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December 20, 2024

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FERC Order 1920-A Wins Approval with Accommodations to States

WASHINGTON — FERC on Nov. 21 voted to approve Order 1920-A, which upholds most of the original’s changes to the commission’s rules on transmission planning and cost allocation while giving more consideration to states (RM21-17-001). 

Commissioner Mark Christie (R), who voted against Order 1920 when it was issued in May, joined the Democratic majority in issuing the revised order, which addressed his main criticism of the original: Transmission providers now will be required to file any cost allocation proposals agreed to by states in a region alongside their own for the commission to consider. 

The original order gave state entities six months to agree on a cost-allocation method for transmission projects, but planners could simply ignore it and file their own method. It represented a change from the Notice of Proposed Rulemaking that had drawn Christie’s support in the first place. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

FERC issues major orders like 1920 under Section 206 of the Federal Power Act, the same statute that covers complaints about utility rates and ISO/RTO rules. With Order 1920, FERC had to find that regional planning efforts around the country were leading to unjust and unreasonable rates and then come up with a just and reasonable replacement rate, Christie said at the open meeting. 

“The changes made today in Order No. 1920-A to the replacement rate set by Order No. 1920 go a long way [toward] restoring the state role to what the NOPR promised, and I am pleased to support these changes,” he wrote in a partial concurrence. “I express my deep appreciation to my colleagues for their willingness to engage in good-faith negotiations leading to these important changes to the replacement rate.” 

“This order builds upon an already strong Order No. 1920 and will further enhance the ability of state regulators to provide their important perspectives on the much-needed new transmission facilities our nation needs to ensure our grid can serve the significant growth in demand for electricity,” Chair Willie Phillips said. 

Other changes Christie applauded include a requirement that if a transmission provider wants to change a cost-allocation agreement after it has gone into effect, they will have to consult with state regulators. It also will allow the State Agreement Approach in PJM, which New Jersey used to plan connections for state-backed offshore wind, to stay in place under the new regional planning regime. 

Christie noted in his concurrence that “the requirement in Order No. 1920 that large corporate power-purchasing preferences must be a factor in planning long-term scenarios is explicitly removed. That was one of the most unconscionable, special-interest driven features of Order No. 1920, directing transmission providers to plan hundreds of billions of dollars of transmission projects to subsidize the power-purchasing preferences of huge multinational corporations and shifting the costs to residential and small-business consumers already struggling to pay their monthly power bills.” 

That means expensive transmission lines to connect corporate demand with resources they have contracted with will not be cost allocated to all customers in a region, he added. 

Commissioner David Rosner said he was proud to vote out a “bipartisan order” that makes meaningful changes to Order 1920 based on the rehearing requests but still fulfills the original’s purpose of identifying needed regional transmission infrastructure that makes the country more secure. 

“The need for this rule is urgent and obvious,” Rosner said. “In conversations I have had around the country these last few months in my new role, I have come to see that there is broad agreement that we have a pressing need for more infrastructure.” 

New large customers are looking to connect to the grid while the uses of electricity are expanding into new areas of demand, while the interconnection queues are overflowing with resources that Order 1920-A will help get connected to the grid, he added. 

Commissioner Judy Chang said Order 1920-A should get the country building major transmission lines. 

“Based on that experience, I think Order 1920 — and now Order 1920-A — is a very strong order, and substantially improves transmission planning and helps to solve the cost allocation problem that we’ve been talking about for the last 20 years,” Chang said.  

Failing to agree on cost allocation leads to a logjam of transmission projects that the new rule should help to break up, she added.

Commissioner Lindsay See (R) said she recused herself from participating in the order on the advice of FERC’s designated ethics official, but she has “been really encouraged by what I’ve heard about the process that led to it. This order involves some of the hardest and most important issues before the commission, [and] I’ve heard from my colleagues that it reflects many hours of serious discussion trying to understand different points of view. 

FERC had not published the text of the order by the close of business Nov. 21, so several stakeholders declined to comment until they had actually read it. 

But Grid Strategies President Rob Gramlich, who has long supported the kind of changes in Order 1920, said he liked that FERC is moving forward with the new planning and cost allocation rules. 

“The states that were concerned should be very happy,” Gramlich said. “It’s kind of a bipartisan, FERC-state kumbaya moment. No one got everything, everyone got something.” 

Christie’s concurrence cuts the legal and political risk, he added. 

“Hopefully most states lay down their arms and start participating in planning,” Gramlich said. 

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DOE Commits to Funding Gulf Coast, Midwest Hydrogen Hubs

The U.S. Department of Energy has announced $2.2 billion in funding commitments to two hydrogen hubs: the HyVelocity hub on the Gulf Coast and the Midwest Alliance for Clean Hydrogen (MachH2) hub in four Midwestern states.

The Nov. 20 announcement means the DOE so far has reached funding agreements with five of the seven hydrogen hubs selected in October 2023 to receive a combined total of up to $7 billion through the Infrastructure Investment and Jobs Act. (See DOE Designates Seven Regional Hydrogen Hubs.)

The previous agreements are with the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) hub in California; the Appalachian Regional Clean Hydrogen Hub (ARCH2); and the Pacific Northwest Hydrogen Hub (PNWH2). (See California Reaches Funding Agreement to Launch Hydrogen Hub; Pacific NW Hydrogen Hub Launched with 1st Round of Federal Funds; and Feds Launch Appalachian Hydrogen Hub.)

The two hubs still in funding negotiations with the DOE are the Heartland Hydrogen Hub in Minnesota, North Dakota and South Dakota and the Mid-Atlantic Hydrogen Hub in Pennsylvania, Delaware and New Jersey.

In the two new awards, DOE committed up to $1.2 billion to the HyVelocity hub, with an initial funding round of $22 million. The MachH2 hub will receive up to $1 billion in federal funding, including an initial allotment of $22.2 million. The initial funding will allow the hubs to launch, starting with a planning and design phase expected to last 12 to 18 months.

DOE’s Office of Clean Energy Demonstrations (OCED) will oversee development of the hydrogen hubs and decide whether to provide funding for the hubs to progress to the next stage.

It’s not clear what impact the incoming Trump administration will have on the hydrogen hub funding. When asked about potential funding impacts, a DOE spokesperson noted that OCED was established to oversee large and complex projects that can span 10 years or more. “The dedicated federal workers within OCED remain committed to this mission,” the spokesperson told NetZero Insider in an email.

Gulf Coast Hub

The HyVelocity hydrogen hub would be centered around Houston and serve the Gulf Coast region. The Gulf Coast already is the nation’s largest hydrogen producer, according to HyVelocity, which aims to be the largest hydrogen hub in the U.S.

The industry-led hub includes six core partners: AES Corp., Air Liquide, Chevron, ExxonMobil, MHI Hydrogen Infrastructure and Ørsted. As proposed, the hub would produce clean hydrogen by electrolysis of water and from natural gas coupled with carbon capture and storage. The plan also includes pipelines to connect production facilities to demand centers.

The clean hydrogen would be used for fuel cell electric trucks, industrial processes, ammonia production, refining and petrochemical production, and marine fuel, according to a project fact sheet. The total cost for Phase 1 of the Gulf Coast hub is $56 million, including the $22 million federal contribution.

Midwest Hub

The Midwest Alliance for Clean Hydrogen hub is eyeing project sites across Illinois, Indiana, Iowa and Michigan, with possible expansion into other states. The hub is in “a key U.S. industrial and transportation corridor,” according to the Alliance.

As proposed, the hub would produce more than 1,000 metric tons per day of clean hydrogen using diverse local energy sources such as renewable energy, natural gas and nuclear power, according to a project fact sheet.

“Our fleet of always-on nuclear power plants in Illinois is helping to power our economic growth with clean energy today and positions us to be a leader in the clean hydrogen future,” Illinois Gov. JB Pritzker said in a statement.

The Midwest hub consists of eight projects to be developed by nine entities: Air Liquide; BP; Constellation Energy; GTI Energy; Invenergy; Mass Transportation Authority – Flint; Michigan Department of Environment, Great Lakes and Energy; Midwest Hydrogen Corridor Coalition; and Nicor Energy Ventures (NEV).

The projects aim to decarbonize industries including heavy-duty transportation, manufacturing, steel and glass production, power generation and refining. Phase 1 of the Midwest hub will cost $51.7 million, with $22.2 million coming from the DOE.

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FERC Outlines Reliability Impacts from Colder Winter

Electricity and natural gas demand could be higher this winter because of lower expected temperatures than last year, and large parts of the North American electric grid face a “higher likelihood of tight supply and reliability issues during extreme winter conditions,” FERC staff said Nov. 21 while presenting the commission’s 2024-2025 Winter Energy Market and Electric Reliability Assessment.

NERC representatives also joined FERC staff for the presentation at the commission’s monthly open meeting, providing insights from the ERO’s recently released 2024-2025 Winter Reliability Assessment. (See NERC Sees ‘Reasons for Optimism’ as Winter Approaches.) Like NERC’s assessment, the FERC report covers December 2024 through February 2025.

Opening the presentation, Micah Gowen, of FERC’s Office of Energy Policy and Innovation, outlined multiple potential trouble spots during the winter months. The report highlighted the National Oceanic and Atmospheric Administration’s forecast for December through February, predicting lower overall temperatures across the U.S. compared to last winter.

Colder temperatures “could contribute to higher year-over-year natural gas and electricity demand,” the report said, though it noted that NOAA also suggested the southern and eastern parts of the country may experience higher-than-average temperatures, with as high as a 70% chance in some areas. In addition, Gowen noted that “all regions may face a higher likelihood of tight generation availability under extreme weather conditions.”

Drought, Wildfire Risks Persist

Additional weather-related influences include drought conditions and wildfire risks, both of which are expected to persist into the winter in multiple regions. NOAA’s three-month precipitation outlook shows droughts are likely to improve in the Pacific Northwest because of projected rains from La Niña but persist in the central U.S. and even increase in the Southwest and Southeast. This could limit the availability of hydroelectric generation in some parts of WECC’s territory, though the increased rain in some areas may help to balance this issue.

Wildfire risks are forecast to remain elevated into the early winter in Texas, Oklahoma and Southern California because of dry conditions and to continue through winter in Texas, where higher temperatures than the rest of the country are predicted. The persisting wildfire conditions could lead to public safety power shutoffs. On the other hand, mild temperatures could lower electric demand and “allow for greater system operator flexibility,” the report said.

Natural gas futures prices for the past three winters. Prices for 2024-2025 are average last traded futures prices for December, January and February. Previous winters’ prices are average settled futures prices. | Intercontinental Exchange

With natural gas production likely to “remain relatively unchanged compared to winter 2023-2024,” Gowen said, the expected higher demand for gas for heating and electricity generation has pushed natural gas futures prices higher at several hubs. The report quoted the Energy Information Administration’s forecast average production of 104 Bcfd, down 1% from last winter’s average but still 6% above the previous five-year average.

As of Nov. 14, futures contract prices at the national benchmark Henry Hub in Louisiana averaged $2.95/MMBtu for this winter, up from last winter’s average settled futures price of $2.61. Prices at the Algonquin Citygate Hub near Boston averaged $8.86, up from $7.61 settled last winter. The report noted that an additional influence on New England natural gas prices is high global LNG prices because the region heavily relies on imports during the winter.

Prices are also lower at several hubs, including PG&E-Citygate in Northern California, with average prices for this winter down 10% from last winter at $4.74/MMBtu, and SoCal-Citygate, down 3% at $5.02. The report attributed these declines to mild forecasted winter weather, higher storage inventories and increased hydroelectric generation.

Reliability Effects

Rakesh Batra, of FERC’s Office of Electric Reliability, discussed the supply and demand forecasted for each NERC region.

Citing NERC’s assessment, Batra said that all regions “have sufficient available resources and net transfers to meet their respective operating reserves under normal winter conditions,” despite higher electricity demand compared to last winter. However, he added that extreme events may drive demand higher or damage transmission and generation facilities, making serving demand more difficult.

Batra noted that NERC and other stakeholders have taken numerous steps since the winter storms of 2021 and 2022, including the passage of the cold weather standards EOP-011-4 (Emergency operations) and EOP-012-2 (Extreme cold weather preparedness and operations), both of which became effective Oct. 1. However, he also said that grid reliability could be impacted this winter by the ongoing restoration work from Hurricanes Helene and Milton, which hit the Southeast earlier this fall.

Commissioners reacted to the report’s warnings by encouraging stakeholders to make grid reliability a priority investment, including by accelerating compliance with the new cold weather standards. Commissioner David Rosner said that, although many of the new standards’ requirements will not become effective until next year, “the best time to comply with the 2025 deadline is today.”

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Powerex to Cancel Rights on PacifiCorp Tx System over EDAM Changes

Powerex intends to terminate a large portion of its rights on PacifiCorp’s transmission system in response to the utility’s plan to update its Open Access Transmission Tariff to align with CAISO’s Extended Day-Ahead Market (EDAM), the company said in a Nov. 14 paper that also warned the changes could cost the utility about $135 million in revenue.

Powerex argued in the paper that PacifiCorp’s expected tariff changes could lead to the utility using EDAM’s rules related to the distribution of transmission congestion rents to “effectively strip” its transmission customers of “the economic value of their transmission rights” — to the detriment of customers in both EDAM and SPP’s Markets+.

“Unfortunately, PacifiCorp has chosen to use its entry into EDAM to fundamentally redefine what it provides to its transmission customers in exchange for the transmission revenue it collects,” Powerex, the energy marketing arm of Vancouver, Canada-based BC Hydro, wrote.

The company’s contention potentially opens up yet another front in ongoing competition between EDAM and Markets+ and in the debates between each market’s supporters.

PacifiCorp’s plans already have led to Powerex providing a notice “to terminate the vast majority of Powerex’s long-term firm point-to-point transmission rights on PacifiCorp’s transmission system, for which Powerex currently pays over $42 million per year to PacifiCorp,” according to the paper.

However, despite the move to cancel the contracts, Powerex emphasized it will retain 200 MW of rights to ensure power flows in SPP’s Markets+ — a position it intends to fight for before FERC.

Jeff Spires, director of power at Powerex, told RTO Insider in an email that the company “continues to hold the long-term firm transmission rights it intends to use for Markets+ connectivity, and is committed to protecting these rights on the PacifiCorp system.”

Under PacifiCorp’s anticipated changes, transmission customers will face new congestion charges calculated in EDAM, collected in CAISO and delivered to PacifiCorp, according to Powerex. The congestion charges will not be returned to customers but rather spread across all of PacifiCorp’s load and exports, the paper stated.

“As a result, transmission customers that wish to use their rights to schedule physical deliveries outside of organized markets will not receive the economic value of the path they invested in, but will instead face volatile and potentially large EDAM congestion charges that they cannot manage or hedge,” Powerex argued. “Similarly, customers that wish to use their firm transmission rights in Markets+ will also not receive the economic value of the path they invested in, as they too will face these EDAM congestion charges (that are again allocated largely to PacifiCorp).”

Transmission customers will be forced to sell their transmission rights to CAISO for use in EDAM to continue receiving congestion value associated with their delivery path, Powerex contended.

PacifiCorp could lose out on $135 million per year from its sale of point-to-point service to unaffiliated transmission customers, as the proposal will reduce the incentives to invest in the company’s firm transmission service, Powerex alleges.

“Any loss of third-party transmission revenue resulting from PacifiCorp’s proposal will directly increase the revenue that PacifiCorp must recover through higher retail rates,” the paper stated. This loss in revenue has not been considered in any EDAM benefit study, according to Powerex.

Clarity Needed at Market Seam

Additionally, Powerex urged Portland General, NV Energy, Idaho Power and LADWP, among others, to “consider whether to follow PacifiCorp’s lead and jeopardize their existing transmission revenue stream, or to instead seek ways to continue to provide the core benefits that are the foundation for transmission customers’ investments in long-term firm transmission service.”

The tariff changes highlight the absence of a governance structure in EDAM that protects transmission rights “in an equitable and consistent manner,” according to the paper.

When asked to comment on Powerex’s paper, a PacifiCorp spokesperson told RTO Insider that “[i]n developing its tariff for participation in EDAM, PacifiCorp has taken the view that addressing transmission usage for other markets is premature at this stage since market to market coordination requires larger discussions with stakeholders that can only occur in the context of developed and approved market designs. Once the issues at market seams become clearer, PacifiCorp will work with stakeholders and relevant parties to address those issues.”

Portland, Ore.-based PacifiCorp, whose sprawling territory includes portions of six states, was the first utility to join CAISO’s Western Energy Imbalance Market in 2014 and the first to publicly announce its intent to join EDAM in December 2022.

The company fully committed to joining EDAM in April. (See PacifiCorp Fully Commits to CAISO’s EDAM.)

Cindy Crane, CEO of PacifiCorp, recently touted the benefits of EDAM during CAISO’s Stakeholder Symposium in October, citing CAISO data showing $6 billion in member benefits from the WEIM since its inception and $1.4 billion in benefits in a fully implemented EDAM. (See Western Utility CEOs Reflect on Evolving Energy Markets.)

However, SPP’s plan to launch Markets+ has gathered momentum over the past two years and has garnered support from powerful backers such as the Bonneville Power Administration and Powerex.

In the competition for participants between the two markets, Markets+ supporters have consistently pointed to the market’s independent governance structure and market design established under that governance. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.)

Powerex’s recent paper continued to push that argument while also claiming that EDAM benefits studies have failed to consider potential revenue losses if PacifiCorp’s transmission tariff proposal should pass.

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MISO Outlines Plan on Fast-track Queue for Resource Adequacy

MISO hopes to file a proposal in February to create an exclusive, faster route through its interconnection queue for generation projects that are key to maintaining resource adequacy.

At a special Nov. 18 workshop, Director of Resource Utilization Andy Witmeier said MISO hopes to have the fast-track process in place by June for generation projects that are key to sustaining resource adequacy over a five-year horizon. (See MISO to Devise Express Lane in Queue for Generation Projects that Keep Lights On.)

Witmeier emphasized that MISO sees the fast pass as a short-term fix, with a sunset date included in the proposal. That date would be based on the RTO’s best estimate for when it might have its interconnection process streamlined enough to achieve a one-year queue wait time for generation projects.

“It will take us time to get a one-year queue process,” Witmeier warned.

Some stakeholders said dividing the queue into two parallel processes with one given priority might result in two clogged queues, making MISO’s ultimate goal of a single, yearlong process even more unattainable.

Witmeier said MISO’s automatic withdrawal penalties in place for the traditional queue likely will curb the late-stage withdrawals that set restudies in motion and make processing sluggish.

“The restudies on the older cycles is preventing us from finalizing the newer cycles. … We’re plagued with restudies. And we can’t wait for that any longer,” Witmeier said.

“What I can tell you is, if I’m not down to a one-year queue cycle by 2028, I’m paying penalties,” he added, invoking FERC’s Order 2023.

Witmeier said that to enter the expedited process, generators must be part of a plan from a load-serving entity, be able to come online within three to five years for a known RA need, have network service to be deliverable and have endorsement by their state as a necessary project. MISO would not discriminate based on fuel type as long as a project is deemed essential.

The RTO is working with the Organization of MISO States on what documentation that states and authorities might use to demonstrate that a project is necessary, and how that documentation might differ for projects located in MISO’s deregulated areas.

Witmeier also said MISO will need to establish a cost allocation method for the projects. The RTO probably would charge a higher, nonrefundable application fee to cover staff hours for the studies, which will be conducted serial-style instead of in batches.

Clean Grid Alliance’s Beth Soholt asked what would happen if a project enters the expedited queue only to not ultimately receive a certificate of public convenience and necessity.

“Ultimately, whether or not to recognize that project is necessary as a resource adequacy project is up to that jurisdiction,” MISO Deputy General Counsel Kristina Tridico said.

“We think the likelihood of projects going into [the expedited queue] and dropping out is very low,” Witmeier added. Projects that have state backing are already usually considered foregone conclusions, he said.

Travis Stewart, representing the Coalition of Midwest Power Producers, said that even an express lane will not make RA projects “immune” from the exorbitant network upgrade costs often found in MISO interconnection studies.

But Witmeier said that under the expedited processing, developers should get a clearer idea sooner of network upgrade costs.

“We expect a lot of these LSEs will have done their due diligence and done their own studies on expected network upgrades,” he added.

So far, MISO is not proposing a withdrawal penalty for the expedited class of projects. Stakeholders asked it to reconsider that stance, arguing that even those projects could be canceled.

Sustainable FERC Project’s Natalie McIntire said existing projects in the regular queue might be harmed financially through expedited projects snapping up available transmission capacity first. She asked how MISO would make sure that the regular queue is still viable.

Witmeier said MISO will draw on the same system modeling for the regular and accelerated processes. He said projects in both queues would have a chance to claim transmission capacity on the system. After that, MISO would consider it unavailable.

McIntire said she did not see how, somewhere along the line, the parallel processes would not assign the same transmission spot to two projects.

“It seems to me we have a math problem,” McIntire said.

“It seems like an age-old problem that we’ve had, and we’re compounding it,” WEC Energy Group’s Chris Plante agreed.

MISO will hold another workshop to hammer out details on its expedited resource adequacy queue studies Dec. 6.

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Texas PUC’s Cobos to Leave Commission

Texas Public Utility Commissioner Lori Cobos announced Nov. 21 that she plans to step down from the commission at the end of 2024.

Cobos told her fellow commissioners, PUC staff and stakeholders that she already had shared her plans with Gov. Greg Abbott. She promised a much broader statement during the commission’s last open meeting of the year, Dec. 19.

“It has been a tremendous honor and a privilege to serve as a PUC commissioner,” Cobos said. “I want to thank the governor for the opportunity of a lifetime and for placing his trust in me to serve on the commission after Winter Storm Uri. I’ll say a lot more later … we’ve accomplished an extensive list of important milestones at the commission over the last several years, and I am proud and tremendously grateful to have been part of that amazing work.”

Cobos has played a leading role in the development of major transmission infrastructure projects, including in the Permian Basin region in West Texas and in the Rio Grande Valley. (See Texas PUC Approves Permian Reliability Plan.)

She was one of the three commissioners named to replace the PUC’s incumbents, all of whom left the commission after the devastating February 2021 winter storm that came within minutes of collapsing the ERCOT grid. Cobos joined Peter Lake, who chaired the commission, and Will McAdams. Both left the PUC in 2023.

The commission since has been expanded by state law to five members.

“Like I told Peter and Will when they were leaving, ‘Thank you for being willing to say: yes.’ These were not jobs that people were falling all over themselves to come take right after Winter Storm Uri,” commission Chair Thomas Gleeson told Cobos. “It took a special kind of person with the heart of a public servant to want to come and do this right after the storm. You will be missed up here.”

Abbott appointed Cobos to the PUC in June 2021. Her term expired that September but by law, she did not have to be reappointed and has continued to serve at the governor’s pleasure. (See Abbott Taps OPUC’s Cobos to Fill out PUC.)

Cobos has more than 20 years of experience in the Texas power industry, including several senior-level positions at the PUC and in-house counsel at ERCOT. She joined the commission after being appointed as CEO and public counsel for the Office of Public Utility Counsel.

Cobos is an ex officio member of the ERCOT Board of Directors and serves on SPP’s Regional State Committee. She also is president of the Southeastern Association of Regulatory Utility Commissioners.

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La. PSC Reviewing Entergy Request for $5B Data Center with Gas Gen

The Louisiana Public Service Commission has taken the first steps to consider Entergy’s request to power a proposed $5 billion artificial intelligence data center in northern Louisiana with $3.2 billion in mostly natural gas generation.  

Louisiana commissioners at their Nov. 20 meeting voted unanimously to hire familiar firms Stone Pigman and the Sisung Group’s United Professionals Co. to review Entergy Louisiana’s application (U-37425), which could spell a possible 25% increase in its generation, according to commissioners. 

Though Entergy continues not to name the customer, multiple news outlets reported that Public Service Commissioner Foster Campbell confirmed outside of the meeting that Facebook parent Meta seeks to raise an AI data center in Richland Parish. Meta currently does not list a Louisiana-based data center among its plans. 

According to its filing made earlier in November, Entergy plans to build three new combined cycle natural gas generators at a combined 2.26 GW, a new 500-kV transmission line and substation, and other upgrades to host the unnamed large customer. Entergy seeks cost recovery and rate-making treatment for the project, as well as a corporate sustainability rider, where the customer would commit to funding 1.5 GW of new solar or solar and storage hybrid generation. Entergy also requests an exemption from an RFP competitive solicitation process and a ruling from the commission by October 2025. 

In a statement to RTO Insider, Entergy again declined to identify the customer, with spokesperson Neal Kirby saying the utility is “not able to identify the type or scope of the customer until the customer is ready to disclose their plans.”  

Entergy said in its filing that it expects the data center “has the potential to transform the economic landscape” of northern Louisiana and “employ directly 300 to 500 employees with an average salary of $82,000, in a region of the state that has long struggled with a lack of economic development and high levels of poverty.”  

Richland Parish’s approximately 20,000 residents have an average $25,285 per capita income, according to the U.S. Census Bureau.  

“This is the best news that we’ve had in north Louisiana in a long, long time. So, I’m for it 1,000%. We need it more than anybody. This data center would be a godsend for northeast Louisiana,” Campbell said at the meeting, adding that the data center could represent an investment of anywhere from $5 billion to $10 billion. 

Campbell said he thought the facility is all but a given and added that a lot of people “will have good-paying jobs.” 

The Louisiana PSC allowed consulting firm United Professionals a maximum of $675,000 and law firm Stone Pigman a maximum of $788,000 to evaluate Entergy’s request. 

“This is a very expansive docket that may require, depending on what happens with intervenors and whatnot, very extensive legal work and legal services. We’re talking about the approval, certification of five different resources, including three generating resources, one high-voltage transmission line and upgrades of a transmission substation. So, it’s all rolled into one proceeding that needs to be handled on an expedited basis. The customer here has expressed a need to get this done quickly, to get this data center to market very quickly,” Stone Pigman attorney Dana Shelton explained to the commission. She added that she anticipated hearings in the docket.  

Commissioner Davante Lewis said that while the commission is on “an [expedited] timeline,” he urged the law firm to make sure “every intervenor is heard” and asked for a “thorough review.”  

“There are a lot of complicated issues that should be worked out that could be beneficial, especially when we’re talking about the generation capacity, the water consumption,” Lewis said. “These are long-term commitments; these are big projects.”  

Shelton said while she was “encouraged by the package Entergy has put on the table,” her firm would make sure “unwarranted costs are not visited on our residential ratepayers.” 

Longtime PSC consultant Lane Sisung, of United Professionals, told commissioners his evaluation will be complex because it involves not one but three generators, associated transmission and “future rate mechanisms to allow a single customer access to renewable portfolios.”  

“It has many elements to it that aren’t normally within a bid,” Sisung said, adding that the consulting firm also would monitor Entergy’s construction and conduct a prudence review.  

Entergy did not respond to RTO Insider’s request for comment on how the three new gas plants could fit into Meta’s zero-carbon target coming due within six years. Meta has a goal to reach net zero emissions across its “value chain,” which extends beyond its data centers to its suppliers, sometime in 2030. Kirby said Entergy is committed to its own net zero by 2050 emissions goal, but did not address the 20-year mismatch between Entergy’s and Meta’s aims.  

In its filing, Entergy said the unnamed customer has “robust sustainability goals.” The utility added that it explored alternatives but didn’t find any as strong a trio of new gas plants.  

The Alliance for Affordable Energy, the Southern Renewable Energy Association (SREA) and the Union of Concerned Scientists already have petitioned to intervene in the case. SREA’s filing indicates Entergy’s requested exemption from a competitive solicitation for the generation would “unfairly limit competition.”  

During the utility’s most recent earnings call, Entergy CEO Drew Marsh said the new industrial customer — presumably Meta — signed a 15-year electric service agreement with Entergy Louisiana. Marsh at the time also said Entergy was in “active discussions” about carbon capture solutions with customers, refraining from naming any. 

Marsh also mentioned Entergy Louisiana’s front-end engineering and design study to evaluate the technical and financial feasibility of installing carbon capture and sequestration (CCS) at the Lake Charles Power Station. (See Entergy CEO: Nuclear, Carbon Capture in Equation to Handle Industrial Growth.)  

According to Entergy’s application, the large customer “has agreed to pay a capped amount” toward the cost of CCS at the Lake Charles Plant. 

Entergy also said the proposed corporate sustainability rider for the customer could offset “a significant percentage of emissions” from the planned natural gas generators. 

Finally, Entergy noted that the new gas plants would be “30% hydrogen co-firing with the capability of supporting 100% hydrogen firing in the future with upgrades, and all will have the ability to incorporate a CCS component in the future.” The utility said it’s also possible it could offer the plants’ excess supply in the MISO markets, lowering costs for its customers. 

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Kairos Power Cleared to Build Demonstration SMRs

The Nuclear Regulatory Commission has approved construction of Kairos Power’s Hermes 2 demonstration plant in Oak Ridge, Tenn. The NRC and Kairos announced the decision Nov. 20. 

It is the first fourth-generation electricity-producing reactor to be greenlighted for construction in the U.S. It will be shaped by the knowledge gained from Hermes 1, a low-power demonstration reactor producing heat but not electricity, which in December 2023 became the first Gen IV reactor to receive a construction permit in the U.S. 

The fluoride salt-cooled, high-temperature design also was the first non-light-water reactor to be permitted in the U.S. in more than a half-century. It is the heart of Kairos’ business model but only part of an iterative, vertically integrated effort to commercialize advanced reactor technology. 

Reactor modules will be fabricated in New Mexico and shipped to Tennessee using modular construction techniques, which likely are to be central to any successful effort to scale and speed the deployment of small modular reactors in the United States. 

This standardization is hoped to eliminate the feedback loop in the U.S. commercial nuclear sector — high cost and low speed of construction help limit new projects, while the scarcity and uniqueness of projects help make construction so slow and expensive. 

Standardizing and multiplying new projects could change this. 

Many policy makers are eager to see this change, and see nuclear fission emerge as an affordable and constant source of zero-emissions power. 

The U.S. Department of Energy has committed up to $303 million to the Hermes project. 

The NRC approval process for the Hermes 2 construction permit is one step toward the modularization that could reduce the time and cost needed to build a reactor: Hermes 2 incorporated process improvements made during the Hermes 1 review, and the similarities between the two iterations allowed the second review to leverage work done in the first. 

Peter Hastings, Kairos’ vice president of regulatory affairs and quality, highlighted this in a news release: “The licensing basis established with both the Hermes and Hermes 2 construction permits will carry forward to future license applications, ensuring the safety of Kairos Power’s deployments while supporting continued innovation and efficiency in the review process.” 

Another factor: NRC has streamlined its mandatory hearing process, which now is conducted via written documents. 

“While keeping safety at the forefront, the permitting process was quite efficient, and we issued these permits in less than 18 months,” NRC Chair Christopher Hanson said in a news release. “This shows we can rapidly apply relevant conclusions from earlier reviews to promptly reach decisions on new reactors.” 

Small modular reactors and other next-generation nuclear technologies have some hurdles to overcome before widespread deployment. Safe, affordable and scalable designs must be perfected, a fuel supply chain must be built, a raft of regulatory approvals must be secured and public support must be built for a technology that long has been a pariah. 

But there is widespread interest in seeing this happen. 

Big Tech has begun betting on nuclear to power the data centers that are expected to add significant demand to the grid. 

In October, Google and Kairos announced a first-of-its kind power purchase agreement for Kairos reactors starting by 2030 and growing to 500 MW by 2035. (See Google, Kairos Sign 500-MW Nuclear PPA.) 

Hermes 1 is targeted for operation in 2027. 

Hermes 2 will bring together Kairos’ various research and development efforts in a complete plant architecture at reduced scale, with two 35-MW reactors and a shared power-generation system feeding 20 MW into the grid once NRC approves its operating license. 

Operational data gleaned from Hermes 2 would support development of a larger version for commercial operations, and build certainty around licensing, the supply chain and construction of future reactors, Kairos said. 

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AEU Report Shows Major Economic Benefits from Quicker Queues

Fixing the interconnection process to speed up the development of new generation could add $100 billion in economic benefits, according to an analysis released Nov. 21 by Advanced Energy United.

Improving interconnection processes around the country could lead to $57 billion in economic benefits and 667,000 job-years from increased solar energy deployment and $42 billion and 376,000 job-years from increased onshore wind deployment, according to the report, “How Interconnection Reform Can Accelerate Clean Energy Deployment.”

“Our nation’s electricity demands are growing, and these broken interconnection processes are standing in the way of Americans building the energy projects we need to thrive,” AEU CEO Heather O’Neill said in a statement. “Fixing interconnection would unleash job-creating energy projects and deliver an economic boom in states across America. If states can more quickly build the poles and wires needed to connect new electricity resources to the power grid, they will unleash their economic potential, lower electricity bills for residents and improve energy reliability for all.”

Generators coming online in 2023 averaged five years in the queue, from when they requested interconnection to commercial operation, compared to an average of just two years from 2000 to 2007.

FERC has attempted to address the issue with orders 2023 and 1920, and the report argued that states can support and build on those efforts by engaging in implementation and pushing for supplemental reforms.

“In the United States, almost 2,500 GW of non-emitting power generation and energy storage capacity are seeking to interconnect, equivalent to double the capacity of all generation sources currently online in the United States,” the report says. “Legacy interconnection processes were established decades ago to individually evaluate a small number of large, predominantly coal and natural gas power plant proposals, and these processes are ill-suited to evaluate thousands of more geographically distributed wind, solar and energy storage projects.”

The precise impacts of speeding up the queues will take years to play out, but the report offers an illustrative analysis showing how accelerating them can benefit the economy.

Under one of the scenarios, attrition of projects initially increases by 25% this year, which reflects a “purging” of the queues prompted by Order 2023’s higher financial requirements. But as additional improvements play out, project attrition is expected to fall by 50% from historic rates, while a business-as-usual case would see a 10% increase.

The report includes state projections (for the Lower 48 except Texas) for projects getting through the queue quicker and what benefits that would bring to their economies.

“Results vary between states, which is to be expected, as interconnection requests reflect renewable energy resource potential, state policy support and local project development considerations such as land availability, perceived permitting complexity, local construction costs and more,” the report said. “Nonetheless, each state sees incremental renewable energy deployment with interconnection reform.”

For most states, implementing changes will lead to an appreciable increase in renewable projects, with California, for instance, seeing 147 TWh in additions by 2030, compared to 112 TWh under business as usual.

One clear group of exceptions is those states banking on large offshore wind contracts — Connecticut, Delaware, Maryland, Massachusetts, New Jersey and Rhode Island — for most of their incremental renewable growth. The successful deployment of offshore wind depends on other factors, the report says.

“In a few states, successful interconnection reform leads to a significant increase in renewable generation such that generation in 2030 exceeds state [renewable portfolio standard or clean energy] requirements,” the report says. “New Mexico and Arizona show renewable energy generation increases that outstrip state requirements, showing that each state is well positioned for exporting first-rate solar and wind-generated electricity.”

The report suggests that states advocate for transmission providers to build trunk lines that aid interconnection and fast-track interconnection requests that are proposed for areas with available grid capacity.

It also suggests tailoring analyses to requested levels of interconnection (capacity- or energy-only), standardizing study assumptions, evaluating alternatives to traditional transmission upgrades, using automation, and using independent monitors to oversee the process and recommend improvements.

Another suggestion is to expedite construction of needed upgrades by adopting industry best practices and proactively addressing supply chain constraints.

“By engaging directly with FERC, pursuing available federal funds and calling on their regional grid operator to fulfill their responsibility to provide reliable and low-cost electricity, states can maximize economic opportunities made possible by more abundant solar and wind projects,” O’Neill said.

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CAISO Kicks off ‘Workshop’ to Update RA Mechanisms

CAISO on Nov. 18 kicked off a Resource Adequacy Modeling and Design “workshop” designed to reevaluate and refine several mechanisms the ISO uses to ensure resource adequacy.

The workshop builds on the ISO’s RA Modeling and Program Design working group, in which staff and ISO stakeholders highlighted problem statements associated with the RA program. It aims to continue refining solutions to the problems identified and develop policy responses.

The main goal of the effort is to update the default counting rules and planning reserve margin (PRM), evaluate the need for the Resource Adequacy Availability Incentive Mechanism (RAAIM) or an unforced capacity mechanism (UCAP), and reevaluate outage and substitution rules and the capacity procurement mechanism (CPM), also referred to as the “backstop.”

The issues will be addressed in the three different tracks, but ISO staff noted the tracks can be combined or changed based on stakeholder feedback.

Track one addresses modeling, default rules and accreditation, while track two deals with outage substitution and availability and performance incentive mechanisms. Track three tackles visibility and backstop.

The workshop will be further divided into three “packages” that outline workflow. Package one identifies minimal changes needed to take the first step in addressing the topic, package two outlines forward planning and package three covers operational measures.

The packages are “illustrative” and not representative of CAISO’s preferred or final approach, said Partha Malvadkar, principal of RA and infrastructure policy at the ISO.

“What we’re looking for as we work towards policy development is packages of changes that make sense together and that are achieving the goals and objectives that came out of the working group process in a comprehensive and consistent manner,” Malvadkar said.

PRM and Default Counting Rules

Another central aim of the initiative is to evaluate how well PRMs and counting rules set by local regulatory authorities (LRAs) reflect forced outage rates, performance and availability. Evaluating the need for UCAP, which was discussed in the prior initiative, fits into this area. (See CAISO Considers Replacement of RA Incentive Program.)

“In response to potentially changing regulatory structures at the CPUC (including the scoping of UCAP), CAISO has an opportunity to establish alternatives to the current resource counting design and eliminate/redefine availability and performance incentives while acknowledging LRA authority to establish counting rules,” according to a presentation from the meeting.

The ISO also identified the need to update the PRM based on changes in the RA resource mix and evolving reliability needs within the CAISO balancing authority area (BAA). CAISO policy developer Ansel Lundberg identified that qualifying capacity values, also referred to as “counting rules,” should reflect the relative contribution of different resource types to maintain BAA-wide and local reliability and to meet at least a 0.1 LOLE.

The initiative also addresses the need for capability testing to account for seasonal resource availability. According to Lundberg, the availability of resources based on varying seasonal ambient derates is not consistently reflected in resource net qualifying capacity (NQC), which poses challenges for grid operations. CAISO thinks it should adopt minimum requirements so it can rely on capacity to perform consistent with accreditation in a given season. Such requirements could minimize partial forced outages that derate resources below their NQC value during critical periods.

Outages and Substitution

CAISO also intends to work to establish a more efficient process for outages and substitution. Central to that is developing a voluntary planned outage substitution pool, where scheduling coordinators can make capacity available and pay for it if needed. SCs could also procure from the pool.

The ISO is also considering developing a planned outage buffer provided by each LRA, as well as moving to annual or seasonal showings, CAISO lead policy developer Anja Gilbert said.

The final intent of this track is to remove planned outage substitution requirements and replace them with strong incentives and better information about periods of risk.

RAAIM Reform

RAAIM is one such incentive mechanism that could help remove planned outage substitution requirements. But the ISO is considering revising RAAIM to become a “pay-for-performance” mechanism for capacity to respond and non-capacity resources to be available during scarcity conditions.

That model, which has been implemented in PJM and ISO-NE, acts as both a reward and penalty relative to a resource’s obligation during scarcity events. If a supplier’s poor performance contributes to reliability risk, it could face “strong consequences,” according to Lundberg’s presentation.

Backstop and Visibility

A central component of the prior and current RA initiatives within the ISO is the need for more visibility into RA and non-RA resources. (See CAISO’s Capacity Procurement Mechanism Inefficient, Stakeholders Say.) CAISO’s lack of visibility into the “not-shown” RA fleet makes the backstop mechanism less efficient, but regular reporting on the status of RA capacity could improve the system, said CAISO lead policy develop Hilary Staver.

The ISO suggested options for policy reform, including updating CPM authority to accommodate the backstop based on an assessment of energy sufficiency and/or net peak needs.

“We’re looking to provide visibility into RA and non-RA resources in order to allow for efficient decision making in CAISO operations, obtaining capacity with the right attributes when and where it’s needed, and trying to be efficient and effective in our backstop approach,” Staver said.