CenterPoint said respondents are encouraged to submit proposals that include utility-scale solar, wind and storage projects (standalone or paired), along with thermal generation, load-modifying resources, demand-side resources and other innovative solutions

“This RFP allows us to explore a wide range of technologies that can contribute to our long-term generation strategy,” said Shane Bradford, CenterPoint’s Vice President for Indiana Electric.

Proposals are due October 8, 2024, the company said.

Last year CenterPoint released its resource plan for Indiana, calling to reduce carbon emissions from its generation fleet by more than 95% over the next 20 years. This would include ending its use of Indiana coal by 2027.

At the time, the company said by 2030, it expected more than 80% of CenterPoint Energy’s electricity to be generated by solar and wind, with the rest provided by natural gas.

The assessment focuses on the viability of the council’s 2021 Power Plan resource strategy and finds implementing it — specifically achieving energy efficiency consistent with the high end of the council’s target, pursuing renewable deployment of around 6,600 MW by 2029, and ensuring sufficient balancing resources and demand response — will provide for an adequate system.

That analysis comes with a caveat, however. Pursuing the low end of the council’s energy efficiency target would not provide for an adequate system, and if data center load growth accelerates and more closely aligns with utility projections in the region by 2029, the resource strategy will be insufficient, indicates the report.

The council uses an adequacy model called GENESYS to simulate the region’s bulk power system. In each simulation (which represents one year), a simulated shortfall event occurs over a time period when load cannot be served by resources in the model. Each modeled shortfall signals that emergency measures are necessary to avoid a blackout, like expensive cost resources not in an active utility portfolio, high-priced market purchases above normal import limit (such as those that occurred during January 2024’s winter storm event), calls for conservation by government officials (as in September 2022 California heatwave), or curtailment of fish and wildlife hydro operations (as happened during the 2001 Energy Crisis).

The assessment accounts for system changes that will be implemented by 2029, including load growth, in-region resource developments, and out-of-region market fundamentals. Electric load is expected to substantially increase by 2029, thanks to data centers and electric vehicles. However, announced changes to thermal plant retirements, such as Valmy 1 & 2 and Jim Bridger 1 & 2 conversions from coal to gas fueling, and anticipated transmission expansion throughout the WECC, including Boardman-to-Hemingway in the region, appear to alleviate some of the challenges associated with the increased loads when coupled with the 2021 Plan’s resource strategy.

The Pacific Northwest’s hydroelectric system provides more than half the grid’s nameplate capacity. The region has historically had an excess of peaking capacity but continues to be limited by the water supply that powers the hydroelectric system. Due to significant increases in variable energy resources, changes in hydroelectric operating constraints, and other added complexities, the region can no longer assume that it has sufficient capacity to meet all demand; thus, it is important to include a metric to protect against excessively high-capacity shortfalls, argues the report.

From an adequacy perspective, while hydropower is slightly reduced, based on the limited subset of studies used for a comparative study, the changes do not lead to a significantly different regional adequacy result. Offsetting the reduced hydropower is a small increase in regional thermal generation and market reliance, yet within the market reliance limit, throughout most of the year, especially at night.

The 2021 Power Plan’s resource strategy recommends that between 750 and 1,000 average MW of cost-effective energy efficiency, at least 3,500 MW of renewable resources, and 720 MW of low-cost and frequently deployable demand response be acquired, as well as increasing balancing up reserve requirements to 6,000 MW to respond to growing short-term uncertainty in variable energy resources (primarily wind and solar) by 2027.

The report acknowledges other changes to the regional power system that are important to consider since the 2027 assessment, including announced thermal retirement changes of coal-to-gas conversion, expanded transmission capacity, and hydro changes from the Resilient Columbia Basin Agreement to the Lower Snake and Lower Columbia projects.

The funding would support technologies that capture CO2 from industrial and power generation or directly from the atmosphere and transport it either for permanent geologic storage or conversion into valuable products such as fuels and chemicals.

The sixth opening of FECM’s Carbon Management funding opportunity announcement (FOA) will support the following areas of interest:

• Reactive carbon capture approaches for point source capture or atmospheric capture with integrated conversion to useful products. Reactive carbon capture is the integration of carbon capture with conversion to a product. This area of interest would focus on conceptual design studies followed by laboratory validation of reactive CO2 capture approaches from exhaust flue gas streams at electric generation and industrial facilities or from the atmosphere, with conversion of the CO2 into environmentally responsible and economically valuable products.
   
• Engineering-scale testing of transformational carbon capture technologies for natural gas combined cycle (NGCC) power plants. Testing under real flue gas conditions aims to achieve 95 percent or greater carbon capture efficiency and 95 percent CO2 purity, while demonstrating significant progress toward a 30 percent reduction in the cost of capture.
   
• Engineering-scale testing of transformational carbon capture technologies in portable systems at industrial plants. Development and testing of portable systems for transformational technologies would be conducted at a variety of sites, including oil refineries and petrochemical, cement and lime, pulp, steel and iron, and glass plants.
   
• Preliminary front-end engineering design (Pre-FEED) studies for carbon capture systems at existing (retrofit) domestic NGCC power plants. Pre-FEED studies of commercial-scale, advanced carbon capture systems at existing NGCC power plants or combined heat and power facilities that employ NGCC power generation.
   
• Pre-FEED studies for carbon capture systems at hydrogen production facilities using coal, mixed coal/biomass or natural gas feedstock. Studies to advance commercial-scale carbon capture systems that separate CO2 with at least 95 percent capture efficiency at new or existing hydrogen production facilities using coal, mixed coal/biomass/municipal solid waste/unrecyclable plastics, or natural gas feedstocks.
   
• Enhancing CO2 transport infrastructure (ECO2 transport): Pre-FEED studies for multimodal CO2 transfer facilities. Studies that support the development of viable and strategically adaptable multimodal transportation infrastructure capable of transferring CO2 across regional and national CO2 transportation networks.

Aypa Power intends to develop, own, and operate a 150 MW/600 MWh battery storage facility in Kuna, Idaho just outside the capital of Boise. Aypa’s secured financing package includes a $233 million green loan, including a construction and term loan, a tax equity bridge loan, and a letter of credit facility. Additionally, the project secured $90 million in tax equity, bringing the total financing to $323 million. The company secured a 20-year agreement with Idaho Power last year and hopes to bring it online in 2025.

Renewable Energy World asked Aypa Power to see if the Idaho battery storage project requires any additional state or local approval and is awaiting a response. It’s a natural question for any clean energy project proposed in Idaho given a recent trend of local opposition.

Kuna residents recently came out in force against the 2,385-acre Powers Butte Energy Center solar project developed by Savion, Idaho News 6 reports. The proposed solar farm would be located in a rural farming area, much to the annoyance of the opposition, who say the farm would be a blight on the surrounding area.

Kuna residents attended the second public hearing on the Powers Butte Energy Center project, but Ada County Commissioners did not make a decision on the project’s future. By the end of the month, the Ada County Commission moved to halt on the project, BoiseDev reports, citing public opposition and their own feelings in their decision. Commissioners said the project would come with environmental concerns and unfavorable views.

Ryan Davidson, an Ada County Commissioner, called the decision “tough” and said the board he serves on is “not anti-solar.” He said the commission previously approved a Savion solar project that was developed “out in the desert,” instead of near residents.

It’s not just solar that faces an uphill battle in Idaho: a controversial wind project is facing another obstacle after Sen. Jim Risch introduced legislation to delay the 1,000 MW Lava Ridge Wind project, which is located on federal land near the Minidoka National Historic Site. The project’s opponents claim that the wind farm will “visually compromise” the historic site honoring more than 13,000 Japanese-Americans who were incarcerated during World War II.

Opposition to the Lava Ridge Wind project led the Bureau of Land Management to suggest nearly halving the size of the project from 400 turbines to 241 as part of the “preferred alternative” plan. Idaho’s state legislature unanimously passed a resolution in March 2023 expressing opposition to the Lava Ridge Wind Energy Project.

Based on local reporting, Idaho residents haven’t appeared to have objected to any battery storage project, though Aypa’s would be the state’s first utility-scale facility.

Idaho Power, the investor-owned utility providing electricity to most of the state, sees energy storage serving a key role in the future. Last year, the utility laid out a plan to acquire 101 MW of energy storage to address potential capacity shortfalls driven by limited third-party transmission capacity, load growth, and declining peak performance from several resources, NewsData reports. Some of that load growth will come from a Meta data center that’s expected to be completed in 2025.

While opponents of wind and solar — referred to unaffectionately as “NIMBYs,” an acronym for Not in My Backyard — have successfully fought projects across the country, the majority of Americas don’t mind living near clean energy projects, according to polling data.

A Washington Post-University of Maryland poll found around 75% of Americans are comfortable living near solar projects. Wind projects faired slightly worse at 70%. The poll did not ask about energy storage projects.

Despite broad support for clean energy projects in the U.S., at least 15% of counties have “halted new utility-scale wind, solar, or both,” according to a USA Today report, by implementing “outright bans, moratoriums, construction impediments, and other conditions.”

In their respective second-quarter earnings reports, NRG Energy and Vistra discussed potential opportunities for data center co-location.

NRG’s 21 generating sites are “ideally suited for new large loads and power plant development, offering co-location opportunities both behind and in front of the meter,” said NRG President and CEO Larry Coben on the company’s earnings call Thursday.

Coben said NRG’s facilities would be attractive to data center developers for their access to water for cooling, premium fiber channel access for low latency and existing grid access for rapid market entry. NRG’s fleet includes a mix of natural gas, renewables and coal.

“We were getting lots of people sort of throwing us bids for our sites,” Coben told investors.

He continued: “We know they think we’re just a bunch of power guys who don’t know anything about data centers. So, if that’s what they’re bidding us, we really need to look at this, because it means there’s a lot more value in there than the bids that we’re receiving.”

Regarding discussions with data center providers and any potential co-location deals, Coben said NRG was working on a strategy and would release more details later in 2024.

The concept of large loads co-locating with generation continues to draw interest. The most-watched proposal would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in Pennsylvania.

Multiple utilities protested the proposed Talen Interconnection Service Agreement (ISA), prompting FERC to call for a technical conference in the fall to discuss the larger issue of co-location.

For Vistra, the pending Talen case or upcoming FERC technical conference “has not slowed the conversation down” on potential data center co-location deals, said company President and CEO Jim Burke.

“We’re in due diligence for a number of sites,” Burke told investors on the company’s Q2 call. “This is a really big opportunity for our industry to meet customer needs.”

Vistra reiterated the company can provide data centers the speed to market advantage since there wouldn’t be the same level of buildout needed on the transmission side.

“I think there’s going to be plenty of data center load behind-the-meter or co-located, and also front of the meter,” Burke said.

On planning for load growth and building new gas plants

The industry’s rapid load growth is being driven by data centers, electrification and new manufacturing. This is compounded by the retirement of fossil-fired plants. As a result, both NRG and Vistra see emerging supply gaps and tightening markets.

Among the regions expected to experience a surge in demand, ERCOT’s current long-term load forecast shows peak demand increasing from 86 GW in 2024 to 137 GW in 2028. This load growth will require significant planning and construction of new generation and transmission.

While NRG and Vistra operate plants outside of Texas, most of their growth is taking place in the ERCOT market. Both companies are taking advantage of the Texas Energy Fund (TEF), a government low-interest loan program used to incentivize the development of more dispatchable generation and smaller backup power in the state.

NRG has filed TEF loan applications for three separate projects, totaling more than 1,500 MW of capacity. Thee company would begin construction on two of the three facilities as early as October of this year.

One of these projects is a new 689 MW natural gas combined-cycle unit with Mitsubishi Power M501JAC equipment, located at NRG’s Cedar Bayou plant in Baytown, Texas. The target completion date would be late-2027.

The 415 MW simple-cycle unit at TH Wharton would include Siemens Energy’s SGT6-5000F equipment and could come online by mid-2026.

Finally, the 443 MW simple-cycle unit at Greens Bayou would be powered by a GE 7HA.03 turbine and could be finished by mid-2028.

“We believe our projects are well-situated for a timely approval, given their shovel-ready nature and the completeness of the applications that we submitted,” said Coben.

Texas Lt. Gov. Dan Patrick recently said 81 applicants representing over 41 GW of dispatchable power had applied through the fund, as of May 31. Patrick said the state planned on expanding the program during the next legislative session.

Coben told investors NRG could apply for more loan funding in a potential second TEF round, but also noted the challenge of multi-year lead times for turbines and other equipment.

“If you don’t have a place in the turbine queue today, there’s no way you’re getting a new project online before 2030, at the earliest,” he said.

In May, Vistra announced plans to add up to 2,000 MW of natural gas-fired capacity in West, Central and North Texas.

860 MW of simple-cycle peaker plants would support West Texas, including the state’s growing oil and gas industry. The company is seeing multiple demand drivers, including data centers and the electrification of oil field operations, specifically the Permian Basin of West Texas

Vistra would also convert its coal-fired Coleto Creek plant near Goliad to natural gas after the plant retires in 2027. Repowering would enable up to 600 MW of gas-fired capacity.

Also included are 500 MW of augmentations at existing facilities, nearly half of which are already finished, Burke said on the Q2 earnings call.

In its quarterly report, Vistra leadership noted the industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment needed for the construction of renewables projects. As a result, Vistra has deferred some of planned capital spend for these projects, the company said in its 10-Q filing.

The company did announce two long-term power purchase agreements (PPAs) with Amazon and Microsoft for two new large-scale solar facilities.

Supply chain disruptions have also increased the lead times to procure certain materials necessary to maintain Vistra’s natural gas, nuclear and coal fleet, according to the filing.

“We have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages,” the company reported.

In its Q2 report, NRG said procuring mid to long-term generation through PPAs continues to be part of its strategy. The company has entered into renewable PPAs totaling nearly 1.9 GW with third-party developers, all of which were operational as of July 31.

Constellation, which operates the largest nuclear fleet in the U.S., is working with data center customers on potential co-location deals, Dominguez said during the company’s second-quarter earnings call this week.

Data centers project to be significant drivers of growth in electricity demand. According to a study recently released by EPRI, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used.

“The simple fact is that data centers are coming, and they’re essential to America’s national security and economic competitiveness,” said Dominguez.

The rapidly growing data center industry has sparked an active and even divisive discussion among policymakers and stakeholders about how to powering them.

Notably, Exelon and American Electric Power (AEP) are protesting a proposal that would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in northeast Pennsylvania.

In a filing to the Federal Energy Regulatory Commission (FERC) last month, the parties said the proposed Interconnection Service Agreement (ISA) raises unresolved questions and could result in unfair cost burdens on ratepayers and negatively impact market operations and reliability.

FERC is now seeking more information about the amended ISA. Last week the federal agency called for a technical conference in the fall to discuss co-locating large loads like data centers with generators.

Constellation (a former Exelon entity) believes co-location allows significant new load to be served without requiring expensive system upgrades, especially when grid operators are struggling to integrate new resources faster.

“Friday’s actions at FERC may have slowed things, but ultimately will be constructive in our view,” said Dominguez on the investor call. “We think the benefits [of co-location] are compelling.”

In terms of any co-location deals of its own, Dominguez said Constellation wouldn’t be timebound by any FERC rulemaking on the Talen ISA. He did acknowledge a tightening in the market and more urgency for participants to lock up supply.

“We independently are working on contractual provisions that will allow us to manage whatever outcome comes out of those proceedings,” he said.

Dominguez noted PJM Interconnection’s latest capacity auction, which saw energy prices skyrocket more than 800%. Insufficient future transmission planning, the retirement of fossil-fired generation, long interconnection queues and the implementation of FERC market reforms are all contributing to the hikes.

The auction sends a build signal to generators, but Dominguez said nuclear power specifically could emerge a winner from PJM’s skyrocketing prices. Constellation operates eight nuclear plants (16 reactors) in PJM territory.

“We expect to see higher sustained pricing for capacity to address reliability needs and send more accurate price signals to retain, operate and relicense our plants,” he said.

Meanwhile, PJM utilities have now identified at least 50 GW of expected data center load growth, Dominguez reported.

He said despite disagreement on the vehicle to power data centers, there is a great opportunity for Constellation to work with utilities to bring both grid-connected and co-located projects along.

“We’re still fairly early innings in terms of understanding all of the different use cases and how our resources will interact with the grid,” he said.

It’s the latest scrutiny CenterPoint has faced following the storm. During a Texas Senate special committee meeting this week, there were many questions about the utility’s $800 million purchase of massive, more expensive generators rather than mobile generators as intended by state law.

That legislation – SB 1075 and HB 1500 from the 88^th Texas Legislative Session – allowed utilities like CenterPoint to lease small mobile generators to quickly get power to hospitals, vulnerable populations and cooling or warming centers.

Patrick said the massive, more expensive generators purchased by CenterPoint could not be used in nearly all emergencies but allowed them to make a huge profit. He said CenterPoint testified they would make at least $30 million in profits off the backs of ratepayers.

“CenterPoint violated the spirit and purpose of the legislation by leasing generators that are not truly mobile and, as they testified, have never been deployed for an emergency,” said Patrick.

He added: “Since CenterPoint pursued profit over effectiveness, they actually had to borrow small mobile generators from those companies for Hurricane Beryl.”

The Public Utility Commission of Texas (PUC) previously approved reimbursing the $800 million to CenterPoint over time through ratepayer increases. Patrick said he would write a letter to the PUC urging them to revoke their decision to grant CenterPoint’s request for reimbursement through ratepayers.

“Call it potential fraud, deceptive practices, poor money management, or whatever you wish; CenterPoint purposely violated the intent of the legislation to make a profit while not helping their customers during a crisis,” Patrick said.

PJM Interconnection, the largest electrical grid operator in the United States, held its annual power market auction Tuesday, and the results are staggering.

The auction produced a price of $269.92/MW-day for most of the PJM footprint, compared to $28.92/MW-day for the 2024/2025 auction. Capacity auction prices fluctuate annually based on the need for investment in generation resources, but a more than 800% increase will have a massive ripple effect across PJM’s 13-state footprint.

“PJM’s capacity auction has competitively secured resources to meet the RTO reliability requirement for the 2025/2026 Delivery Year,” reads PJM’s press release. That is a true statement, I suppose.

The auction secured 135,684 megawatts for the period from June 1, 2025, through May 31, 2026. The power mix from generators included 48% gas, 21% nuclear, 18% of coal, 1% of solar, 1% of wind, 4% of hydro, 5% of demand response, and 2% from other resources, PJM said. The total Fixed Resource Requirement (FRR) obligation is an additional 10,886 MW for a total of 146,570 MW. The total procured capacity in the auction and resource commitments under FRR represents an 18.5% reserve margin, compared to a 20.4% reserve margin for the 2024/2025 Delivery Year.

“The significantly higher prices in this auction confirm our concerns that the supply/demand balance is tightening,” PJM CEO Manu Asthana said. “The market is sending a price signal that should incent investment in resources.”

How did we get here?

The short explanation behind the price hikes: supply and demand. A longer line of reasoning includes insufficient future transmission planning, the retirement of fossil fuel generation, long interconnection queues, and the implementation of FERC-approved market reforms.

According to PJM, the drivers of higher prices in this auction include:

• Decreased supply offers into the auction due mainly to generator retirements
• Increase in projected peak load
• FERC-approved market reforms, including improved reliability risk modeling for extreme weather and accreditation that more accurately values each resource’s contribution to reliability

National trade association Advanced Energy United points out PJM scored a “D-” in a recent scorecard of how all grid operators are managing “generator interconnection,” the process of connecting energy projects to the power grid. PJM’s interconnection process was going so poorly it shut down its interconnection queue until sometime in 2025. Hundreds of projects are still stuck waiting in line. A 2023 report from Americans for a Clean Energy Grid graded PJM a “D” for its process of building new transmission lines, which are needed to connect energy projects to population centers.

“Electricity prices are skyrocketing because the grid operator PJM is failing to plan for the kind of energy infrastructure we need to affordably keep the lights on,” said Jon Gordon, Director at Advanced Energy United. “PJM didn’t prepare for an energy transition we all saw coming, and now consumers are going to pay the price.”

“PJM fell behind on interconnection and long-term transmission planning years ago, and now the problems are just cascading and piling up,” added Gordon, who leads United’s engagement with PJM. “With transmission planning improvements on the docket and further interconnection reforms urgently needed, these auction results should send a clear message that change can’t come too soon.”

Is change coming?

The price increase within PJM’s service territory is set to take effect in June 2025. Capacity prices are one component of wholesale costs that ultimately get factored into the price paid by end-use customers; electric bills also reflect the cost of other wholesale services like energy and transmission, as well as distribution services, state programs, and other fees.

The total amount of supply resources in the auction decreased again this year, continuing a trend across recent auctions and underlining PJM’s stated concerns about generation resources facing pressure to retire without replacement capacity being built quickly enough to replace them. About 6,600 MW of generation have retired or have must-offer exceptions (signaling intent to retire), compared to generators which offered in the 2024/2025 Base Residual Auction (BRA).

Meanwhile, the peak load forecast for the 2025/2026 Delivery Year has increased from 150,640 MW for the 2024/2025 BRA to 153,883 MW for the 2025/2026 Delivery Year. Additionally, FERC-approved market reforms contributed to tightening the supply and demand balance by better estimating the impact of extreme weather on load and more accurately determining resource reliability value.

These reliability concerns associated with reducing supply and increasing demand are not limited to PJM; the North American Electric Reliability Corporation has identified elevated risk to the reliability of the electrical grid for much of the country outside of PJM.

To facilitate the entry of new resources, PJM is implementing its FERC-approved generation interconnection reform, with approximately 72,000 MW of resources expected to be processed in 2024 and 2025. However, PJM remains concerned with the slow pace of new generation construction. Approximately 38,000 MW of resources currently have already cleared PJM’s interconnection queue but have not been built due to external challenges, including financing, supply chain, and siting/permitting issues.

“Interconnection process reform is proceeding, but hurdles remain for many projects outside of our process,” said Stu Bresler, executive vice president of market services and strategy. “We are considering ways to accelerate those who can successfully overcome those challenges and build.”

Auctions are usually held three years in advance of the delivery year. The 2025/2026 auction was originally scheduled to be held in May 2022, but auctions had been suspended while FERC considered approval of new capacity market rules. PJM has compressed its auction calendar to return to a three-year-forward basis. The next BRA, for the 2026/2027 Delivery Year, is currently scheduled for December 2024.

A detailed report of the auction is available on PJM’s capacity market page.

For perspective, AEP’s systemwide peak load at the end of 2023 was 35 GW. The utility serves 5.6 million customers in 11 states through its subsidiaries and has the country’s largest transmission system.

AEP Interim CEO Ben Fowke said the company continues to work with data centers to meet their increased demands for power, while ensuring that new contracts are fair to all of its customers.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly, and the right investments are made for the long-term success of our grid,” Fowke told investors.

Fowke cited AEP filing new data center tariff proposals in Ohio and large-load tariff modifications in Indiana and West Virginia.

In Ohio, the proposed rate structure would require new data centers with loads greater than 25 MW and cryptomining/mobile data center operations with loads greater than 1 MW to agree to meet certain requirements before infrastructure is constructed to serve them.

Data centers specifically would be required to make a 10-year commitment to pay for a minimum of 90% of the energy they say they need each month – even if they use less.

Along with Exelon, AEP is also protesting a proposal that would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in northeast Pennsylvania. The utilities claim the proposed interconnection agreement would result in unfair cost burdens on ratepayers and negatively impact market operations and reliability.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used.

The burgeoning of data centers is one reason utilities are planning for the largest increase in natural gas-fired plants in over a decade. Buyers of F-Class, advanced-class and aeroderivative gas turbines are reportedly experiencing lead times not seen since the gas boom of the early 2000s.

AEP’s Public Service Company of Oklahoma (PSO) plans to seek regulatory approval for the purchase of Green Country, a 795 MW natural gas combined-cycle plant in Jenks, Oklahoma. Subject to approval, PSO expects to close on the transaction by June 30, 2025.

On impact of environmental regulations

In the utility’s 10-Q, AEP said federal rules and environmental control requirements would impact the utility’s generation fleet. AEP noted EPA’s suite of measures to crack down on pollution from fossil-fired plants.

Under one of the measures, coal-fired plants which plan to stay open beyond 2039 would have to reduce or capture 90% of their carbon dioxide emissions by 2032. As of June 30, 2024, AEP said approximately 46% of the company’s owned generating capacity was coal-fired.

AEP said it is in the early stages of identifying the best strategy for complying with the rule while ensuring resource adequacy.

The company, along with other utilities, states, companies and trade associations challenged the rule and requested a stay, which was denied by the D.C. Circuit Court of Appeals.

AEP and other utilities have now filed applications with the United States Supreme Court seeking an emergency stay.

“Battery storage is a key element to building a green economy here in New York, and we have taken comprehensive efforts to ensure the proper safety standards are in place,” Governor Hochul said. “With updating fire codes, we’re ensuring that New York’s clean energy transition is done safely and responsibly.”

Governor Hochul convened the Working Group in 2023 to ensure the safety and security of energy storage systems, following fire incidents at facilities in Jefferson, Orange, and Suffolk Counties. The Working Group was tasked with independently examining energy storage facility fires and safety standards and creating a draft fire code Recommendations Report.

Proposed recommendations include:

• Requiring industry-funded independent peer reviews for all BESS installations exceeding energy capacity thresholds established for lithium-ion batteries;
• Requiring that qualified personnel or representatives with knowledge of the BESS installation are available for dispatch within 15 minutes and able to arrive on scene within four hours to provide support to local emergency responders in the event of a BESS fire.
• Extending safety signage requirements beyond the BESS unit itself to include perimeter fences or security barriers and include a map of the site, BESS enclosures, and associated equipment.
• Removing the fire code exemption for BESS projects owned or operated by electrical utilities to ensure that all projects comply with the fire code.
• Including a requirement that every BESS facility is equipped with an Emergency Response Plan (ERP) and site-specific training to be offered for local fire departments to familiarize them with the project, hazards associated with BESS, and procedures outlined in the ERP.
• Including a fire code requirement in all BESS installations for monitoring of fire detection systems by a central station service alarm system to ensure timely, proper notification to the local fire department in the event of a fire alarm.
• Introducing a new provision in the fire code mandating regular industry-funded special inspections for BESS installations to ensure thorough safety and compliance.

“Lithium-ion batteries and energy storage facilities play a large role in New York’s work toward achieving our clean energy goals,” said Secretary of State Walter T. Mosley. “Governor Hochul recognized the importance of putting the proper safety standards in place for this new, but critical, technology, and this draft language based on recommendations from the Governor’s Working Group will help ensure the safe operation of these facilities into the future.”

15 draft recommendations were proposed by the working group after examining existing FCNYS and other energy storage fire safety standards. The group previously released initial data finding no reported injuries nor harmful levels of toxins detected following fires at battery energy storage systems in Jefferson, Orange, and Suffolk Counties last summer.