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November 17, 2024

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Truckers Group Opposes Wash. Clean Trucks Timeline

Washington has adopted California’s Advanced Clean Trucks (ACT) program to govern the Evergreen State’s long-term transition to zero-emissions trucks, but a group representing truckers argues the timeline for doing so is faster than is practical for the industry.

Under ACT guidelines, 7% of medium- and heavy-duty trucks sold in Washington in 2025 must be zero-emission vehicles, increasing to 20% by 2028, 30% by 2030, 40% by 2032 and 55% by 2035. 

That schedule is too aggressive, according to the Washington Trucking Associations (WTA). 

“While ACT is meant to move industry toward zero emissions for medium and heavy-duty (M/HD) trucks, WTA members have concerns about vehicle costs, operational challenges and low to non-existent vehicle adoption,” wrote WTA President Sheri Call in an Aug. 15 letter to Gov. Jay Inslee (D).  

Washington does not have the regulatory infrastructure in place to discourage companies from using out-of-state outside trucks that do not comply with emissions-reduction standards, she wrote. 

“Artificially manipulating the market to mandate ZEV truck sales will have a profound impact on the industry and lead to unintended consequences,” Call wrote. “California officials wrote, adopted and implemented the ACT program for the state of California. But Washington is not California.”

California has been building support for decarbonization for decades, including funding incentive programs for clean commercial trucks. And its ramp-up of zero-emission sales is more gradual than the Washington schedule, she added. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.) 

“A zero- emission truck costs about two and half times more and sacrifices about two and half tons of payload compared to a clean diesel truck today. Electric M/HD trucks also compromise range, while only providing about 150-200 miles per charge,” Call said in the letter. “Fueling infrastructure is also expensive and can take up to two years for permitting and installation. There is also the ongoing uncertainty of electric grid capacity as examples of officials asking vehicle owners to avoid charging cars during hot summer days continue to become more commonplace.” 

Call also pointed to the 12% federal excise tax on new trucks and trailers — “a policy the industry has long thought to inhibit adoption of newer, cleaner diesel trucks.” 

The ACT’s timeline is too aggressive and does not accommodate innovation or current technological limits, she wrote.

“WTA respectfully asks you and the Legislature to reconsider the link to California’s emission standards and adopt the federal standards that are more suitable to Washington’s unique needs. Washington employers should not have to face policies created by another state, with no input from stakeholders or analysis for its impact here,” Call wrote. 

In an email to NetZero Insider, Mike Faulk, spokesperson for the governor’s office, said the state is studying the issue.  

“These regulations were thoughtfully crafted to make compliance feasible. There are a variety of compliance options, including giving credit from previous years sales to meet the first target in 2025 and credit-sharing across weight classes allowing for manufacturers to ramp up availability,” Faulk wrote.

“The state is committed to supporting the trucking industry in this transition,” Faulk continued, noting it has provided more than $130 million in funding from the Climate Commitment Act — the state’s cap-and-invest program — to help truck owners cover the costs of electric trucks and charging infrastructure. 

“We continue to work with California and Oregon to pursue federal funding to build an electric truck charging corridor along I-5. And we’ve secured over $60 million in state and federal funding to electrify drayage trucks operating in and around ports,” he wrote. 

California, Oregon and Washington recently secured $102 million in federal funding for the West Coast Truck Charging and Fueling Corridor project, a joint effort to install a network of chargers between the borders with Canada and Mexico. (See West Coast Truck Charging Corridor Wins $102M in Federal Funds.) 

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BLM Issues Solar Roadmap for 11 Western States

The U.S. Bureau of Land Management on Aug. 29 released proposed guidelines for solar energy development on more than 31 million acres of public land in 11 Western states.

BLM’s original Western Solar Plan covers six Southwest states and dates to 2012. The proposed update reflects increased interest in solar development in five Northwest states and changes in photovoltaic technology during the intervening decade.

It steers solar development closer to transmission lines rated at 69 kV or larger; off slopes greater than 10%; onto previously disturbed lands; and away from protected lands, cultural resources and important wildlife habitats.

Project-specific analysis still would be required on every solar facility proposed.

The plan would not apply to projects that are smaller than 5 MW or not connected to the grid.

The proposal is scheduled to be published in the Federal Register on Aug. 30. Sixty days is allotted for protest and consistency review; any issues identified in that time will be resolved, then BLM will publish the record of decision.

BLM and the National Renewable Energy Laboratory calculated that 700,000 acres would be sufficient to meet the nation’s clean-energy goals.

The total planning area covers 162 million acres of public land in the 11 westernmost states. That was narrowed to about 22 million acres in the draft Western Solar Plan released in January 2024 but expanded to more than 31 million acres in the final proposal.

As of July 2024, BLM had permitted approximately 29 GW of clean-energy projects — 69 geothermal, 52 solar and 41 wind, plus 42 transmission connection lines on federal land.

At that time, it also was processing 62 applications for clean-energy projects in the Western states with a combined potential of 31 GW. It said hundreds more project applications were in preliminary review.

The proposal has drawn considerable attention and feedback — BLM said that after it published the draft in January it received more than 50,000 comments.

Some industry groups said Aug. 29 that BLM had drawn the maps too narrowly in the final proposal.

In a prepared statement, the Solar Energy Industries Association said it has long sought to level the playing field for energy development on public lands, and the solar plan does not do that:

“While we’re still reviewing the details, we’re pleased to see that BLM listened to much of the solar industry’s feedback and added 11 million acres to its original proposal. While this is a step in the right direction, fossil fuels have access to over 80 million acres of public land, 2.5 times the amount of public land available for solar.”

American Clean Power made a similar point and said it looks forward to working with BLM and stakeholders to reduce unnecessary regulatory hurdles:

“ACP appreciates the time BLM has dedicated to reviewing the permitting process for solar development and recognizes the flexibility added into the project design features and additional acres made available in the final plan. However, we remain concerned by the exclusion of some areas which could otherwise allow for development in ways compatible with resource protection.”

The Wilderness Society, however, praised the protective stance BLM took. It said:

“The BLM’s final Western Solar Plan harnesses this clean and abundant resource responsibly, focuses projects away from ecologically and culturally sensitive places, honors community input and realizes the imperative that our public lands must be part of the climate solution. We look forward to working with the administration, the solar industry, communities, Tribes, and other stakeholders to ensure individual projects live up to the strong standard that was set today.”

BLM Director Tracy Stone-Manning said the final plan is a good one:

“It will drive responsible solar development to locations with fewer potential conflicts while helping the nation transition to a clean energy economy, furthering the BLM’s mission to sustain the health, diversity and productivity of public lands for the use and enjoyment of present and future generations.”

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Late August Heat Wave Delivers 122-GW MISO Summer Peak

CARMEL, Ind. — MISO set its 122-GW summertime peak on the unofficial last week of summer, with widespread heat necessitating back-to-back maximum generation warnings.

MISO instituted two separate maximum generation warnings Aug. 26-27 for the Midwest region after issuing conservative operations and a capacity advisory beginning Aug. 25. Much of the footprint registered over 90 degrees on Aug. 26, with a blistering heatwave parked over the Midwest.

“MISO and our members reliably served the highest demand of the summer season due to the extreme heat across our North and Central Regions,” spokesperson Brandon Morris said in a statement to RTO Insider. “The declarations we issued allowed us to access the necessary resources to maintain reliability.”

MISO said the emergency warnings were due to culmination of the higher-than-normal temperatures, forced generation outages and limited transfer capabilities. As it dealt with the heat wave on Aug. 26, MISO sent reminders to market participants with external resources that their interchange schedules must match their capacity obligations to MISO.

The RTO realized a summertime peak of 122 GW on Aug. 26. At an Aug. 29 Reliability Subcommittee, MISO’s John Harmon noted that the peak bested July’s high of 118 GW. MISO originally forecasted a summer peak of 123 GW to occur in July. (See “July Peak Prediction Unfulfilled,” MISO Predicts Painless Fall Despite Missouri Capacity Shortfall.)

“We did have a couple of maximum generation warnings due to the hot weather and lower than normal wind. We managed through that well,” Harmon said. He promised MISO would deliver a more thorough review of the event once it gathers the data for a stakeholder presentation.

Coal and natural gas supplied roughly 70% of demand over the heat wave’s most intense daytime hours. While the warnings were in place, MISO also relied on a few gigawatts of imports from PJM, although it, too, was contending with high temperatures.

The situation was helped Aug. 26 by thunderstorms that developed across western Minnesota and moved across central and eastern Minnesota into western Wisconsin.

MISO’s growing solar fleet also may have helped the footprint meet demand. The RTO is nearing 7-GW monthly solar peaks.

After Aug. 27, the system returned to normal operating conditions.

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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 12th 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 eventually would 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 filed jointly 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 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 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, although 40% of non-union firms still reported it “very difficult,” compared with only 24% of unionized firms. 
    • Some demographics are under-represented 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, Mich., 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.”