that want to expand. Gridstor argued the main issue leading to the long queues is a lack of adequate transmission, so any expedited, special processing should be time limited.

“It is imperative that the commission should seek a limiting principle — that is, the smallest compromise to open-access principles needed to achieve the goal of rationing interconnection requests,” Gridstor said. “Reforms that go beyond what is strictly necessary to address the current supply-demand imbalance should be rejected, given the more fundamental responsibility of the commission to uphold open access principles.”

Marrying Interconnection and Transmission Planning

The technical conference will also consider arguments around proactively expanding the grid, which would spread the costs of connecting new resources more broadly than they are now.

“Closer integration of generator interconnection and transmission planning processes will result in a more efficient buildout of the electricity grid,” Brattle Group Principal John Michael Hagerty said. “The vast majority of transmission upgrades today are identified through siloed processes, based on grid reliability studies (with limited consideration of future resource needs) and generation interconnection studies. Proactive transmission planning processes that holistically account for both future projected demand and changes in the future generation resource mix and consider a comprehensive set of transmission benefits will identify the upgrades that reduce total customer costs and allow new resources to efficiently enter the system through the generator interconnection process.”

Hagerty’s comments drew from a report he co-authored with Grid Strategies for Advanced Energy United and the Solar and Storage Industries Institute on potential changes. It argued that proactive planning will avoid unneeded upgrades identified through siloed reliability studies and result in more cost-effective upgrades that provide access to more new resources.

Such plans need to be based on multiple scenarios to deal with the uncertainty around the future. Hagerty said a reasonable cost-allocation method would also help.

“Proactive planning does not require a specific approach to cost allocation for the new transmission upgrades,” Hagerty said. “Identifying a reasonable cost allocation approach that aligns costs with beneficiaries will be an important step in implementing an integrated planning and interconnection process.”

Regions could continue to assign upgrade costs to generators, but they would fund a smaller percentage of a larger suite of transmission upgrades developed for their use, he added.

The R Street Institute also argued for proactive planning and broader cost allocation, as it had earlier in FERC’s transmission planning rulemaking. Those would lead to lower costs overall, meaning lower bills for consumers.

“This improved efficiency translates into major cost reductions for network upgrades, which consumers ultimately pay for, either directly or indirectly,” R Street said. “Because transmission costs are so heavily incurred by consumers, large savings from more efficient network upgrades reduces costs to consumers irrespective of cost allocation method.”

R Street cited ERCOT’s “connect and manage” system, in which transmission network upgrades are entirely determined in planning, and generator interconnection does not include deliverability requirements, leading to much lower barriers to entry than the “invest and connect” approach used in other markets.

“Transmission costs are borne by consumers, either directly or indirectly,” R Street said. “Therefore, it is in consumers’ best interests that transmission expansion efforts be most efficient. Separating network upgrades from the generation interconnection process is one way to improve efficiency.”