RTO Insider

October 22, 2024

2 Huge Solar-plus-storage Projects Planned in California

Intersect Power is seeking approval for two 1.15 GW solar-plus-storage projects in California using a streamlined permitting process available through the California Energy Commission.

If built as planned, the projects individually would surpass in size the Edwards & Sanborn solar-plus-storage project that was completed in January in California’s Mojave Desert. That project’s 875 MW of solar capacity was the most of any facility in the United States, NASA reported in January. And its 3,287 MWh of storage made it the largest energy storage facility in the world.

The Perkins Renewable Energy Project, proposed by Intersect Power subsidiary IP Perkins LLC, would be a 1.15 GW solar facility in Imperial County. It also would include up to 1.15 GW of four-hour battery storage, or up to 4,600 MWh of storage.

The Darden Clean Energy Project would consist of a 1.15 GW solar facility and 1.15 GW of four-hour battery storage. Proposed by Intersect subsidiary IP Darden I LLC, the project would be built on about 9,500 acres in Fresno County in the state’s Central Valley region.

If completed, the two projects would put a sizable dent in California’s battery storage needs — projected to be 52 GW of storage capacity by 2045. The state announced recently it had hit a milestone of 13,391 MW of battery storage. (See California Hits Milestones for Batteries, DR Grid Support.)

Streamlined Approval Process

The Perkins and Darden proposals are seeking approval through the California Energy Commission’s opt-in certification process — a voluntary process intended to streamline permitting of renewable energy projects.

Under the opt-in process, the CEC becomes the lead agency for permitting and state environmental review. The CEC certificate is in lieu of any permit that normally would be required through the local land-use review process and most state permits.

The CEC has the authority to license thermal power plants of 50 MW or larger. Assembly Bill 205 of 2022 expanded the agency’s authority to include opt-in certification for renewable energy projects such as solar, onshore wind and energy storage systems.

The Perkins project, which will sit partially on federal land, also will receive federal permitting assistance through the FAST-41 program, officials announced Oct. 15. FAST-41 is an initiative to streamline permitting through a predictable and transparent process.

Unlocking Renewables

The Darden Renewable Energy Project was discussed Oct. 16 during an environmental scoping meeting hosted by the CEC. An Intersect Power representative said the project would be on retired agricultural land that is “highly disturbed” due to its past use.

And the project has the potential to unlock more solar development in the region. Development there has been slow due to a lack of interconnection opportunities, according to Intersect.

“The Darden project would create a vital new point of interconnection for future renewable energy generators in western Fresno County by building and transferring a new 500 kV switching station to PG&E,” the company said in a presentation.

The Perkins project also would create “a vital new point of interconnection for renewable energy” in the Imperial Valley for future projects as well as Perkins, according to the project application.

Although the Darden project previously included an 800 MW green hydrogen facility, that component was removed this month. Removal of the hydrogen facility reduces the project’s operational water demand from 1,039-acre-feet per year to 35 AFY.

Opt-in Timeline

Under the opt-in certification process, the CEC is required to post a draft environmental impact report within 150 days of the date the application is deemed complete, followed by 60 days for public comment. A final EIR is due within 270 days from the application completion date.

Other state agencies that retain permitting authority over the project, such as state water boards, must decide on the application by day 360.

The Darden and Perkins projects are two of six proposals under review under the CEC’s opt-in certification process.

The other opt-in projects are:

- Compass Energy Storage Project: A 250 MW battery storage system in the city of San Juan Capistrano.
- Fountain Wind Project: Up to 48 wind turbines, each with a capacity of up to 7.2 MW, in Shasta County.
- Potentia-Viridi Battery Energy Storage Project: A 400 MW battery storage system in eastern Alameda County providing up to 3,200 MWh of storage.
- Soda Mountain Solar Project: Up to 300 MW of solar and 300 MW of battery storage in San Bernardino County.

October 22, 2024

DOE Doubles Down on Advanced Nuclear with HALEU Contracts

With tech giants Google and Amazon turning to small modular reactors to power their megawatt-guzzling data centers, the U.S. Department of Energy is doubling down on its efforts to build out a domestic supply chain for the high-assay, low-enriched uranium (HALEU) these advanced reactors will need.

In a series of recent announcements, DOE awarded 10 contracts covering two of the key stages of the nuclear fuel production cycle ― enrichment and deconversion ― and released its final environmental impact statement (EIS) aimed at accelerating the development of such facilities.

The goal, according to the EIS, is to produce 290 metric tons — that’s 639,341 pounds — of HALEU over the next 10 years. Doing so by expanding existing enrichment and deconversion facilities could have the lowest level of environmental impacts, the EIS says.

Announced Oct. 17, four of the DOE contracts will help to expand HALEU enrichment capacity, while the other six contracts, for deconversion, were announced Oct. 8. Each of these companies will be negotiating with DOE for 10-year contracts for a minimum amount of $2 million, with additional billions in funding available for enrichment and deconversion services.

According to a DOE press release, the multiple awards will create “strong competition … allowing DOE to select the best fit for future work,” while building “a strong, reliable domestic nuclear fuel supply chain free of influence from adversarial foreign nations.”

The U.S. has a well-established supply chain for the low-enriched uranium (LEU) used in the country’s existing fleet of 95 light-water reactors, including two new units at the Vogtle nuclear power plant in Georgia, which came online this year.

Prior to Russia’s 2022 invasion of Ukraine, the U.S. was dependent on a single company in Russia for its supply of HALEU. Building out a domestic supply chain quickly became a bipartisan priority, and Congress passed a law prohibiting such uranium imports from Russia, which President Joe Biden signed in May.

The war in Ukraine, coupled with the boom in electricity demand driven by data centers, has created a “muscular resurgence” of interest in nuclear, National Climate Advisor Ali Zaidi said in a DOE press release on the enrichment contracts.

The four companies receiving the enrichment contracts are Louisiana Energy Services, Orano Federal Services, General Matter and American Centrifuge Operating (ACO).

Orano was also chosen for a deconversion contract, and ACO is a subsidiary of Centrus, another deconversion awardee. The other four on this list are BWX Technologies, Framatome, GE Vernova and Westinghouse.

Most of the companies have extensive experience as either developers of advanced reactors or suppliers of nuclear fuel and will be expanding existing facilities or, in the case of Orano, building new ones.

ACO has already been producing small amounts of HALEU under a DOE-funded demonstration project, while Orano recently announced its plans for building a state-of-the-art enrichment facility on a site owned by DOE in Oak Ridge, Tenn.

In a Centrus press release, CEO Amir Vexler said the enrichment contract will help the company expand its HALEU production capacity “so that we can restore a robust, American-owned uranium enrichment capability to power the future of nuclear energy.”

ACO’s own domestic supply chain for the equipment it will need for enrichment includes 14 U.S. suppliers in 13 states, the company said.

HALEU 101

Nuclear fuels are classified based on their concentrations of the “fissile” U-235 isotope used to trigger or maintain the nuclear reactions that produce energy. The concentration for LEU fuel is 3 to 5%, while for HALEU, it is 5 to 19.75%.

A higher concentration of fissile material means reactors fueled with HALEU can be smaller, with smaller fuel cores, but still produce high levels of energy. The fuel cores also will last longer ― requiring less refueling ― and the reactors can operate more efficiently and produce less radioactive spent fuel to be stored.

On the downside, the World Nuclear Association notes that the various parts of the HALEU fuel cycle will cost more and, in the U.S., will require separate licensing from the Nuclear Regulatory Commission.

The notes that it licensed the Centrus pilot program and has also licensed HALEU used by a Navy test reactor. The commission is also “actively reviewing license applications for fuel enrichment facilities and fuel fabrication facilities to produce and utilize HALEU.”

The nuclear fuel cycle starts with mined uranium, which contains less than 1% of the fissile U-235 isotope and more than 99% of the heavier, nonfissile U-238 isotope. The enrichment process runs mined and milled uranium, called yellowcake, through a series of centrifuges, which spin out the heavier U-238 isotopes, automatically increasing the concentrations of U-235.

Patrick White, research director of the Nuclear Innovation Alliance, noted that the extra processing to get from LEU concentrations of U-235 to the higher HALEU concentrations might require a relatively modest expansion of an existing facility.

The more concentrated uranium produced by enrichment is smaller in size, making further concentration easier, he said.

“The amount of enrichment facilities that you need for lower enrichment is going to be much greater than the amount of enrichment facilities you’re going to need to do higher enrichment because it’s a lot more work to do those initial steps of concentrating because you’re managing such a large volume of material,” White said.

“Essentially, it takes much less work to go from 5 to 20% [enrichment] than it does to go from natural uranium to 5%,” he said.

The enriched uranium, in the form of uranium hexafluoride (UF6), is then further processed, or deconverted, into one of two forms of uranium used in fuel cores, uranium oxide (UO2) or metallic uranium, in both cases via a chemical process.

Deconversion facilities for UO2 already exist for LEU production, but White said, they are not “rated for and compatible with HALEU, so they will need to develop new infrastructure for HALEU deconversion.”

TerraPower, which will use metallic uranium as fuel stock for its Natrium reactor, has partnered with Framatome to build a pilot plant for metallization, located at Framatome’s existing nuclear fuel plant in Richland, Wash.

Economies of Scale

But will the U.S. need 290 MT of HALEU over the next 10 years?

DOE’s Advanced Reactor Demonstration Program is funding the development of two advanced reactors ― TerraPower’s Natrium reactor and X-energy’s Xe-100 ― which will each need between 20 MT and 25 MT of HALEU per year, according to a department spokesperson.

But beyond these demonstrations, the power demand from hyperscale data centers running artificial intelligence could provide the market needed for broad commercialization.

On Oct. 14, Google and Kairos Power signed an agreement to develop a fleet of SMRs that will be able to provide 500 MW of power by 2035. Amazon’s investment in X-energy, announced Oct. 16, is aimed at putting 5 GW of new power on the grid by 2039.

In addition, DOE is now accepting applications for $900 million in funding for the development of first-of-a-kind SMRs that will generate a string of orders.

White sees the DOE contracts and other programs to create economies of scale for HALEU production and provide a buffer for any disconnect of supply and demand.

“How much material do we need to procure to actually make reasonable investments in production?” he asked. “One of the challenges with any of these systems, whether it’s the enrichment facilities or whether it’s the deconversion facilities, is that they really are subject to economies of scale. Producing one kilogram of HALEU costs a heck of a lot more on a per unit basis than producing one MT or 10 MT.”

October 22, 2024

ISO-NE Boosts Energy Adequacy Modeling Capabilities

ISO-NE is working to add to its probabilistic energy adequacy tool the capability to model preemptive actions to help conserve stored fuel prior to extreme winter weather events, ISO-NE representatives told the NEPOOL Reliability Committee (RC) on Oct. 22.

The probabilistic modeling framework, or PEAT, initially was developed in coordination with the Electric Power Research Institute for several long-duration shortfall risk evaluations in 2023. It now is being incorporated into ISO-NE’s energy assessments and would be the backbone of the RTO’s proposed Regional Energy Shortfall Threshold (REST).

REST is intended to quantify and determine an acceptable level of shortfall risk for the region, and eventually to inform the development of solutions when risks are identified. (See ISO-NE Details Proposal for Regional Energy Shortfall Threshold and NEPOOL Reliability/Transmission Committee Briefs: Aug. 13-14, 2024.)

ISO-NE plans to run REST analyses seasonally to evaluate near-term shortfall risks and over longer periods to better understand risk trends in the region.

The PEAT modeling is being improved to account for both preventive and corrective capacity deficiency actions, said Mike Knowland of ISO-NE. While the PEAT modeling already includes corrective actions, modeling preventive actions is a new addition.

“Incorporating both preventive and corrective actions directly into PEAT allows for a robust quantitative estimate of the impacts of these actions on shortfall amounts,” Knowland said, adding that the modeling will be able to isolate the effect of preemptive actions.

The preemptive modeling is intended to help the RTO optimally dispatch resources prior to and during extended periods of resource adequacy risk, which ISO-NE expects to increase as intermittent renewables proliferate.

Jinye Zhao of ISO-NE said the RTO also “has significantly enhanced PEAT to incorporate a multiday rolling-horizon economic dispatch for the 21-day energy assessment,” which looks out three days in advance on a rolling basis to optimize the dispatch of stored fuel resources.

“Based on system conditions and fuel availability in the future days, the model can decide the appropriate time to trigger preventive actions and allocate the appropriate amount as needed to alleviate an anticipated energy shortfall,” Zhao said.

In the new process, ISO-NE first will conduct its 21-day energy assessment using only modeling of corrective shortfall actions. Following the identification of an energy shortfall, the RTO will run the assessment again and include modeling of both preventive and corrective actions.

Net import relief and net conservation relief, which will be incorporated in both the preemptive and corrective PEAT modeling, each will be “modeled as a block of up to 500 MW,” Zhao said.

For the REST project, the modeling improvements could enable “a multimetric criteria which may include an additional metric that captures the duration of energy shortfall,” the RTO told stakeholders.

ISO-NE is scheduled to present its initial proposal on the REST at the RC in November. It has emphasized the need for stakeholder input on the level of acceptable shortfall risk for the region.

Determining an acceptable risk threshold will require more than just modeling expertise — it will pose political questions about how much the states are willing to pay for reliability insurance on the grid, and it could have a significant impact on regional programs supporting stored-fuel or dispatchable resources.

“Following establishment of the REST, a subsequent effort will evaluate if adherence to the REST requires development of specific regional solutions,” Knowland noted.

ISO-NE’s inventoried energy program (IEP), which compensates generators for keeping stored fuel on site during the winter, is set to expire after this winter. While the IEP was intended as a short-term solution, the RTO has not committed to either ending or continuing the program.

Presenting the results of the RTO’s Economic Planning for the Clean Energy Transition report at the Planning Advisory Committee meeting in August, Patrick Boughan of ISO-NE emphasized that new market enhancements may be needed in the long-term to support dispatchable resources as renewables proliferate. (See ISO-NE: New Mechanisms May be Needed to Ensure Future Grid Reliability.)

October 22, 2024

Attentive Withdraws NY Offshore Wind Proposals

Barely three months after it was launched, New York’s fifth offshore wind solicitation has its first casualty: Attentive Energy has withdrawn the 1,275 MW proposal it submitted this summer.

Attentive said it remained committed to offshore wind and to helping the region meet the environmental and economic goals that offshore wind is expected to benefit.

New York’s fifth solicitation (NY5) has turned into a near-repeat of NY3. (See NY OSW: If at First You Don’t Succeed, Try, Try Again.)

Attentive, Community Offshore Wind and Vineyard Offshore’s Excelsior Wind were awarded contingent contracts in NY3, but NY3 was canceled in April when GE Vernova halted development of the turbine that was key to those contracts. (See NY Offshore Wind Plans Implode Again.)

NY5 opened in July. The same three developers submitted proposals again, along with a new entrant: Ørsted’s Long Island Wind.

Their deadline to submit offer pricing for the combined 25 proposals was Oct. 18. On that date, Attentive withdrew its four proposals.

The New York State Energy Research and Development Authority expects to notify the three remaining bidders of contingent awards by Nov. 8 but will not disclose details publicly until the contracts are finalized, likely in the first quarter of 2025.

Attentive is a joint venture of TotalEnergies, Rise Light & Power and Corio Generation.

In a prepared statement Oct. 21, it said: “Attentive Energy commends the state’s steadfast support of offshore wind and will continue to evaluate market conditions and future opportunities as they arise.”

Attentive’s lease area is closer to New Jersey than to New York. It won a contract in NJ3 and has submitted a bid in NJ4. (See NJ Awards Contracts for 3.7 GW of OSW Projects and 3 OSW Proposals Submitted to NJ.)

In other offshore wind news along the East Coast:

No Federal Grant for Maine Port

The state of Maine did not get the $434 million U.S. Department of Transportation grant it sought to help build a port to support the floating offshore wind industry.

The state hopes to grow into a leader in floating wind, which relies on still-expensive and immature technology, but which is poised for growth, as most offshore areas are too deep for fixed-bottom turbines.

The first-ever Gulf of Maine wind lease auction is scheduled Oct. 29.

DOT on Oct. 21 announced 44 grants totaling more than $4.2 billion through the Bipartisan Infrastructure law. Among them were 18 large port projects, but Maine’s was not among them.

In a prepared statement, MaineDOT Commissioner Bruce Van Note responded:

“We knew the grant program would be extremely competitive and that our application was ambitious. We believe the result is a reflection of the fiercely competitive nature of this program and that it does not reflect, or undermine, the widely recognized need for this port, the strong merit of Maine’s plan, or the vast economic and environmental benefits associated with port development.”

Van Note added that the state still is awaiting word on another, smaller grant that would help cover the cost of designing and permitting the port.

The port has other hurdles to clear: The state’s preferred site is an island that is a nature preserve. (See Maine Chooses Nature Preserve for Floating Wind Port.)

Preservationists have vowed to fight the plan, and they have a long track record of successfully beating back other development proposals.

Cables for Leading Light

Hellenic Cables announced it has reached an agreement to supply 132-kV inter-array cables for the Leading Light Wind proposal off the New Jersey coast.

The Garden State chose the Leading Light plan for a contract in January as part of NJ3.

At 2,400 MW, it is one of the largest wind farm plans yet announced off the U.S. coast, but developers have run into a problem they must solve before they can put Hellenic’s 65 kilometers of submarine cable to use: They need wind turbine generators with a combination of output and cost that will render the project economically viable.

The New Jersey Board of Public Utilities in September granted the developer more time to shop for turbines, lest the project become financially untenable under terms negotiated with the state — the same fate that doomed many of the now-canceled contracts along the Northeast coast. (See New Jersey BPU Approves Invenergy Offshore Wind Delay.)

Leading Light Wind is a rarity in the still-young U.S. offshore wind industry — it is led by two American companies, Invenergy and energyRE.

A commercial and industrial ecosystem to support offshore wind energy development is growing in the United States, but the sector still has a heavy European component at this stage.

To wit: Fulgor will manufacture the cables in Corinth, Greece. Fulgor is a subsidiary of Hellenic Cables, headquartered in Athens. Hellenic is a subsidiary of Cenergy Holdings, based in Brussels. Cenergy is a subsidiary of Viohalco, originally of Greece but now of Brussels.

October 22, 2024

NY Project Alleviates Transmission Chokepoint

A major transmission project completed last year is already alleviating congestion on a historic chokepoint between upstate and downstate New York. On its blog, NYISO claims these upgrades, particularly to the Central East Interconnection, have paid dividends, reducing wind energy curtailments along the transmission corridor.

NYISO claims these are the most significant upgrades in 30 years, boosting the transfer capability by about 1,000 MW.

The Central East Interconnection slides through the hills of upstate New York along the relative smoothness of the Mohawk River. It forks, hooking into the rest of the grid at Schenectady and southward out of the river valley into New Scotland, a distant suburb of Albany.

“Albany was functionally downstate,” said Marguerite Wells, executive director of the Alliance for Clean Energy New York (ACE NY). “Even though nobody in Albany thinks they live downstate and nobody in New York City thinks that Albany is anything other than upstate.”

The bottleneck grew out of multiple historical trends, including the industrial development along the Mohawk River and the piecemeal creation of the power grid. The last time the corridor was updated was during the 1960s.

“The issue was that this whole corridor … they had old, existing 230-kV transmission lines as well as some old 345-kV lines,” said Girish Behal, vice president of projects and business development for the New York Power Authority. “These were old existing transmission lines in old existing corridors that over a period of time got utilized to a point where you couldn’t put more energy on it.”

Behal likened the upgrade to transforming a state road to an interstate highway, using the same right of way but upgrading the engineering specifications to allow more capacity.

A collage of images from the New York Power Authority showing initial construction of the Central East Interconnection transmission upgrades. | NYPA

“It increased the Central East interface thermal transfer limit by 350 MW and the voltage transfer limit by 875 MW — a significant amount of capacity on those transmission lines to move those electrons around,” he said.

About 93 miles of new lines were from new steel monopoles from Albany County to Oneida County, effectively quadrupling the power through the corridor.

Curbing Wind Curtailment

NYISO says the upgrades mean this chokepoint on the grid has opened. Wind curtailments, once a norm, have plummeted. In December 2023 in the early evening, the interface flow for Central East surpassed 3,000 MW for the first time since 2005.

Before the upgrade, the Capitol District was powered mostly by gas turbine plants. Much of the new power comes from renewable sources. According to NYISO, about 30% of the state’s installed wind capacity is in the Mohawk Valley.

In 2023, NYISO asked wind generators to turn off to the tune of 162 GWh because the grid could not handle the energy. Roughly 80% of those requests came in the first four months of 2023, before the upgrades to Central East were completed.

“It’s not incorrect for … NYISO to say that the Central East Interface improvement unbottles wind because it unbottles the whole state,” Wells said.

Wells explained that this particular upgrade helps the entire state move power more effectively. Because upstate has more renewable energy than downstate, this effectively unbottled wind without touching the transmission infrastructure that hooks directly to wind generation.

She said the next phase of upgrades to transmission would directly improve the lines that attach to wind generation, reducing curtailment even further.

A big step in a massive process

This is far from the only upgrade that’s necessary for New York’s energy transition. At the ACE NY fall conference, Bart Fernie, a vice president at National Grid, said some of the circuits in need of upgrades are over 100 years old.

“They were designed to basically import 100 MW. Now they’re being asked to export 1,000,” Fernie said in a panel on transmission infrastructure. “What we’ve come up with, supported by the state, is what we call the Upstate Upgrade. That’s 1,000 miles of rebuilding and modernizing upstate New York transmission.”

Schuyler Matteson, the clean energy planning lead for the New York Department of Public Service, echoed these comments.

“We live in a state that has some of the oldest electrical infrastructure in the world — not just the region, but in the world,” Matteson said. He ran through the preliminary results of the Coordinated Grid Planning Process, saying that to meet the state’s generation needs, the number of interconnections would have to triple. “Then we need to find ways to get those electrons to customers.”

Later in the panel discussion, Fernie and Matteson made it clear the 1,000 miles of new upgrades were just the beginning and not all of that would involve new transmission lines. They mentioned dynamic voltage support, grid-enhancing technologies and other avenues to make the best use of existing infrastructure and rights of ways.

In an interview with RTO Insider, Behal also emphasized the Central East Interconnection upgrade was far from the last upgrade needed. New York, as the birthplace of the electrical grid, has many sections in need of refurbishment.

“We have some transmission lines in upstate New York that were built in the 1940s,” Behal said. “It’s an antiquated system that now, with renewable generation coming in and trying to connect there’s a very significant need to upgrade those to a higher voltage or higher conductor size.”

October 22, 2024October 22, 2024

Company Briefs

Constellation Orders Transformer for Three Mile Island Restart

Constellation Energy has ordered a main power transformer for the Three Mile Island nuclear reactor it is attempting to restart in Pennsylvania.

The $100 million transformer is expected to be the biggest single piece of equipment that will need to be replaced.

Constellation is investing $1.6 billion to revive the operation over the next four years.

More: Reuters

Gevo Granted $1.46B Loan for Jet Fuel Plant

The Department of Energy last week granted a conditional loan guarantee worth $1.46 billion to Gevo, the Colorado company that aims to build the nation’s first ethanol-to-jet-fuel facility in South Dakota.

The Gevo project, called “Net-Zero 1,” would include a plant to produce ethanol exclusively for use in aviation fuel, using corn from farmers contracted to produce their crops using a set of climate-friendly practices. The ethanol would be transformed into jet fuel in a separate facility at the same site. 

The Gevo fuel would reduce annual carbon emissions by 600,000 metric tons a year, according to the DOE.

More: South Dakota Searchlight

Startup Lyten to Invest More than $1B in Lithium-sulfur Battery Factory

Silicon Valley startup Lyten last week announced that it plans to invest more than $1 billion to build the world’s first gigafactory for lithium-sulfur batteries in Reno, Nev.

Lyten, backed by Chrysler-parent Stellantis and delivery services provider FedEx, said its facility will produce up to 10 GWh of lithium-sulfur batteries annually at full scale. The first phase will start production in 2027.

More: Reuters, Reno Gazette Journal

October 22, 2024October 22, 2024

State Briefs

ALABAMA

Alabama Power Coal Plant Tops GHG Polluter List for 9th Straight Year

Alabama Power’s James H. Miller Jr. Electric Generating Plant was named the nation’s top greenhouse gas emitter for the ninth consecutive year, according to EPA data.

The plant released almost 16.6 million tons of greenhouse gas in 2023, the most of any single power plant, factory, refinery or other industrial facility in the country. That’s about 1.2 million tons more than the second-place emitter, Missouri’s Labadie Power Plant.

Power plants were the country’s largest source of greenhouse gases, with 1,320 plants releasing about 1.5 billion tons of CO2 equivalent, the EPA said.

More: Inside Climate News

ARIZONA

Corporation Commission Defends Exempting Plant from Environmental Review

The Corporation Commission has asked the Maricopa County Superior Court to dismiss complaints saying it misinterpreted a statute governing power plant expansions and reversed decades of precedent set by previous commission votes.

Attorney General Kris Mayes and two environmental groups sued the commission following its June decision to overturn a ruling from the Power Plant and Transmission Line Siting Committee that required Unisource Energy to obtain a Certificate of Environmental Compatibility for four new 50-MW generators at its Black Mountain Generating Station. Under state law, plants with a nameplate rating of 100 MW or more must obtain a certificate, but UNSE argued it should not have to obtain one since each individual generator is less than 100 MW.

A hearing has not been set in any of the lawsuits.

More: Arizona Capitol Times

HAWAII

PUC Probing Hawaiian Electric’s Role in Lahaina Wildfire

The Public Utilities Commission has issued more than 30 information requests to Hawaiian Electric as part of an ongoing investigation into the Aug. 8, 2023, Lahaina wildfire that killed 102 people and caused more than $5.5 billion in damage.

The PUC is reviewing the cause and origin report from the Maui Department of Fire and Public Safety and the Department of Justice’s Bureau of Alcohol Tobacco Firearms and Explosives that concluded the fire started when downed power lines reenergized in overgrown vegetation that violated county fire code.

The commission is also tracking and assisting how regulated utilities prevent and prepare for wildfires and other natural hazards.

More: Hawaii Tribune Herald

MINNESOTA

Minneapolis City Council Overrides Mayor’s Veto of Carbon Fee

The Minneapolis City Council last week voted 9-2 to override Mayor Jacob Frey’s veto of a fee on carbon emissions.

The council also voted to push back the fee’s start date seven months to July 1. It also directed the administration to do a fee study by May 1, giving the council time to adjust the fees.

Frey vetoed the measure two weeks ago, saying he supports the fee but that state law only allows the city to charge regulatory fees to recoup the costs of the program, so the city would have to hire staff, create the program and figure out how much it will cost to run the program before it could start charging polluters.

More: The Minnesota Star Tribune

PUC Orders Xcel Energy to Refund Customers for 2011 Sherco Outage Costs

The Minnesota Public Utilities Commission last week ordered Xcel Energy to refund customers for costs related to a failure at its Becker coal plant 13 years ago.

During the outage, Xcel had to buy replacement power and additional fuel from alternative sources. The PUC had held off determining whether the replacement costs were reasonable, but an administrative law judge recently found that Xcel’s failure to prudently operate and maintain Unit 3 contributed to the accident.

Xcel will refund customers about $58 million.

More: MPR News

MONTANA

PSC Rejects MDU Rate Increase

The Public Service Commission last week rejected a rate increase requested by Montana-Dakota Utilities.

Commissioners also denied an interim increase request for several reasons, including a lack of Consumer Counsel input and the cost burden put on residents.

However, the PSC may still grant the full increase ($8.68/month) after further review, according to a staff report. Three PSC seats are on the ballot this November, and winners will take office in 2025.

More: Daily Montanan

NEW YORK

RWE, National Grid Propose State’s Largest OSW Project

German utility RWE and New York utility National Grid last week announced a proposal for a joint offshore wind project.

The companies plan to build a 2.8 GW Community Offshore Wind farm off Long Island, the largest offshore wind power plan yet submitted to NYSERDA. It is the second time they have submitted the project for NYSERDA’s approval. The previous bid was awarded, then canceled when the economic viability of first-generation offshore wind projects soured.

Under the new proposal, Community Offshore Wind would come online in two phases in 2030 and 2032.

More: The Maritime Executive

TEXAS

CEQ Investigating Errors in Energy Transfer Pipeline Fire Report

The Commission on Environmental Quality announced it will investigate apparent gaps in Energy Transfer’s final pollution report following a Deer Park pipeline fire.

The pipeline fire raged for days, but Energy Transfer’s report, dated Oct. 3, stated that the full event lasted only 10 hours. The shortened duration could mean the company’s pollution estimates were incorrect.

The blaze erupted on Sept. 16 when an SUV veered off-course and struck a natural gas liquids pipeline valve. The fire released more than 37,000 barrels of y-grade natural gas liquids including a mixture of gases such as ethane, propane and butane.

More: Houston Chronicle

VERMONT

Burlington Electric Seeks to Buy Out City’s Wood-burning Plant

The Burlington Electric Department last week announced it was entering into negotiations to take over full ownership of the McNeil Generating Station, the state’s largest single producer of power.

The biomass-burning plant is currently under split ownership — Burlington Electric Department owns 50%, Green Mountain Power owns 31%, and the Vermont Public Power Supply Authority owns 19%. But the joint owners agreed this month to negotiate a potential sale that could give the city full ownership of the plant.

More: VTDigger

WISCONSIN

Superior Gas Plant Withdraws Permit Request

The owners of the proposed Nemadji Trail Energy Center are moving to withdraw requests for an air permit for the facility, leaving the facility’s future in limbo.

If the withdrawal is finalized by the Department of Natural Resources, the $700 million methane gas plant would be required to go through an entirely new permitting and review process. The development has forced companies with a stake in NTEC’s construction to reevaluate the project.

“Due to the extended timeline of the federal permit process, the Nemadji Trail Energy Center partners have requested that the [Wisconsin DNR] revoke the facility’s air permit,” said Dairyland Power Cooperative spokesperson Katie Thomson. “This is a timing issue. The window of time to construct and commission the facility allowed in the air permit is no longer achievable.”

More: Wisconsin Examiner

October 22, 2024October 22, 2024

Federal Briefs

Court Pauses TVA Pipeline Permits Amid Legal Battle

The 6th U.S. Circuit Court of Appeals issued a 2-1 spilt decision to temporarily halt two permits needed to begin construction on a pipeline that will supply a Tennessee Valley Authority natural gas plant.

The decision prevents Tennessee Gas Pipeline Company from starting to build its 32-mile pipeline through Dickson, Houston and Stewart counties that will feed TVA’s combined-cycle natural gas facility at the site of the coal-fired Cumberland Fossil Plant.

The Southern Environmental Law Center and Appalachian Mountain Advocates asked the appeals court in August 2023 to reconsider a water quality permit issued by the Department of Environment and Conservation. In the ruling, Judges Eric Clay and Karen Moore said the groups risk irreparable harm if construction begins before the judges decide their case.

More: The Associated Press

Enviro Groups Sue TVA, Alleging New Kingston Gas Plant Was Chosen Illegally

The Southern Environmental Law Center sued the Tennessee Valley Authority on behalf of multiple environmental groups who assert the federal utility violated planning laws by committing to replace the Kingston coal plant with a gas plant before studying alternatives or seeking public feedback.

The lawsuit asserts TVA spent millions on the gas plant through agreements with pipeline operator Enbridge and GE before it studied negative environmental effects or renewable energy alternatives. The plaintiffs have asked the court to reverse TVA’s decision, force it to prepare a new environmental impact study, halt construction of the plant and comply with environmental planning law.

More: Knoxville News Sentinel

Chemical Safety Board Launches Investigation Following Deadly Hydrogen Sulfide Leak

The U.S. Chemical Safety and Hazard Investigation Board announced it will investigate a hydrogen sulfide leak that killed two people at Pemex’s Deer Park plant in Texas.

The leak, which also left 13 people hospitalized and injured at least 35 people, began Oct. 10 and prompted shelter-in-place warnings for the cities of Deer Park and Pasadena. Deer Park Pemex officials confirmed in a Community Awareness and Emergency Response alert that they had released the gas at around 4:40 p.m. but said it was contained to their facility. It wasn’t until around 7 p.m. that the city issued the warning.

Deer Park and Harris County officials said Pemex failed to use the CAER system as intended to keep people surrounding the facility informed.

More: Houston Chronicle

BLM Approves Cape Geothermal Project

The Bureau of Land Management last week issued a decision record approving the Cape Geothermal Power Project in southwest Utah.

The project, proposed by Houston-based Fervo Energy, will generate 2 GW.

The BLM has approved 14 geothermal power projects on federal lands, nine of them in Nevada, since President Joe Biden took office in January 2021.

More: BLM

October 21, 2024October 22, 2024

SPP Markets & Operations Policy Committee Briefs: Oct. 15-16, 2024

LITTLE ROCK, Ark. — SPP says it is devoting significant resources to finally resolve Attachment Z2, a bone of contention among SPP stakeholders since 2016, by the end of this decade.

General Counsel Paul Suskie told the Markets and Operations Policy Committee on Oct. 15 that it will take 24,000 hours of staff time and nearly $2 million to finally resettle Z2 refunds and resettlements following a pivot by FERC in ordering SPP to reverse its previously approved invoicing process.

“Think through this: It took us from 2008 to 2016 to create the Z2 process. Now we have to undo it and recreate it and resettle going back to 2015,” Suskie told MOPC. “Luckily, we have a lot of knowledge and expertise and processes that will make that easier than it was to create it, but it is a significant undertaking that will probably take until 2029 to complete.”

Under Attachment Z2, transmission upgrade sponsors receive credits from any upgrade users whose service could not be provided “but for” the upgrade. The attachment also requires the RTO to invoice the charges monthly and to make any adjustments within one year.

However, software problems delayed the attachment’s final implementation for eight years before 2016, during which the RTO did not invoice for the upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

By then, SPP already back-billed market participants $138 million, not including interest, in 2016 and continued to use Z2 credits at the same time. It has applied $503 million in Z2 credits since 2015.

“Because this is a process [where] each payment impacts other payments, what we’re doing today is in error because FERC reversed what they did from 2008 to 2015,” Suskie said, noting it will require recalculating each operating day since September 2015 to undo and refund the historical settlement.

Several members filed Section 206 complaints against SPP over the Z2 resettlements. In 2022, the grid operator filed an update to its proposed refund plan from 2019. It urged FERC not to order refunds until all litigation is final. (See 8th Circuit Denies Review of FERC Orders on SPP Attachment Z2.)

SPP’s Michael Desselle, who is retiring, is given a standing ovation by the Strategic Planning Committee. | © RTO Insider LLC

Suskie said the commission has been clear that the RTO is not to process refunds without a FERC order. Left in limbo are individual refunds totaling $147 million, plus $33.4 million in interest, due to transmission customers from 2008 to 2015.

SPP is developing an interim software solution to calculate and distribute resettlements on activity from September 2015 until the production system can be used. It expects to have resettlements in sync with routine monthly settlements by 2029. That will require unwinding more than $20 billion in previous settlements to resettle Z2 activity; only 1 to 2% of all resettlements will be related to Z2, staff said.

SPP emailed estimates of the refunds owed and/or that will be received after the MOPC meeting. The grid operator has created a Z2 website and is building an email distribution list to keep stakeholders updated.

SPP Modifies GI Backlog Process

SPP has modified its approach to clearing the backlog in its generator interconnection queue that dates back to 2018, revising the methodology to improve the accuracy of studies and restudies.

“That just made more sense and provided more accurate results at the time than when we filed [at FERC] for the backlog plan,” SPP’s Jennifer Swierczek said. “We realized that doing that many clusters at once, customers might not have all the information they needed to proceed to the facility study and the [generator interconnection agreement],”

The grid operator has added a planned restudy after each cluster’s first two definitive interconnection system impact studies (DISIS). A facility study and the execution of the GIA follow the restudy.

The backlog initially included four clusters, from 2018 through 2021. SPP planned to keep the 2022 window open “so the line didn’t get longer behind us,” Swierczek said, but a record number of requests forced the RTO to shut down the cluster and add it to the backlog. The same thing happened in 2023 when its 129 requests exceeded those of the previous year’s 108.

The 2024 cluster will be handled under the RTO’s normal process, but the grid operator has requested a waiver from FERC to extend the 2024 cluster study’s close from Oct. 31 to March 1, 2024.

SPP began tackling the backlog in 2022 with the 2018 cluster. The queue contained 1,139 active requests for 221 GW of capacity at the time; it now has 395 active requests for 82 GW of capacity. The RTO has executed 48 new GIAs for 7.75 GW of capacity during the backlog work.

Swierczek said the 2017 cluster, which is not part of the backlog, and the first 2018 study group have 91 projects between them, most of which she said are healthy. Large numbers of withdrawals in other clusters will have to be addressed in their next DISIS phase, with all backlog clusters ready for restudies by next summer, she said.

Separately, members approved a proposed revision (RR651) to the GI manual allowing upgrades approved mid-DISIS study from other planning processes to be considered as potential mitigations for constraints identified during the ongoing study. SPP says constraint mitigations identified in the study process will be provided by solutions that have been approved and reduce the need for restudies due to withdrawals.

New MOPC Leadership, Members

The meeting was the last for ITC Holdings’ Alan Myers after two years as MOPC chair.

“He’s done a great job over the last two years, and I’m looking forward to see what he has to close this out with,” said Lanny Nickell, Myers’ staff secretary.

“It has truly been my privilege to lead this group for two years,” Myers said after a round of applause, thanking members for their recognition. Then, true to his nature, he said, “Let’s dive in.”

Omaha Public Power District’s Joe Lang will assume the chairmanship in January.

MOPC added two new members: Ozarks Electric Cooperative’s Derrick Redfearn and Viridon Southwest’s Neeya Toleman. A Blackstone company, Viridon develops transmission projects in SPP.

Curing LREs’ RAR Deficiencies

Members easily endorsed three revision requests in separate votes.

The Supply Adequacy Working Group’s proposal (RR632) giving load-responsible entities several more weeks to address deficiencies in meeting their resource adequacy requirement. LREs would have from March 15 to May 15 (an additional 30 days) to cure summer season deficiencies and from Sept. 15 to Nov. 15 (15 extra days) to resolve winter season deficiencies.

SAWG’s vote to delay a revision request (RR642) until SPP completes its load-hosting capacity tool (LHCT) next year, giving applicable transmission owners three months to review the tool’s data. SAWG is working to implement the Holistic Integrated Tariff Teams’ directive to modify Attachment AQ of the tariff so SPP can proactively perform analysis to determine how much load can be accommodated at each node on the system without incremental investment (load hosting capacity assessment).

The Market Working Group’s recommendation (RR638) to remove the exemption for day-ahead reliability unit commitment self-commits. It said the removal will mitigate market manipulation by resources intentionally switching between “self” status and “market” status to increase their make-whole payments and help the market reach a more economical solution with more accurate information.

MOPC’s consent agenda included SPP’s annual violation relaxation limit analysis; the Project Cost Working Group’s in-service date delay report; the 2025 Integrated Transmission Planning assessment scope; and nine RRs that, if approved by the Board of Directors, would:

- RR545: Add language clarifying the objectives and initiation of a high-priority study and provide additional flexibility when developing the scope by removing the requirement to perform economic analysis and expanding on the current requirement to only conform to the ITP Planning Manual’s requirements.

- RR630: Add Tri-State Generation and Transmission’s various zones in the Western Interconnection to zones that will be a part of the SPP West Region.

- RR641: Clarify that self-committing resources contributing to the make-whole payment distribution volume is not only referring to energy storage resources but to all resource types.

- RR644: Remove expired or terminated grandfathered agreements from the list of GFAs and update any termination dates or any changes in buying or selling parties as part of the annual update.

- RR645: Update the ITP manual by considering aging infrastructure in transmission planning solutions by accounting for avoided or deferred reliability transmission facilities and aging infrastructure replacement.

- RR646: Update the ITP manual’s contingency screening criteria in the constraint assessment from 25% loading to 10% loading for 200-kV and above systems.

- RR647: Increase the cap under Schedule 1-A (Recoverable Costs) from $0.465/MWh to $0.515/MWh.

- RR648: Remove the regulation-up and regulation-down mileage factors from the applicable mitigated offer calculation and clarify terminology to match the supporting calculation for uncompensated costs for offline uncertainty.

- RR649: Add value to the network resource interconnection service (NRIS) product by creating an expedited process for designating new network and designated resources outside of the aggregate transmission service study process. It also would revise the generator interconnection study process for new NRIS requests, define deliverability areas and allow existing resources that meet eligibility requirements to use the expedited process.

October 21, 2024

Agencies Describe a Year of Iran Cyber Attacks

Cyber actors backed by Iran have been attacking critical infrastructure providers in the U.S. and other countries for more than a year, hitting sectors including energy, government and information technology, intelligence agencies from multiple countries said.

The warning about Iranian cyber activities came in an advisory released Oct. 16 by the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and endorsed by the FBI, the National Security Agency and their counterparts in Canada and Australia. The agencies described tactics that the Iran-supported actors have used since October 2023, as observed in “FBI engagements with entities impacted by” the attacks.

Several approaches are documented in the report. Attackers gain initial access to target networks through brute force techniques such as password spraying, in which they use the same password against many different user accounts. If the user account has multi-factor authentication enabled, the attacker will bypass the safeguard by “push bombing” the account, hitting the user with multiple MFA notifications until they approve the request by accident or stop notifications.

Once they have entered the network, attackers often register MFA in their names to protect their access. The agencies observed two cases in which intruders took over an account with uncompleted MFA registration and set it to their own devices.

Discovering the attackers’ presence in a compromised system can be difficult because they make use of living off the land techniques to blend in with normal system activities. Cyber experts have seen these techniques used increasingly by actors linked to China — particularly the Volt Typhoon group — to infiltrate U.S. critical infrastructure organizations. (See China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn.)

The agencies recommended reviewing authentication logs for multiple failed login attempts to valid accounts. To detect the use of compromised credentials, agencies said entities could look for a single IP address being used for multiple accounts, or cases of “impossible travel” when a single account shows logins from multiple IP addresses with significant geographic distances.

Mitigations include disabling user accounts and system access for departed staff, continuously reviewing MFA settings to ensure all active internet-facing protocols are covered and ensuring password policies align with relevant guidelines from the National Institute of Standards and Technology. The advisory also recommended that software manufacturers incorporate security by design principles to protect against actors using compromised credentials.

CISA and the other agencies said it is likely the Iranian actors’ goal is “to obtain credentials and information … that can then be sold to enable access to cybercriminals.” They did not indicate that they believe these particular attackers aim to disrupt the critical infrastructure providers themselves.

However, Iran has a longstanding place in U.S. security experts’ minds. The country’s history of “aggressive cyber operations” earned it an entry in the Director of National Intelligence’s 2024 Annual Threat Assessment, which noted that “Iran is willing to target countries with stronger cyber capabilities than itself.”

While many of Iran’s cyber operations are aimed at Israel and other rivals in the Middle East, the DNI observed that it has targeted the U.S. in the past. In 2020, cyber actors linked with Iran tried to interfere in the U.S. presidential election by attempting to obtain voter information, sending threatening emails to voters and spreading disinformation. The director said they may attempt to do so again in 2024.