The California Energy Commission and Department of Transportation (Caltrans) are seeking feedback on the structure of the state’s Electric Vehicle Charger Reliability and Accessibility Accelerator (EVC RAA) grant program, designed to replace and repair more than 1,300 chargers at 300 sites statewide.
In January, the U.S. Department of Transportation awarded Caltrans $63.7 million of Infrastructure Investment and Jobs Act funds to develop the program, which sets aside 10% of funds from the National Electric Vehicle Infrastructure (NEVI) Formula Program; $58.4 million is available for solicitation, with the remainder being used for CEC and Caltrans administrative costs.
“The purpose of the EVC RAA program is to repair or replace broken — or not operational — publicly accessible electric vehicle chargers to improve the reliability and accessibility of the existing network,” Emily Belding, zero-emission vehicle infrastructure coordinator at Caltrans, said at a joint CEC and Caltrans presolicitation workshop March 27.
Stations eligible for funding are those listed as “temporarily unavailable” as of Oct. 11, 2023, by the Federal Highway Administration, Belding said. There are more than 3,500 eligible ports in California, and EVC RAA funding will support the repair or replacement of more than 1,300.
Each site must be NEVI-compliant, meaning it should contain a minimum of four Level 2 or DC fast-charging ports. At sites located within 1 mile of a designated alternative fuel corridor, chargers must deliver at least 150 kWh of power. (See Calif. Looks to Streamline Process for Issuing NEVI Funds.)
Additionally, EVC RAA is part of the federal Justice40 Initiative, meaning at least 40% of eligible ports must be in communities marginalized by underinvestment or overburdened by pollution, and a minimum of 50% of deployed chargers must be in disadvantaged or low-income communities in general.
For replacement projects, CEC is estimating it will cost $12,500 for Level 2 ports — those able to offer at least 6 kW of continuous power delivery — and $300,000 for DCFCs, said Ben De Alba, zero-emission vehicle infrastructure specialist at CEC. The agency will not award more than the cost per port for replacement projects.
Eligible applicants must be private entities, including EV charging and service providers, third-party installers, and charging station operators. Ineligible projects include those for which costs would exceed the cost to replace the broken or nonoperational equipment, EV chargers currently under warranty or an existing service-level agreement, and those that don’t meet the definition of “publicly available.”
Projects must be completed in 12 months, and because of the limited time frame, funds cannot be used for operations and maintenance. Chargers must maintain an average uptime of 97% over five years, and applicants are required to submit a five-year operations and maintenance plan.
CEC and Caltrans will score each application on factors including project readiness, the benefit to Justice40 communities and cost effectiveness.
John Schott, director of public-private partnerships with ChargePoint, questioned the decision to limit eligibility for funds to private entities.
“If you look at the list of eligible charging stations, there definitely are some public entities and some cities and towns who have quite a number of broken chargers that I know they’re interested in fixing. So, if they weren’t able to find either an installer, network provider or one of the identified eligible applicants, that certainly might hinder their ability to take advantage of this funding,” Schott said. “I understand your interest in trying to minimize the scope and not have tons of individual grant awards to manage. But I think in the spirit of this federal solicitation and really trying to fix those broken chargers out there, I would respectfully request that you would reconsider that.”
Comments on the EVC RAA program structure are due April 15. The solicitation is expected to be released in August, and applications are due in September.
“This has been a very complex program from the start,” De Alba said. “We’re moving as quickly as we can to award the funds and get these stations repaired or replaced.”
Despite record winter precipitation in California, hydroelectric generation in the Western U.S. fell to a 22-year low in the 2022/23 water year, largely due to droughts in Washington and Oregon, a new analysis found.
Since the 2016/17 water year, Western hydropower generation has been diminishing except for a 13% uptick in 2021/22, according to a March 26 report from the U.S. Energy Information Administration (EIA). A water year runs from Oct. 1 to Sept. 30.
The 2022/23 water year resumed the downward trend, with an 11% drop compared to the previous year. The 141.6 million MWh of Western hydropower generation in 2022/23 was the lowest since 2001.
Previously, the record low was in the 2020/21 water year.
The EIA attributed last year’s drop to drought conditions leading to “historically low” hydropower generation in the Pacific Northwest. Annual hydropower fell by 23% and 20% in Washington and Oregon, respectively.
Western U.S. hydropower output for water years from 2001 until 2023. | EIA
The 2022/23 water year for the region started with near-normal to below-normal precipitation, EIA noted. But in May 2023, a heat wave in the Pacific Northwest caused temperatures to spike as much as 30 degrees above normal, rapidly melting the snowpack.
“Water flows in May were high, but much of the water supply needed for generation during the summer months melted during the May heat wave,” EIA said. Water supply in the PNW then stayed below average for the rest of the water year, reducing hydropower generation. Tight supply conditions became evident during a five-day cold snap in January when the region was forced to import large volumes of power to meet near-record demand and avert rolling blackouts. (See NW Freeze Response Shows WEIM Value, CAISO Report Says and Powerex Report Expands NW Cold Snap Debate.)
California weather in 2022/23 was dramatically different than in the Northwest. A series of atmospheric river storms dropped record rain and snow on the state from December 2022 to March 2023.
The wild winter left California with its largest snowpack since records began in the mid-1980s. Drought-depleted reservoirs were replenished, and hydropower generation for 2022/23 reached 30.0 million MWh, nearly twice that of the previous year.
The 11 states in the Western region produced about 60% of the nation’s hydropower last year, roughly the same as in the 2021/22 water year.
Washington, Oregon and California produced the most hydropower in the region; Washington and Oregon combined contributed 37% of the U.S. total. The other Western states are Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah and Wyoming.
Elsewhere in the region, Southwestern states had above-normal precipitation in 2022/23. Hydropower generation at Glen Canyon Dam was up 27%. But output was down 11% at Hoover Dam due to water conservation, EIA said.
California’s snowpack appeared to be in good shape March 26, at 102% of the state’s April 1 average, according to the California Department of Water Resources.
Still, EIA is forecasting a 12% drop in hydropower production this water year in the Western market region of California. Similar decreases are expected in the Northwest and Southwest, according to EIA’s short-term energy outlook.
As the Massachusetts legislature gears up to address permitting and siting challenges for clean energy infrastructure, a new report shows how the state has disproportionately sited electricity infrastructure in environmental justice communities.
Authored by a coalition of climate and EJ organizations, the analysis found that more than 80% of polluting generation facilities and nearly 70% of substations are located within 1 mile of a state-designated EJ community.
Massachusetts defines EJ populations based on income, race and language barriers. The state has classified about 50% of its neighborhoods as EJ communities.
“This analysis shows yet again that environmental justice communities in Massachusetts have suffered for decades from inequitably sited energy infrastructure, bringing unhealthy and unsafe conditions like air pollution to their neighborhoods,” said lead author Paula García, senior energy analyst at the Union of Concerned Scientists.
As the state prepares for significant electricity demand growth, Massachusetts’ electric distribution companies have proposed major investments in new substations, while the state is also planning for a massive increase in solar, wind and utility-scale battery resources. (See Mass. Utilities Submit Grid Modernization Drafts.)
The state’s investor-owned utilities have proposed installing 50 new substations by 2034. Based on the available data about the location of the utilities’ new substation investments, the analysis indicated that “new substations will likely aggravate this historic trend, with seven of the 11 mapped projects proposed for siting within EJ neighborhoods.”
“The little information that is available suggests that proposed electric infrastructure will yet again disproportionately burden environmental justice communities,” said co-author John Walkey, director of climate justice and waterfront initiatives at GreenRoots. “Decision-makers must recognize this harmful pattern and establish a formal avenue for community needs to be centered in decisions happening in their own backyard.”
The authors wrote that the clean energy transition will bring climate and public health benefits to the region but stressed that clean energy projects can still have detrimental local effects. They noted that substations can impact local communities through noise pollution and risks of fires and explosions, while poorly sited renewables can impact public spaces and wildlands.
Future siting processes must do a better job incorporating the perspectives and concerns of host communities into project planning and consider the cumulative impacts of existing energy infrastructure, the authors wrote.
The analysis also called on the state to add two public members to its Energy Facilities Siting Board to represent EJ and Indigenous communities and to add climate, EJ and public health to the board’s statutory priorities.
Co-author Sofia Owen, senior attorney at Alternatives for Community and Environment, said some lawmakers have expressed concern that adding these EJ protections to the state’s siting processes could slow the deployment of infrastructure necessary for decarbonization.
“It actually will speed things up if you have buy-in from the community,” Owen said. “I am hopeful that the administration will take to heart the things that EJ and climate justice advocates have been saying for a long time.”
Aspects of the bill supported by the organizations, H.3187, were included in a combined bill passed out of the House side of the legislature’s Joint Telecommunications, Utilities and Energy Committee.
Rep. Jeff Roy (D), co-chair of the committee, has highlighted permitting and siting reform as one of his top priorities for this legislative session. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.) Roy has introduced his own bill, which was also included in the package that was reported out of the committee.
Along with bills from the House, the state’s Commission on Energy Infrastructure Siting and Permitting is due to make recommendations to Gov. Maura Healey by the end of March, which could lead to an additional permitting and siting proposal from the administration, while the Senate could also produce its own bill.
Amid all the moving parts, top legislators are targeting the passage of an omnibus climate bill by the end of the session in July. If previous climate bills passed in the state are any indication, the negotiations could come down to the wire.
MISO and PJM are deliberating whether to embark on an interregional transmission study this year as they field more calls from stakeholders to revamp their joint planning framework.
“Certainly, all the feedback we get is considered,” Jarred Miland, MISO senior manager of system planning coordination, said during a meeting of the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC) on March 25. “Interregional planning is important to MISO and PJM. … MISO and PJM have been in joint, active discussions regarding the feedback.”
Miland promised “more to come” on the interregional planning front.
The RTOs have 45 days following the IPSAC meeting to determine the need for a Coordinated System Plan study, which may produce interregional projects. The Joint Planning Committee, composed of MISO and PJM staff, makes the final call on whether an interregional study is warranted.
MISO and PJM delayed their March IPSAC teleconference by about a month after the calls for more thorough and proactive interregional planning.
Iowa Utilities Board Member and newly minted Organization of MISO States (OMS) President Josh Byrnes has characterized the joint letter from OMS and the Organization of PJM States Inc. (OPSI) as a “polite nudge” to get the ball rolling on substantial interregional planning.
PJM’s Jeff Goldberg said the RTOs are currently reviewing interregional congestion issues that could be the focus of either a targeted market efficiency project study or a more intensive interregional market efficiency project study.
Planners opened the IPSAC meeting by emphasizing their separate, ongoing regional planning efforts. Representatives of both RTOs spoke about their respective plan for long-range regional planning.
Miland said MISO is coordinating with PJM on some of its recently unveiled second portfolio of long-range transmission plan (LRTP) projects, some of which cut across PJM’s ComEd territory. Miland said that although some lines will cross into the PJM system, the LRTP lines will be considered regional.
However, multiple stakeholders continued to press for better interregional solutions at the seams.
Michigan Public Service Commission Chair Dan Scripps reminded the RTOs that regulators, who review projects for affordability on cost containment on behalf of customers, are asking for new infrastructure.
“‘Our regional grids are undergoing significant changes that merit consideration of joint planning activities,” Scripps said, quoting a letter from OMS and OPSI sent in February.
Scripps said national studies and increasingly severe weather show “major opportunities for interregional progress.” He said MISO and PJM can use their existing long-term transmission planning processes to holistically plan interregional facilities.
WEC Energy Group’s Chris Plante said he worried that MISO and PJM may miss an opportunity to show they are taking FERC’s potential rule on minimum interregional transfer capability seriously.
MISO Director of Economic and Policy Planning Christina Drake assured stakeholders that the RTOs “are taking this very seriously.” However, she said the two “don’t have anything concrete to release” in terms of a timeline for responding to calls for a reworked interregional process.
RMI’s Claire Wayner said MISO and PJM could have a more comprehensive planning process that considers reliability, public policy and congestion-relieving benefits. She said it is unsurprising that the RTOs’ process, with its limitations on who can propose a project when and for what purpose, hasn’t produced needed transmission projects.
“As a former state regulator, I feel like we are witnessing a remarkable moment, where you’re seeing a confluence of forces who want … MISO-PJM interregional lines,” the Sustainable FERC Project’s Lauren Azar said. She advised MISO and PJM to get a jump on interregional planning so that by the time more severe weather strikes the regions, they are not perceived as inattentive.
Grid Strategies Vice President Michael Goggin appeared before the IPSAC to reiterate the value of more interregional capacity. He used his 2023 report showing that expanded interregional transmission between the RTOs could offer more than $1 billion in annual energy market savings, as they often experience peak demand at different times. MISO and PJM experienced $1.7 billion in congestion in 2021-2022, he said. (See New Report Finds MISO, PJM Could Save Billions Through Interregional Tx Expansion.)
“These are sizable quantities of market congestions that are causing real costs to customers,” he said. “As a nation, we are failing at building interregional transmission.”
Goggin called for “proactive, multivalue” interregional transmission planning. For that to happen, PJM must move on from its siloed transmission planning that considers benefits individually, he said.
The developer of New Jersey’s most advanced offshore wind project, Atlantic Shores, is pushing ahead with a second project as the state prepares to launch a new solicitation — its fourth — that could add as much as 4 GW in wind-generating capacity to help meet the state’s goal of 11 GW.
The Bureau of Ocean Energy Management (BOEM) on March 18 posted a Notice of Intent (NOI) to prepare an Environmental Impact Statement (EIS) on the Atlantic Shores North Project proposed by the developer, Atlantic Shores Offshore Wind. The plan would create an 82-acre sea tract eight miles off the New Jersey coast and 60 miles from New York.
The project would occupy the second half of the tract leased by the developer. The first half is the planned location of the 1,510-MW Atlantic Shores project — also known as Atlantic Shores South — that the New Jersey Board of Public Utilities (BPU) approved in its second solicitation, in 2021.
The Atlantic Shores North Project, with 157 wind turbine generators, would send electricity through cables that would make landfall in Sea Girt, N.J., and either Asbury Park, N.J., or New York City. The developer says it will consider submitting applications to future solicitations launched by either New York or New Jersey.
Terence Kelly, head of external affairs for Atlantic Shores, said the company is forging ahead despite the problems that in November prompted Danish developer Ørsted to withdraw its two New Jersey projects — the 1,100 MW Ocean Wind 1, the state’s first project, and the 1,148-MW Ocean Wind 2.
Atlantic Shores is “bullish” on producing power off the New Jersey coast, in part due to the commitment from New Jersey Gov. Phil Murphy (D) and New York Gov. Kathy Hochul (D), Kelly said in an interview with NetZero Insider.
“You see all the progress made. You can’t, can’t help but be a little bit bullish,” he said. “It’s a nascent industry that — getting through some challenging moments in the last year or two — sets us up to have a breakthrough moment where we can overcome the obstacles of the past.”
Accelerated Solicitation Schedule
BOEM posted the NOI on the Federal Register two days before the BPU on March 20 held a hearing to gather public input on the guidance document for the state’s fourth offshore wind solicitation, which seeks to secure new wind capacity of between 1,200 MW and 4,000 MW. The approved capacity could be even larger, “if circumstances warrant,” according to the guidelines.
The BPU expects to launch the solicitation during the second quarter, with applications in the third quarter and a decision on which projects to back by the end of the year.
If that timeline holds, in a sign of the state’s determination to demonstrate its commitment to offshore wind, the BPU would announce the endorsed fourth solicitation projects less than a year after picking the winners of the third solicitation in January. The agency at that time backed two projects — Leading Light Wind and Attentive Energy Two — totaling 3,742 MW of capacity. (See NJ Awards Contracts for 3.7 GW of OSW Projects.)
The state had planned to solicit new projects every two years, but it accelerated the process after Ørsted’s departure to make up for lost ground. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)
The developer’s withdrawal left Atlantic Shores, a 50/50 joint venture between EDF-RE Offshore Development and Shell New Energies US, at the helm of the state’s leading offshore wind project.
“The compounding challenges of the interest rate environment, of inflation and the supply chain bottlenecks, those are all things that are real, they remain real,” Kelly said. But he added that “we are sizing them up in a way that we say, you know what, cautiously we can proceed, because these are great markets.”
Going through the NOI process is part of the company’s strategy to get as much of the permitting and regulatory issues out of the way early on, he said. That way, when the company submits a solicitation bid it can present a “mature” project with a solid foundation that can persuade state officials selecting projects that Atlantic Shores is ready to bring the project successfully to fruition.
Although the lease area is close to New Jersey, it sits in federal waters, so the power generated by the project would go to the state that strikes a finance and power agreement with the developer, Kelly said.
“We remain committed to New Jersey,” he said, noting that New York also will have a solicitation in the near future. He added that the developer is ready for opposition from New Jersey stakeholders to the Atlantic Shore North Project.
“Stakeholder concerns are valid, and we should take them into consideration,” he said. “And they should be weighed appropriately against the public policy goal to get to 100% clean energy by 2035.”
Project Evaluation Criteria
New Jersey’s wind projects have faced opposition from commercial fishermen, businesses that fear fewer visitors will come to the shore if wind turbines are on the horizon, and residents and property owners who fear the projects will diminish their quality of life.
BOEM’s announcement that it would initiate the environmental review of Atlantic Shore North prompted an opposition group, Save Long Beach Island, to denounce the plan in a fundraising email that day.
As well as its proximity to shore communities, the project would “add insult to injury” by potentially sending power to New York, the message said.
“This is truly inequitable because LBI (Long Beach Island) and New Jersey would bear the adverse property value, rental, tourism and other impacts of the turbine projects, while New York would get the benefit of the power,” said the email, from organization President Bob Stern. It added that the organization would need “new financial support” to oppose the project in the environmental process and to file litigation against the Atlantic Shores North Project.
Opposition surfaced at the hearing for the fourth solicitation guidance proposal, where there was little presence among the 10 speakers of either the OSW industry or the environmental groups that see OSW as essential to cutting carbon emissions and helping mitigate the effects of climate change.
Opposing the projects, Jeff Platenyk, who said he is a longtime resident of New Jersey, expressed concern at the weighting of different factors the BPU uses to decide which projects to approve. The agency said the purchase price of an Offshore Renewable Energy Credit — which represents the environmental attributes of one megawatt-hour of electric generation from an offshore wind project — and other ratepayer impacts will carry 60% of the evaluation factors.
Economic strengths and the proponents’ guarantees to make them happen will account for 20% of the factor weighting, and an additional 10% will rest on the likelihood the project would yield a successful commercial operation.
Platenyk questioned why “environmental and fisheries impacts” carry only a 10% weighting, calling it “quite disturbing” given that the projects could reap “serious destruction” of ocean aquatic life.
Supporting the OSW projects, Monmouth County fishing charter business owner/operator Paul Eidman said he sees “the negative impacts of the climate crisis every day out on the water” and offered a suggestion for improving the guidelines. Eidman suggested the BPU take measures to ensure the turbines are decommissioned after 25 years in such a way as to create an “artificial reef underneath these turbines.”
Erica Bosak, an attorney for Clean Ocean Action, which opposes OSW projects due to their possible damage to whales and other marine life, criticized the “voluntary nature of many of the solicitation guidance documents.”
She said the guidance says developers submitting project proposals “should … avoid impacts to sensitive seafloor habitats, including shellfish habitat, prime fishing areas, submerged aquatic vegetation and wetlands.”
“But it is not mandatory for them to do so,” she said.
Transmission Cost Reductions
The BPU, on the same day as the fourth solicitation, approved changes in the scope and cost of the infrastructure through which the power would be brought to the shore. BPU officials said the changes to the transmission system created under the State Agreement Approach approved by the board Oct. 26, 2022, would save ratepayers about $29 million. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The order said the changes stemmed from regular meetings between BPU staffers and representatives of PJM. The changes included cancellations of a transmission line and circuit breaker that were not needed, revised cost estimates for equipment and conclusions that certain projects no longer were needed, the order said.
In what’s beginning to feel like déjà vu, Cardinal-Hickory Creek’s last unconstructed mile again is subject to a preliminary injunction.
Last week, U.S. District Judge William Conley granted conservation groups’ preliminary injunction request, preventing American Transmission Co., ITC Midwest and Dairyland Power Cooperative from finishing the 102-mile, 345-kV line’s final stretch through a wildlife refuge.
The injunction halts the land exchange of more than 35 acres in Grant County to add to the Upper Mississippi River National Wildlife and Fish Refuge for almost 20 acres of the existing refuge in Clayton County, Iowa, to be cleared for the line.
The Driftless Area Land Conservancy, Wisconsin Wildlife Federation and National Wildlife Refuge Association filed the latest lawsuit on the controversial line earlier this month, charging that the U.S. Fish and Wildlife Service, U.S. Rural Utilities Service and U.S. Army Corps of Engineers violated three federal laws when they approved permits and greenlit the land exchange to assemble the final mile-long stretch of the 102-mile, $650 million transmission line through the Upper Mississippi River National Wildlife and Fish Refuge. (See Conservation Groups File Another Lawsuit to Stop Cardinal-Hickory Creek’s Last Mile.)
The parcel swap was OK’d by the U.S. Fish and Wildlife Service (FWS) and set to occur March 22, with ITC and Dairyland positioning construction equipment near the refuge’s edges.
Conley said he would like to see documents that give more insight into the lead-up to the land deal’s approval. The conservation groups said Conley implemented a “stopgap measure to prevent irreversible destructive activity in the refuge while he awaits an administrative record.” Attorneys for both sides will have 30 days to submit briefs.
In a statement, Driftless Area Land Conservancy (DALC) Executive Director Jennifer Filipiak said her organization is thankful for the judge hitting “the pause button.”
“DALC has consistently maintained that it is inappropriate to cross a National Wildlife and Fish Refuge with this massive transmission line. The transmission companies did not evaluate alternative crossings outside of the refuge in their environmental impact statement, and we should not set a precedent that a simple land swap is all it takes to plow through a national treasure,” Filipiak said.
Environmental Law and Policy Center Executive Director Howard Learner, representing the conservation groups, said he’s confident the groups will prevail. In a statement, Learner said FWS shouldn’t be free to “create statutory loopholes with a land exchange.” He warned of a “dangerous precedent for running more massive high-voltage powerlines through other protected National Wildlife Refuges.”
Learner argued in front of Conley last week that FWS didn’t offer the public the opportunity to comment on its February finding that the land exchange wouldn’t significantly affect the refuge.
However, Reade Wilson, a U.S. Department of Justice attorney representing FWS, responded that the agency wasn’t obligated to solicit public opinion on the no-impact decision.
ITC Midwest and Dairyland Power Cooperative criticized the injunction and said Cardinal-Hickory Creek is “a backbone project for the Midwest’s regional power grid that is necessary to improve grid reliability, lower consumer electricity costs and enable renewable energy to be brought to market, resulting in a significant reduction in carbon emissions.”
American Transmission Co. has built and energized its eastern portion of the line.
The two developers also repeated their assertion the wild refuge will be better off — and larger — because of their land offer of prime habitat.
“This latest lawsuit, which is misguided at best, only serves to delay completion of this important energy infrastructure and further increase costs to customers. The plaintiffs have raised meritless arguments in multiple cases, all of which have been rejected. This is just another attempt by plaintiffs to sideline this critical 345-kV tie between Iowa and Wisconsin,” ITC Midwest President Dusky Terry said in a statement.
ITC and Dairyland pointed out that the Cardinal-Hickory Creek project has survived multiple lawsuits in state and federal court from the same conservation groups seeking to stop construction.
“The co-owner utilities have successfully navigated no less than three separate injunctions, won appeals before the Wisconsin Supreme Court and received three different favorable opinions from the U.S. Court of Appeals for the Seventh Circuit,” ITC and Dairyland wrote in a statement.
The U.S. Department of Energy on March 25 announced $6 billion in funding for 33 projects that are meant to help decarbonize difficult-to-abate, energy-intensive industries.
The money comes from both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act and is meant to accelerate the commercial-scale demonstration of emerging industrial decarbonization technologies that are crucial to meeting the Biden administration’s long-term goals to cut emissions.
“Spurring on the next generation of decarbonization technologies in key industries like steel, paper, concrete and glass will keep America the most competitive nation on Earth,” Energy Secretary Jennifer Granholm said in a statement. “These investments will slash emissions from these difficult-to-decarbonize sectors and ensure American businesses and American workers remain at the forefront of the global economy.”
The projects focus on the highest emitting industries, including aluminum, iron, steel, cement and concrete, chemicals and refining. Altogether, they are expected to avoid about 14 million tons of CO2 each year, which is equivalent to taking 3 million internal combustion cars off the road.
While the electric industry has seen a lot of progress when it comes to getting renewables onto the grid, many of the industries impacted by DOE’s funding announcement need technologies that at least have yet to be proven at scale, Jeffrey Preece, the Electric Power Research Institute’s director of research and development, said in an interview.
“They can’t go and procure alternatives that they have today that meet the low-carbon future while also meeting affordability, reliability and, in these cases, supporting their bottom lines,” Preece said.
Industries like concrete, chemicals and steel making compete globally, and they need economic alternatives available, he added.
Many of the projects will deploy technologies that have never been used domestically and have the potential to be adopted across the entire sector, which multiplies the magnitude of potential emissions cuts, DOE said.
“Some of these technologies are likely to play a role across many different industries,” Preece said. “So, it’s not necessarily creating unique pathways for one industry, but there should be opportunities to share more broadly to help other industries.”
Industry contributes nearly one-third of the country’s emissions, and the federal investment will use more than $20 billion to demonstrate commercial-scale decarbonization needed to move industry toward net-zero emissions, DOE said. The projects will cut emissions at the various sites by an average of 77%.
The sector’s complex decarbonization challenges will require specific and innovative solutions that use multiple pathways, including efficiency, electrification and alternative fuels, and feedstocks, such as clean hydrogen.
EPRI has estimated that about 50% of industrial demand could be met with electricity, which would mean significant new load for the power industry, but Preece said some applications work better with other energy sources, and all of those are running on fossil fuels.
“Heavy industry generally requires firm, baseload electricity supply,” Preece said. “And various industries rely on heat sources … that are best served by a fuel.”
While all the industries can benefit from ramping up their efforts around energy efficiency, a lot of work on deploying new alternatives such as hydrogen, carbon capture and storage, and advanced nuclear needs to be done in the next couple of decades.
“If history is our guide, it can take decades to commercialize technologies,” Preece said. “Looking at today’s power generation assets, to your other energy projects, from concept to pilot testing, to first-phase deployment of large-scale, repeatable, replicable commercial deployment, it can take 20-plus years for technology to go from start to fully commercial.”
Many of EPRI’s efforts are focused on trying to speed up that process because avoiding the worst impacts of climate change means significant cuts in CO2 emissions by midcentury, he added.
“The question becomes: How do we do that in a way that doesn’t move one area too quickly and forces an issue in affordability and reliability?” Preece said. “So, our approach to that is working with industrial clusters, hubs, regional groups of industry and power generation, and communities to help assess what technologies might be most impactful for their decarbonization goals and their regional energy supply and use scenario.”
DOE noted that it still has to go through a negotiations process with the projects, and it “may cancel negotiations and rescind the selection for any reason during that time.” Lead applicants can also change during those negotiations. If awarded funds, the projects will go through a phased approach with a number of “go/no-go” decision points where DOE can evaluate the implementation progress.
“Industrial decarbonization is a pathway to creating new jobs, increasing American manufacturing competitiveness, improving local communities and protecting our climate,” Renewable Thermal Collaborative Executive Director Blaine Collison said in a statement. “The Department of Energy’s awards today are important partnerships that will help deliver all these benefits to our people, our economy and our environment. These DOE-industry collaborations will help drive transformation and scale.”
The funding goes hand in hand with other policy measures such as “buy clean” incentives, CeCe Grant, director of the Sierra Club’s Industrial Transformation Campaign, said in a statement.
“We are excited for private industries to take a leading role in cleaning up our industrial sector and will work to ensure that fenceline communities and workers have a real seat at the table to shape the vision for a just transition,” Grant said.
Citing “glaring exceptions and vague requirements” with the proposed cold weather standards submitted by NERC last month, members of the ISO/RTO Council on March 21 expressed “united opposition” to their approval and urged FERC to direct the ERO to submit a revision addressing RTOs’ and ISOs’ concerns within the next four months (RD24-5).
NERC filed EOP-012-2 (Extreme cold weather preparedness and operations) with the commission Feb. 16, the day after the organization’s Board of Trustees approved the standard at its open meeting in Houston. (See “Cold Weather Standard Accepted,” NERC Board of Trustees/MRC Briefs: Feb. 14-15, 2024.) It serves as successor to EOP-012-1, which FERC approved in February 2023 while ordering NERC to develop a replacement within a year.
In its filing, the IRC emphasized that it supports the commission and the ERO’s efforts to prevent future major outages due to cold weather, such as those during winter storms Elliott and Uri, through the development of reliability standards. The council said it “has actively engaged” during all stages of the standards development process “to advocate for durable requirements that will lead to effective winterization” and “was careful to propose specific language to address the concerns it raised.”
However, although the IRC acknowledged the standards drafting team modified the standard in response to some of its comments, it said the submitted standards leave the “most significant concerns … unaddressed.” It warned that approving the standard will lead to more reliability issues, causing additional work for FERC and greater cost for generator owners and the public.
“It is admittedly unusual for the IRC members in the United States to unanimously urge the commission to reject and remand a NERC reliability standard,” the IRC wrote. “The IRC does not take this step lightly, but given … the need to ‘get it right’ rather than just ‘getting it done,’ the IRC urges the commission to carefully weigh the fact that the record reflects the united opposition of all the RTOs and ISOs throughout the [U.S.] (and the [Independent Electricity System Operator] in Canada) to the exceptions and low winterization bar included in the proposed standard.”
Cost Concerns Misplaced, IRC Says
The IRC listed multiple issues with the standard, but a common theme was that NERC’s proposed requirements were “subjective [and] unclear.”
For example, Requirement R7 of EOP-012-2 excuses generator owners from implementing freeze protection measures if those measures would cause a “generator cold weather constraint” — meaning that the measures cannot be “implemented at a reasonable cost consistent with good business practices, reliability or safety.” Unreasonable costs include “prohibitively expensive modifications or significant expenditures on equipment with minimal remaining life.”
The IRC said this definition gives GOs multiple avenues to avoid implementing freeze protection measures, and forces NERC and the regional entities to judge the reasonableness and accuracy of an entity’s estimated costs. Pointing out that this is not normally the ERO’s jurisdiction, the IRC said the commission should direct cost-based constraints to be removed from the standard. Instead, IRC suggested constraints should be granted on a per-unit basis on grounds of technical feasibility, which the IRC observed falls under NERC’s expertise.
In addition, the IRC warned the standard “provides far too much discretion to [registered entities] to interpret whether freeze protection measures are available for [their] equipment when determining whether a basis exists to declare a constraint.” It noted that the standard’s definition of “freeze protection measures” refers to practices and technologies “generally implemented by the electric industry in areas that experience similar winter climate conditions.”
The council expressed concern this language would create difficulties with auditing the standard, because GOs could simply declare a constraint on the grounds that there are no available measures that are “generally implemented” by their peers. This could also “delay and disincentivize” the adoption of new technologies. IRC’s filing said the ERO should be directed to require measures that “would reasonably be expected to result in effective facility performance while operating at the extreme cold weather temperature.”
Exemptions Too Generous
IRC also took issue with the standard’s exemptions for existing generating units. The standard exempts units from some winterization requirements if they “may be called upon to … assist in the mitigation of … emergencies during periods at or below a temperature of 32 degrees Fahrenheit.” IRC suggested that this exemption should apply only to “truly seasonal generating units that will not be called upon to operate during freezing conditions” so that units unsuited for cold weather are not called on in emergencies.
NERC’s proposed timelines for implementing corrective action plans on units that experience cold weather-related emergencies — with entities’ required actions that can be completed within 24 and 48 months — were also a subject of the IRC’s criticism, with the council worrying that these periods “do not appropriately reflect the urgency of winterizing generating units.” It supported reducing the timetables to 12 and 24 months, along with requiring GOs to receive approval from NERC or their REs for longer implementation timelines.
In a statement, NERC said that EOP-012-2 is part of a “suite of cold weather standards [that] are key to addressing” grid impacts of severe cold weather. The ERO pointed to EOP-012-2’s clarifications of applicability, GOs’ eligibility for exemptions and shortening the implementation timeline as “key modifications that build on the general framework and principles established in EOP-012-1,” and said NERC is committed “to monitoring the effectiveness of the standard.”
HOUSTON — CERAWeek 2024 by S&P Global was supposed to explore “strategies for a multidimensional, multispeed and multifuel energy transition” and the energy industry’s response to growing demand for emissions reductions and cleaner forms of energy.
However, the two buzziest words during the weeklong conference March 18-22 turned out to be “data centers” and “artificial intelligence,” or AI, and their effect on growing electricity demand.
During one panel discussion, AES CEO Andrés Gluski noted the demand generated by data centers.
“I’m glad you mentioned data centers,” interjected the moderator, S&P Global’s Xizhou Zhou, “because every session seems to have to mention data centers or AI.”
“Coming out of the pandemic, we started to see demand increase two years in a row,” said Independent Electricity System Operator executive Chuck Farmer. “We’re less worried right now about data centers, but frankly, I wasn’t that worried about data centers until I came to this conference.”
Energy Secretary Jennifer Granholm said the explosive growth of data centers, cryptocurrency miners and AI-fueled technologies is what keeps her up at night.
Cryptocurrency miners have flocked to the U.S. after China’s 2021 crackdown on the industry. The U.S. Energy Information Administration says their energy demand could represent as much as 2.3% of electricity consumption, or 19 GW, according to the Cambridge Bitcoin Electricity Consumption Index (CBECI).
The CBECI estimated the U.S.’s global share of crypto mining went from 3.4% in 2020 to 37.8% in January 2022. ERCOT has 41 GW of requests for new mining capacity in its interconnection queue; about 9 GW have been approved for planning studies, according to NERC.
“Energy demand has been sort of flat because of energy efficiency, and now all of a sudden we’re seeing this huge increase because of AI, because of data centers, because of Bitcoin, because of crypto, because of the additional manufacturing facilities that are coming online because of electrification of transportation,” Granholm said during her appearance. “As the AI revolution has come upon us, I think we have to think a little bit differently about how we ensure that we’ve got enough power.”
Indeed. Experts say AI could be instrumental in creating additional energy efficiency and decarbonization tools. The DOE already has a pilot program to evaluate whether the huge amount of available data can speed up permitting timelines.
“Here’s the hopeful thing,” Granholm said “We really think that AI can be really helpful on quick permitting because with these huge datasets of land characterization, for example, and a huge amount of information already in the public datasets that DOE has access to through our national labs, we think that machine learning can speed up significantly permitting times.”
Microsoft co-founder Bill Gates said during his plenary session that AI can be used to determine the best ways to reduce demand at data centers that naturally will pop up where electricity is cheaper. AI also can be used to calculate emissions climate effects and improve efficiency.
“All of our sort of grid modeling and management, these AI tools will come in and play a role,” he said. “But the current techniques require a lot of electricity.”
Pattern Energy Eyes Next Project
Pattern Energy CEO Hunter Armistead, whose company recently broke ground on what may be the largest clean energy infrastructure project in U.S. history, a 550-mile HVDC line from New Mexico into southern Arizona, offered his own thoughts on speeding up transmission permitting.
“Tight timelines to respond also have timelines for challenge,” Armistead said.
Pattern’s SunZia Wind and Transmission project was placed on the drawing boards in the mid-2000s, back when Blackberrys ruled the business world and Taylor Swift’s “Love Story” first caught Armistead’s attention.
“[‘Fearless’] was a badass album, by the way. I mean, I became a Swiftie early on,” he said.
Pattern didn’t become involved in SunZia until 2018, and it secured FERC’s approval of its tariff only last year. All told, breaking ground on a project that should be commercially available within the next two years took 16 years. (See FERC Approves Tariff for SunZia Transmission.)
“Sixteen years … we can’t do that again. We have to learn from this arc of time and figure out how to shrink it quite a bit,” Armistead said.
While the project’s costs have risen to $11 billion and while Armistead said he hopes Pattern never does a deal that large again, he called SunZia a “transformative moment for our industry.”
“Deals like this more naturally don’t get done. The part that really just struck home with me is how critical this was to so many people,” Armistead said. “My absolute hope for the future is that this is only the beginning. As an organization, Pattern has had the opportunity to learn what this all takes to do.”
He said the company’s next “most ambitious project” is Southern Spirit, formerly known as Southern Cross. The project involves 320 miles of 525-kV HVDC transmission facilities interconnecting ERCOT with MISO and grids in the southeast. The project gained regulatory approval from the Texas commission in 2022 after seven years of review, and FERC has said Southern Spirit will not trigger its jurisdiction over ERCOT. (See “SCT Proceeding Closed,” Texas Public Utility Commission Briefs: Sept. 29, 2022.)
“It is going to be even more awesome [than SunZia],” said Armistead, who said he told staff Southern Spirit is his favorite operational project.
“The reality is the complexity of integrating to ISOs, the disparate weather patterns between what goes on in the southeast and the complication of integrating renewable generation that’s available to the southeast, yet being able to provide capacity back into ERCOT,” he said. “I have no idea how we’re going to structure the commercial side of it, but that’s what makes it super-duper fun.”
Glick Doesn’t Miss Politics
Former FERC Chair Richard Glick popped up at CERAWeek’s Innovation Agora, the conference’s technology and innovation programming center, to promote Hydrostor’s compressed-air, long-duration storage.
Glick told RTO Insider he is “fascinated” with the Canadian company’s technology. Hydrostor uses compressed air and water to store energy produced during the compression. The energy is then used to generate power when it’s released from underground rock caverns.
“We’re like a pumped hydro asset,” Hydrostor President Jon Norman said.
One of consulting firm Glick & Quinlan’s clients raised the former commissioner’s awareness of long-duration storage, defined as eight hours or more.
“There really is a need for longer storage, so I thought this was really kind of the right time to get in and talk about some of the policies. It’s been fun so far,” Glick said. “There are enormous benefits from an environmental perspective and from an economic perspective.”
Glick, who left FERC after 2022 when the U.S. Senate’s Energy & Natural Resources Committee refused to hold a confirmation hearing, said he misses his work at the commission. (See FERC’s Work in 2022 Left in Doubt by Manchin.)
“The issues are really interesting, obviously, and you’re in the middle of everything these days, for good and for bad,” he said. “I don’t miss some of the machinations, some issues that came up over time.”
Perhaps aware that three potential successors would be going before the Senate Energy Committee, Glick added, “I certainly don’t miss testifying on Capitol Hill.”
SMRs Could be Answer for Nukes
Texans have a reputation for talking big, and Jimmy Glotfelty is no exception. The regulatory commissioner has been tasked with leading a task force on whether the state can deploy small modular nuclear reactors (SMRs), but he’s not stopping there.
“This is an opportunity for us to open the door and lay out the welcome mat that we are interested in nuclear,” Glotfelty said during an Innovation Agora pod discussion. “We want to hear from you. If you all want to build, if you need to de-risk projects and we can help you do that in some way, let us know what that way is. That’s what we want to do here.
“We don’t want to be like every other state. We want to be ahead of every other state, and we want to build a business and an industry here for a global nuclear business,” he added. “That’s the way we are looking at this. Not to build one or two plants, but to build a community and to build an industry that will serve the world.”
The task force must deliver a report to the governor and the Legislature by December that outlines how plants are built and designed, how sites are identified, and whether any changes to laws or ERCOT protocols need to be made.
“We should look at nuclear plants in the long term like a dispatchable gas facility. I think as the cost curve comes down, [nuclear and gas] are going to be the same,” Glotfelty said. “That’s our expectation, that gas plants or nuclear plants can support the market’s reliability in an equal fashion.”
Speaking on a separate panel, former U.S. Energy Secretary Ernest Moniz, now CEO of the nonprofit Energy Futures Initiative, said nuclear technologies come in several flavors besides SMRs and include micro-reactors, light water, heavy water, fourth generation, thorium, liquid metal and molten salt.
Moniz said his initiative has put together a suggestion to kick-start SMRs’ deployment, noting it is translatable to gigawatt-scale reactors.
“The issue is getting an order book of sufficient scale to justify investments,” he said, suggesting the order book be put together by the government. “Government has a role to help this happen in the United States when it’s ultimately in the private sector, facilitating to share financial investment, because especially with a new design, the first reactor is likely to be substantially more expensive. If you can share the financial burden and price an order book for 10, 20 reactors or whatever you choose, that would be good.”
That’s exactly what the U.S. government is doing for TerraPower’s planned Natrium reactor in Wyoming. The Gates-founded group has about $1 billion in private funding and a reported $2 billion from the government supporting the project.
TerraPower CEO Chris Levesque told the Financial Times the plant could begin construction in June and enter commercial operation in 2030.
FERC on March 21 upheld its May 2023 order reinstituting de-pancaking provisions in Louisville Gas & Electric and Kentucky Utilities’ transmission rates, which the utility has challenged before the D.C. Circuit Court of Appeals (ER23-2656-001, et al.).
The commission’s May 2023 order reversed its 2019 decision allowing the company to remove provisions that de-pancaked its rates as a condition of LG&E/KU’s 2006 withdrawal from MISO, ensuring customers wouldn’t pay duplicate rates across the merged company’s territory.
FERC’s reversal followed a D.C. Circuit order remanding the 2019 decision back to the commission after several municipal utilities in Kentucky sued.
Upon reconsideration, FERC decided that removing the de-pancaking mitigation “will have an adverse effect on rates for the customers involved.” It directed LG&E/KU to reinstitute the provisions, retroactive to March 2021.
LG&E/KU complied, but not without protest. It filed both its new de-pancaked rates (Rate Schedule 525) and a request for rehearing of the order on remand. FERC in November found that the utility had only partially complied with its directive, as it had not fully restored the provisions of its pre-2019 rates (Rate Schedule 402). The utility also requested rehearing of this order.
FERC automatically rejected the utility’s rehearing request after not acting within 30 days. The order issued at the commission’s March 21 open meeting rejected the utility’s arguments as out of time: FERC found that it raised issues that should have been in response to the order on remand, not to the order on the company’s compliance filing.
“LG&E and KU’s substantive arguments, however numerous or illustrative, go beyond compliance with the remand order’s directive,” FERC said. “Further, contrary to LG&E and KU’s argument that this compliance filing was the first opportunity to address the justness and reasonableness of RS 525, LG&E and KU had a full opportunity to raise arguments supporting their request to end de-pancaking mitigation in the proceedings leading to the remand order, as well as raise arguments concerning the remand order’s compliance directive to reinstitute the de-pancaking provisions of former RS 402, now found in RS 525, in their subsequent request for rehearing of the remand order.”
FERC also issued a letter order March 21 approving the utility’s revisions to RS 525 (ER23-2656-002).
LG&E/KU will now take its arguments to the D.C. Circuit, where it filed a petition of review over FERC’s 2023 order in February.
