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December 13, 2025

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FERC Sides With SEEM Members After Rehearing

In a March 14 filing, FERC ruled that the Southeast Energy Exchange Market (SEEM) is compliant with the commission’s orders and reaffirmed its acceptance of the SEEM Agreement in 2021 (ER21-1111, et al.).  

However, commissioners also ordered SEEM’s member utilities to update the market’s manual to account for changing a key requirement and submit a compliance filing within 30 days confirming they have done so. 

FERC’s filing came after the commission requested briefings in June 2024 from SEEM’s members and its opponents, in response to a 2023 order from the D.C. Circuit Court of Appeals remanding FERC’s approval of the market. (See FERC Requests Briefings on SEEM After DC Circuit Order.) The commission wanted to hear arguments on: 

    • Whether SEEM is a loose power pool. 
    • If so, whether and how SEEM “is consistent with or superior to the open-access requirements for loose power pools” in Order 888. 
    • If SEEM is not a loose power pool, whether and how it is superior to or consistent with the pro forma open access transmission tariff. 
    • Whether the market’s non-firm energy exchange transmission service (NFEETS) should be considered a non-pancaked rate. 
    • Whether NFEETS is “comparable to traditional transmission arrangements in bilateral markets.” 
    • Whether entities with a source or sink outside of SEEM’s territory could conform with the technical requirements of the market’s matching platform. 

Southern Co., Dominion Energy, Duke Energy and Louisville Gas & Electric, all members of SEEM, answered the commission’s request in an August 2024 briefing that argued the market is not a loose power pool because NFEETS is not a discount or a special rate, as FERC previously determined. They further claimed that NFEETS is pancaked and that owning a source or sink connected to a SEEM transmission provider is necessary for SEEM to be technically feasible. 

SEEM’s opponents, a group of environmental organizations and renewable energy trade organizations, countered the following month with a filing arguing that the market’s supporters focused on technical issues while ignoring the fact that SEEM “has walked and quacked like an exclusive power pool” since its conception. The opponents said SEEM violated Order 888 by systematically excluding independent power producers, while energy sales have been dominated by just a few utilities. (See SEEM Opponents Push Back on Supporters’ Claims.) 

In its March 14 filing, FERC agreed with SEEM’s members that the market is not a loose power pool. Commissioners said that, based on information provided in the reply comments, NFEETS “cannot neatly be described as either pancaked or non-pancaked,” but that the service “is best characterized as a pancaked rate because each SEEM transaction relies on the acquisition of NFEETS from each participating transmission provider.”  

The commission added that even if NFEETS did not disqualify SEEM as a loose power pool, the market still would comply with Order 888. FERC said though the order “prohibits participation requirements that are exclusionary based on geographic location or entity type, the commission does not read [Order 888] as prohibiting reasonable technical requirements for participation.”  

These “reasonable technical requirements” include the source/sink requirement, FERC said, because it ensures that participants are close enough for NFEETS to function properly. 

“These are not optional characteristics that constitute artificial barriers to participation,” FERC said. “Rather, they are technically integral to the goal of SEEM — to efficiently match buyers and sellers of energy with transmission capability that is unused through any existing transmission services.” 

FERC did note SEEM members’ statement that they have amended the market’s business practices manual to allow utilities to use pseudo-ties to satisfy the source/sink requirement. Pseudo-ties are used to represent interconnections between two balancing authorities where no physical connection exists between the load or generation and the power system network. 

The commission said the pseudo-tie option “significantly affects rates and services because it is the only option for such resources to participate in SEEM and use NFEETS.” FERC said the terms of service for using pseudo-ties, and the process for evaluating such mechanisms, therefore must be included in the SEEM Agreement, and gave members 30 days to submit a compliance filing verifying the agreement has been updated with the option. 

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NM Regulators Poke Assumptions Behind EPE’s Markets+ Choice

A recent study that contributed to El Paso Electric’s decision to join SPP’s Markets+ rather than CAISO’s Extended Day-Ahead Market (EDAM) has raised questions among New Mexico regulators. 

The results of the Brattle Group analysis were presented to the New Mexico Public Regulation Commission (PRC) during a March 13 workshop.  

The workshop followed EPE’s announcement Jan. 24 that it would join Markets+. The announcement surprised commissioners, who were expecting to see results of additional studies before EPE selected a market. (See related story, EPE’s Markets+ Decision ‘Not Transparent,’ NM Regulators Say.) 

In the new analysis, Brattle updated results from an earlier study for Public Service Company of New Mexico (PNM) and EPE with a “sensitivity case” that includes the value of the Eddy County tie. The tie is a 345-kV transmission line that links EPE with Southwestern Public Service, which is a member of the SPP RTO in the Eastern Interconnection. 

Under that case, EPE’s annual benefits would be $19.3 million if both New Mexico utilities join EDAM, $20.1 million if they join Markets+ and $18.8 million if EPE goes with Markets+ while PNM joins EDAM, Brattle projected in the new analysis. 

That contrasts with results from Brattle’s previous study, which projected EPE’s benefits would be $19.1 million a year if both utilities joined EDAM versus $9.1 million if both joined Markets+. The benefits are in comparison to a “current trends” (CT) case in which PNM and EPE remain in CAISO’s Western Energy Imbalance Market (WEIM) and don’t join a day-ahead market.

PNM announced its choice of EDAM in November. (See PNM Picks CAISO’s EDAM.) 

Eddy Optimization

In its new analysis, Brattle “optimized” the Eddy County tie to SPP East for scenarios where EPE joins Markets+, assuming that trade flows freely across the tie. The model assumes the SPP East market is liquid enough to supply or receive all Eddy tie flows at prices comparable to those of Markets+. 

“Whenever El Paso is purchasing power, we assume that the tie’s importing; whenever they’re selling power, we assume that they’re exporting,” Brattle Group principal John Tsoukalis said during the workshop. 

In the cases where EPE is in EDAM or only in WEIM, the Eddy tie isn’t optimized; instead, its value is assumed to be the same as it was in 2023. 

The optimization is only in the Markets+ cases because Markets+ and SPP East have the same market operator, said Tsoukalis, who said his understanding is that SPP is planning for the optimization. While Tsoukalis said it’s possible that SPP would optimize flows with EDAM, he said he’s not aware of any discussions to do so. 

Commission Chair Pat O’Connell questioned the assumption, saying it implies something “kind of remarkable.” 

“You have to accept that SPP would not work to optimize interregional transfer unless you’re in Markets+,” O’Connell said. 

Commissioner Gabriel Aguilera also wondered whether there would be an opportunity for Eddy County tie optimization through a seams agreement in a case where EPE joins EDAM. Aguilera asked if Brattle could calculate benefits in two additional ways: one in which the Eddy tie is not optimized in any of the four scenarios, and another in which it is optimized in all four scenarios, including cases where EPE joins EDAM or remains solely in WEIM. 

“It seems like all of those have an equal possibility of occurring,” Aguilera said. 

EPE representatives agreed to bring those variations of the analysis to the commission.  

EPE and PNM are co-owners of the 200-MW Eddie County tie: EPE has rights to two-thirds of the capacity, and PNM has rights to the remaining third. That prompted questions from the commission on why the Brattle analysis optimized the tie’s entire 200 MW in the two cases where EPE joins Markets+. 

“PNM owns part of this, and yet your sensitivity analysis relies so heavily on using 200 MW,” Aguilera said. 

Weighing the Choices

After the latest Brattle analysis found similar monetary benefits in the different scenarios, EPE turned to additional factors in making its day-ahead market decision. 

SPP’s experience as an RTO operator and its record of expanding renewable energy resources make “it a trusted partner in this endeavor,” EPE said in its announcement. (See El Paso Electric to Join SPP’s Markets+ in 2028.) 

During the PRC workshop, EPE representatives said another advantage of Markets+ relates to resource adequacy. Markets+ will require all participants to join Western Power Pool’s Western Resource Adequacy Program (WRAP). 

“It is important to make sure that everybody is on equal footing on how you’re calculating your resources,” said Emmanuel Villalobos, EPE’s director for market development and resource strategy. 

Instead of facing a WRAP requirement, EDAM participants will undergo a daily resource sufficiency evaluation (RSE). EDAM participants have the option to join WRAP, but it’s not required. 

Aguilera questioned EPE’s ability to meet WRAP’s requirements. He said the utility might need to accelerate resource procurement, with a resulting cost impact to customers. 

“As a regulator who is concerned about affordability, I would see that as a benefit in EDAM to have more of that flexibility” on resource adequacy, Aguilera said. “Especially given that WRAP hasn’t taken off. It’s been delayed. It’s been having its own issues.” (See WRAP Members Align on Key Issues to Prioritize.) 

EPE did not participate in Phase 1 of Markets+ development and has not yet signed a Phase 2 funding agreement with SPP — a move Villalobos said EPE is likely to make in the first quarter of 2026. The funding commitment would be in the form of collateral rather than money given upfront, he added. 

Consultant Utilicast is wrapping up a gap analysis for EPE, looking at steps the utility needs to take before joining Markets+. 

EPE expects to begin Markets+ implementation activities next year and start participating in the market in 2028. 

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NJ Releases Electrification-focused Energy Master Plan

Facing an expected surge in energy demand, New Jersey’s Board of Public Utilities outlined a draft Energy Master Plan (EMP) on March 13 that would continue the state’s existing, vigorous electrification strategy while also accepting “emerging clean firm technologies,” such as nuclear power. 

The 2024 EMP, which the BPU began researching last year, succeeds the 2019 version, which formed the cornerstone of Gov. Phil Murphy’s aggressive renewable energy strategy. It included the aggressive promotion of offshore wind and solar generation, electric vehicle adoption with incentives, and building electrification. 

The new plan predicts a 66% increase in electricity demand by 2050 if the state pursues its existing policies, driven by the power needs of new data centers, building electrification and the shift from fossil fuel-powered vehicles to EVs. 

What impact the latest master plan will have is unclear, however. Murphy is serving his last year in office, and the vigorous opposition to renewable energy in the current White House may limit some of the state’s efforts. 

The draft plan contains few concrete policy decisions pending further stakeholder input. It concludes that the state’s clean energy goals can be achieved through a “rapid and sustained pace of low-carbon technology deployment.” 

Eric Miller, executive director of the governor’s Office of Climate Action and the Green Economy, said the draft plan offers an “actionable and flexible approach to achieving our clean energy future that’s grounded in the best data available.” 

Among the findings is that the state should adopt a short-term and vigorous pursuit of “no regret” climate actions, such as building and transport electrification, utility-scale solar, and battery storage deployment, the BPU said in its presentation. 

Miller said a “no regrets” policy is one that “we know provides significant benefits to the climate and the state’s ratepayers without material downsides.” Such policies are central to all of the three future energy path scenarios outlined in the plan, he said. 

Mitigation Strategies

The EMP is part of the state’s effort to reach 100% clean electricity by 2035 and an 80% reduction in gas emissions by 2050.

It was compiled by Energy + Environmental Economics (E3) through research, modeling and stakeholder input from four public hearings in spring 2024. (See NJ Master Plan Speakers Seek Sweeping Electrification Plan.) 

E3 looked at four “Climate Pathways Scenarios” with varying levels of emission reductions, including current policy, which it said would not meet the state’s goals. 

    • current policy: 50% renewable portfolio standard; 5 GW of offshore wind would be developed; slow adoption of heat pumps; 25% cut in building gas use by 2050; and EV adoption driven by Advanced Clean Cars and Advanced Clean Trucks programs. 
    • high electrification: 100% clean energy standard by 2035; rapid heat pump adoption; 80% cut in building gas use by 2050; 94% of vehicles are EVs by 2050; and industrial gas use is reduced by 50% by 2050. 
    • demand management: 100% clean energy standard by 2035; 60% of existing homes and commercial buildings have “envelop upgrades,” or exterior wall insulation installed; 5 GW of new solar added by 2050; widespread managed EV charging to reduce peak load; and reduction in vehicle miles traveled through urban design and public transit.  
    • hybrid electrification: 100% clean energy standard by 2035; 40% of homes have a heat pump and a backup gas system; 94% of vehicles are EVs, but 20% are plug-in hybrids; and advanced renewable fuels are blended with fossil gas and petroleum to mitigate a portion of non-electrified fuel use. 

A spokesperson from Murphy’s office said all three of the mitigation scenarios enable the state to reach its goals. The final report will contain “a preferred scenario, but it will not be presented as the only scenario for the future,” they said. 

E3 said the high electrification scenario has the greatest impact on the grid, while the other two are designed to mitigate the stress on the grid using peak demand reduction. Electricity demand is expected to grow by more than 90% by 2050 in all three scenarios, with the biggest increase — 109% — experienced under high electrification. 

Meeting demand would require growth in nuclear power, according to E3’s presentation. There also would be a “role” for “emerging clean firm technologies” such as long-duration storage, and generators fueled by hydrogen or renewable natural gas, it said.  

The mitigation strategies also would rely heavily on rebates to make the new clean technology accessible, the BPU said. That would be especially so in the adoption of heat pumps, which cost about $20,000 to install, compared to $5,000 for a fossil-fuel boiler, the agency said. 

But by 2035, the average energy bill for electrified households and those powered by fossil fuels will be “comparable,” E3 said. For example, the average monthly energy bill, including vehicle fuel, would range from $325 to $360 in 2025, depending on whether the household was all electric or uses some gas. And by 2035, the range would be from $385 to $419, the BPU said. 

Support and Opposition

The BPU presented the plan during a three-hour online public hearing that drew varying reactions from 40 speakers. 

Patty Cronheim, a clean energy advocacy consultant, said she fully supported the high electrification scenario, in part because she has renovated her 100-year-old home to be a “complete electrification building.” 

“I understand firsthand how building electrification can help with the decarbonization transition by relieving peak summer demand,” she said. She urged the BPU to make sure that data centers are “on the hook for clean electricity generation that benefits the public and not be a strain on a system that costs New Jerseyans.” 

David Pringle, a steering committee member of environmental group Empower NJ, said his “main testimony today is going to be skepticism.” 

He said the Murphy administration “hasn’t come close” to implementing all the air emissions and “adaption rules” laid out in the 2019 EMP, and even if it implemented the 2024 rules, the next administration could have its own plans. 

While BPU and E3 officials stressed that affordability and the cost to ratepayers is a key element in the state deciding its energy strategy, Andrew Kuntz, staff attorney with the New Jersey Division of Rate Counsel, expressed concern that there was little evidence so far to support that claim. 

“The current version of the 2024 EMP is devoid of any mention of a rate impact study,” he said. “Affordability matters, and it must be part of this process.” 

Ray Cantor, a lobbyist for the New Jersey Business & Industry Association, said the plan has “a wrong starting point” in focusing on electrification. 

“We need to rely on what we know works, and primarily at this point in time, we need more natural gas generation,” he said. 

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FERC to Rule on SPP’s RA Requirement for Winter

FERC is expected to rule on SPP’s proposed tariff revisions adding a winter season resource adequacy requirement (RAR) during its monthly open meeting March 20 (ER24-2397). 

The commission in November 2023 rejected the proposed revisions, finding SPP’s proposal did not contain any requirement that the resources included in load-responsible entities’ workbooks are expected to be available. FERC also said the grid operator had not demonstrated it is reasonable to permit LREs to rely on resources that are not expected to be available to satisfy their winter season RARs. 

SPP filed a response June 28, asking for an effective date of Jan. 1, 2025. 

The RTO’s Board of Directors approved the winter season obligation in August 2023. (See “Board, RSC Endorse Winter Obligation,” SPP Board/Members Committee Briefs: July 24-25, 2023.) 

In February, the board approved a 38% planning reserve margin for the 2029 winter season. The 2029 summer season has a 17% PRM. 

The commission also has placed on its agenda an order that may be related to requests for rehearing by MISO and Montana-Dakota Utilities of a 2024 order that denied their complaints over a North Dakota cryptomining facility’s burdening a jointly owned flowgate with SPP (EL24-61). 

MISO and MDU sought to have market-to-market coordination on the line lifted after the Atlas Power Data Center added a 200-MW load to an SPP load pocket in northwestern North Dakota. They maintain that congestion management should not extend beyond SPP’s responsibility. (See MISO Argues to FERC for 2nd Look at Crypto-stressed Flowgate Management.) 

MISO in January filed a review petition with the D.C. Circuit Court of Appeals (25-1011) after FERC denied rehearing requests in November 2024, saying they “will be addressed in a future order.” MISO says the “future order” has not yet been issued in any of the underlying proceedings. 

FERC’s agenda also includes: 

    •  A response to SPP’s compliance filing in its effort to facilitate RTO membership for nine Western Interconnection entities. The commission found the grid operator’s tariff for its Western RTO to be deficient in October 2024 (ER24-2185). (See FERC Issues Deficiency Letter for SPP’s RTO West Tariff.) FERC asked for further clarifications on six issues, including transitioning the expansion members’ transmission service request queues into SPP’s existing transmission service study processes and how LMPs on both sides of the West DC ties will inform how the RTO optimizes the interties’ use. SPP is trying to be the first grid operator with markets in both the Western and Eastern Interconnections. RTO West is scheduled to go live in April 2026. 
    • An order related to SPP’s request to incorporate a mark-to-auction collateral requirement for its transmission congestion rights markets. The RTO asked for an effective date of May 1 to allow for enough time to add the collateral requirement before the TCR annual auction (ER24-2906). 
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Experts Urge Texas Policymakers to Go Big with 765-kV Transmission

ERCOT already operates a power system as large as those in several European countries, but demand growth is expected to bring it up to the level of PJM and MISO, which has the industry considering building a new system of 765-kV lines to transmit power around Texas. 

“When you think about PJM’s high-voltage overlay, they have this huge 765- and 500-kV system to move power back and forth and back and forth,” Grid United President Kris Zadlo said on a webinar March 13 hosted by Americans for a Clean Energy Grid. “And I think that’s kind of what we need to start thinking about if we’re going to be going to such a large system.” 

In the next decade, peak demand could double on ERCOT’s grid while overall consumption of power triples, said Michael Webber, professor of mechanical engineering at the University of Texas at Austin. 

The new demand is being driven by different factors. Data centers are part of the picture, but other sources include the need to electrify more of the oil and gas production in the booming Permian Basin and keep up with the general population and economic growth in Texas. ERCOT has grown 1 to 2% per year recently, when much of the rest of the country grew little to none. Growth rates now are up to 3 to 4% annually, Webber said. 

CenterPoint Energy forecasts demand in and around Houston will grow by 10 GW, which is the equivalent of adding Belgium’s total power demand to the system. 

“So, we have to add a Belgium to Houston, but we also have to add a Belgium to West Texas, and maybe half of Belgium to Abilene for data centers, or whatever,” Webber said. “If you start to add it up, and maybe a 10th of a Belgium here and there for LNG export terminals, which all say they’ll be electrified … it’s a lot of demand.” 

If all the demand were in one part of Texas, it could be met by building one power plant, but given how spread out it is across the state, transmission needs to be part of the picture, Webber said. 

“All of this adds up to this new estimate of 150 GW of load coming down the pipe,” said Conservative Texans for Energy Innovation’s Michael Jewell. “When the legislature heard about that, I think it really kind of freaked them out and got them to say, ‘You know, maybe there really is something that needs to happen.’ And I think it really has changed the dynamic to, ‘We do need to think about, how are we going to address this?’” 

Building transmission is part of the answer, but policymakers could decide to stick to 345-kV lines, as they did when Texas last did a major buildout of transmission more than 15 years ago with the Competitive Renewable Energy Zone lines to bring wind to customers. 

“One of the early questions was, should we be looking at 500-kV lines?” Jewell said. “And that kind of fell to the wayside as the advantages of 765 and the greater ability to move power there kind of outweighed almost what one could think of as an interim step in that regard.” 

The idea of building out 765-kV lines first was broached in the legislature with the aim of helping Permian Basin drillers continue to electrify. Once the focus was widened to the entire state, 765 kV made more sense, he added. 

While 765 kV is the largest voltage used in the U.S., China has built an overlay system with 1,100-kV lines, Webber said. Voltages that high start to come up against manufacturing issues, Zadlo said. 

“Once you go above 345, whether it’s 500 or 765, it’s the same thing,” Zadlo said. “My understanding is the 765 breakers come out of the same factories that are making 345 breakers. So really, there’s no difference there. I think the only big difference is when it comes to transformer production.” 

Building a series of 765-kV lines also takes about the same amount of time as building 345, he added. 

Forecasting demand growth always comes with uncertainty, but given that some of the new loads can come online in a year while power plants take three or four, and transmission in Texas takes at least six, it makes sense to start planning for it now, Zadlo said. 

“You can’t accelerate a transmission line, right? You just can’t,” Zadlo said. “It’ll be disastrous if we’re wrong; if we don’t build that line on time. … But you can always slow it down if the load doesn’t materialize. You can always pull back the plans.” 

Another reason to move with big infrastructure buildouts is they almost always are used to their capacity, Webber said. Railroads, broadband, the highways and other historical examples all involved some overbuilding, with only massive technological changes like the advent of automobiles and highways making the railroads less useful a century later. 

“If you’re going to go to the trouble [of building] capacity, you might as well build more capacity, and the higher voltage gives you more capacity,” Webber said. “So, I’d argue that this is actually the American way of doing things, and it would just give us more ability to move things around.” 

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MISO Members Grapple with 54 GW in Incomplete Gen, Predict Storage Expansion

NEW ORLEANS — MISO members haven’t landed on easy answers in getting the approximately 54 GW of unfinished generation that has cleared the interconnection queue online sooner. 

MISO’s Advisory Committee convened March 12 during Board Week to focus on the footprint’s lagging generation projects and how future delays could be prevented. (See MISO Members to Explore Ways to Rev Up Stalled Generation Builds.) 

Despite the focus on commercial operation delays, members agreed later in the meeting that energy storage eventually will flourish in the footprint. 

Illinois Commerce Commissioner Michael Carrigan said some increased transparency from MISO about the challenges in getting generation online would be helpful. He said he appreciated the RTO’s new reporting on the status of approved projects’ commercial operation dates but said more detail on the delays would be valuable for stakeholders. 

Wisconsin Public Service Commissioner Marcus Hawkins said he has observed delayed projects inch past their original budgets into cost overruns. “So, ratepayers are affected by these delays.” 

Multiple stakeholders also said the delays are set to affect states’ resource plans. 

Clean Grid Alliance’s Beth Soholt said states and load-serving entities might consider speeding up their procurement timelines or consider changing their permitting processes. She said that she, like many, “underappreciated” how decisively the COVID-19 pandemic upended the generation development cycle. Soholt said some developers struggled with virtual meetings while land agreements languished without construction. “There’s still a hangover there.” 

CGA Executive Director Beth Soholt speaks (background) as NextEra Energy’s Erin Murphy takes notes | © RTO Insider

Soholt also noted MISO has introduced several rule changes in its interconnection queue over the last few years, which may have some developers scrambling. 

“Interconnection customers have been living by the rules that MISO has set,” she said. 

Hawkins suggested the full effect of the RTO’s latest rule changes — the stepped-up fees, automatic withdrawal penalties, more rigorous proof of land rights and annual megawatt cap — have yet to settle in. Hawkins said he thinks projects that are processed in the stricter environment will arrive better vetted. However, he said, stakeholders might have to accept that the energy transition may be interspersed with failed plans for generation projects. 

“I think this just might be some of the new normal … this presence of stalled or delayed resources,” Hawkins said. 

Soholt said that while a lot of the responsibility for delayed projects is “rightly” on interconnection customers, she asked for a dialogue with transmission owners on what can be done about their own staff shortages and supply chain woes that grind network upgrades to a halt. 

“All it says is, ‘TO Delay.’ So, can we get more granular?” Soholt asked of TOs’ reports to FERC. She also requested that more light be shed on how TOs prioritize construction of network upgrades. She said interconnection customers don’t know enough about what causes network upgrade bottlenecks. 

Pelican Power’s Tia Elliott suggested that stakeholders and MISO create a method to match existing projects in the queue to a nearby LSE’s forecasted needs.  

The Union of Concerned Scientists’ Sam Gomberg asked if it was worth examining the RTO’s generator interconnection agreement contracts to see if there are any impediments or out-of-date language. 

Alliant Energy’s Mitchell Myhre said MISO’s proposed resource addition lane for its queue should help get projects online faster. (See MISO Says Queue Fast Track Design Settled, Ready for FERC.) The RTO is set to file that proposal imminently. 

But Gomberg said he did not see how an express lane in the queue would keep those projects from running into the same “buzz saws” of delays that plague projects in the traditional queue. 

Soholt said MISO should have been focused on its existing queue all along instead of introducing “chaos” with a fast lane, in which projects will need transmission capacity alongside the projects in the regular queue.  

At a meeting of the MISO Board of Directors’ System Planning Committee on March 11, Aubrey Johnson, the RTO’s vice president of system planning and competitive transmission, said members recently have been picking up the pace on generation additions despite the delays. He said members managed to add a record 7.5 GW in nameplate capacity in 2024, up from 5.6 GW in 2023 and 3.5 GW in 2022. In the first half of 2025, the RTO expects to have 5 GW in new nameplate capacity. Members have added 1.4 GW in nameplate capacity since the beginning of the year. 

The interconnection queue contains 308 GW across 1,695 projects; 145 GW of that is solar generation. 

Johnson also said he hopes the recently approved megawatt cap on annual entrants in the queue ends the “mad rush” of projects in recent years and leads to more thoughtful development. 

Storage in the Wings

Later in the Advisory Committee meeting, members agreed that while storage might be a slow burn now, it will heat up in the 2030s.  

MISO should contemplate new rules now, they agreed. 

The RTO has just 164 MW of operational storage in its market, with about 2.7 GW approved and waiting to come online. Its interconnection queue contains 61 GW of nameplate capacity across 388 storage project proposals. 

Executive Director of Markets Innovation and Strategy Zak Joundi said that although storage is in its “infancy” and growing modestly in the footprint, the RTO expects 12 GW of storage around 2030 to become 53 GW by 2043. 

Zak Joundi, MISO | © RTO Insider

Gomberg predicted a rapid deployment of storage in the coming years and said MISO needs to hammer out appropriate market rules to compensate the “versatile” resources that can supply capacity, as well as relieve transmission constraints. 

Myhre said he anticipates the jump in storage will mimic the rise in wind capacity that began about two decades ago. He said megawatts will quickly multiply into gigawatts, with the RTO and stakeholders “learning together” to draw up participation rules. 

Jim Dauphinais, representing a collection of MISO end-use customers, said that while battery storage will prove important, the current technology is limited to about four hours of output. 

“It doesn’t give us the same thing as a generation with a sustained supply of fuel. … While it can plug the gap, it can’t solve the exit of large generation resources,” he said. 

Dauphinais also said storage technologies are only going to be pursued to the extent that they earn revenues. He urged the RTO to begin forming market signals. 

NextEra Energy’s Erin Murphy said storage developers right now may be hesitant to build in MISO because of the investment uncertainty over their accreditation values. 

Joundi acknowledged the RTO has work to do on modeling how storage would contribute to the grid. But he also said current storage volumes are low. 

Murphy pressed MISO to begin modeling work even with a small sample size.  

“We have to say, ‘We’re going to put a stake in the ground and begin,’” Murphy said. 

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Calif. Officials Approve New Safety Measures for Battery Storage

The California Public Utilities Commission on March 13 voted to approve stricter safety standards on battery storage following a series of incidents at battery facilities. 

CPUC passed the new standards as an update to General Order 167, which became effective in 2005 and sets safety standards for electric generating facilities. The five-member commission voted unanimously to approve the update. 

The update provides “a method to implement and enforce maintenance and operation standards for electric generating facilities, in order to add new safety standards for the maintenance and operation of battery energy storage systems,” according to a news release.  

Additionally, the update requires battery storage facility owners to develop emergency plans in coordination with local authorities. It also imposes new technical logbook standards for battery storage systems, among other requirements. (See Calif. Officials Propose New Safety Measures for Battery Storage.) 

Commissioner John Reynolds said the resolution comes as battery storage grows rapidly in California. Battery storage capacity in the state grew from 500 MW in 2019 to over 13,000 MW in 2024, he noted. 

But the expansion of battery storage has caused safety concerns. The commissioners brought up the Jan. 16 fire at Vistra’s 300-MW energy storage facility at Moss Landing in Monterey County. The lithium-ion facility is one of the world’s largest battery energy storage systems. 

The fire, which prompted the evacuations of 1,200 people, is under investigation. Staff from CPUC’s Safety and Enforcement Division visited the site Jan. 22 as part of its probe.  

CPUC previously listed nine other safety incidents at facilities since 2021, including four in 2024. In one incident in September 2024, a fire at a San Diego Gas & Electric facility in Escondido prompted evacuations.  

Evacuations also were ordered in May 2024 during a fire at REV Renewables’ Gateway Energy Storage facility in Otay Mesa.  

“The broad effect of updating this general order is to extend existing safety standards for generation assets to grid-scale energy storage systems, including grid-scale batteries. This update will support the CPUC role in advancing battery safety and will help to keep Californians safe,” Reynolds said. 

CPUC also noted the importance of storage in California’s transition from fossil fuels.  

“Battery storage systems are one of the key technologies California relies on to enhance reliability and reduce dependency on polluting fossil fuel plants,” the news release stated. 

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NY Sells First Build-Ready Site for Renewables

A former iron mining operation once considered the largest of its type in the world has a new distinction: It will host the first site auctioned in New York’s Build-Ready program for large-scale renewables. 

The New York State Energy Research and Development Authority announced March 13 that CleanCapital had won rights to build and operate a 12-MW solar array in Benson Mines in the Adirondack Mountains region. 

Build-Ready is designed to address multiple state policy goals, including renewable energy development and brownfield reuse. 

NYSERDA assesses the viability of sites suggested for the program, then works with the landowners to design a customized benefits package and to advance the design, permitting and interconnection processes, then offers it as ready to construct. Ideally, this offers prospective developers a much-simplified path compared with starting from scratch on their own. 

The pre-auction process still can be lengthy, however. The Benson Mines project was announced in April 2021 with a planned early 2024 auction date, for example. And it initially was envisioned as a 20-MW project but was scaled back to avoid the need for system upgrades. 

NYSERDA said it has screened more than 5,000 sites and moved only a handful into more-advanced stages of potential development. Just three other sites besides Benson Mines are listed as having reached Build-Ready status: a former landfill, the grounds of an airport and an unused city property. 

Benson Mines began mining in the 1800s. It was a powerhouse for the region’s economy in its day, ranking as the world’s largest open pit iron mine by 1950. But it closed in 1978, leaving one more cluster of crumbling industrial structures in a region where tourists and seasonal residents far outnumber industrial workers. 

The former mine has been cleared of the rusting relics. Benson Mines now runs a 1,500-acre timber operation there, and sells aggregate crushed from the estimated 60 million tons of rock on site. 

The solar array will be placed on a tailings pile and is a good fit for the long-term goals for the site, company President Stuart Carlisle said in a news release: “This project has allowed us to put an underutilized portion of the Benson property back into productive use, bringing new investment, infrastructure development and economic benefits to the local community.” 

It will be one of the largest photovoltaic projects in the Adirondack Park, which with its highly regulated land use and rugged wilderness terrain does not lend itself to massive solar arrays. 

In a telling bit of geography, the state’s forest ranger training academy is held just down the road. 

But more importantly, a National Grid substation is even closer. 

NYSERDA President Doreen Harris said as the first of its kind, the Benson Mines project has value beyond its 12 MW of carbon-free power generation capacity: “We have now completed our first auction and are supporting the transformation of this underutilized site into something that is, in fact, build-ready. The Build-Ready program is helping to reimagine sites across the state so that communities can benefit from these otherwise-abandoned spaces.” 

CleanCapital will finance, construct, own and operate the project and has entered into a 20-year Renewable Energy Certificate agreement with NYSERDA. 

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ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes

ISO-NE provided stakeholders with a high-level overview of its proposed prompt capacity market design and discussed several other aspects of its capacity auction reform (CAR) project at a two-day meeting of the NEPOOL Markets Committee on March 11 and 12.

The CAR project aims to transform the region’s Forward Capacity Market, with auctions held over three years prior to each yearlong capacity commitment period (CCP), into a prompt and seasonal capacity market, held a month or two prior to each CCP, which would be split into summer and winter periods with separately procured capacity. (See ISO-NE Refines Scope, Schedule for Capacity Auction Reforms.)

Chris Geissler, director of economic analysis at ISO-NE, said the RTO would run the first prompt auction in April or May 2028 for the CCP beginning on June 1, 2028. It would finalize resources’ qualified capacity values in early 2028.

New resources would need to be in service prior to the auction to sell capacity, Geissler said. One of the motivations behind the prompt auction format is to eliminate “phantom entry,” in which an in-development resource secures a capacity supply obligation (CSO) but does not come online in time for the CCP.

Geissler said ISO-NE would provide “as much opportunity for new resources to demonstrate being in service as possible.” The RTO would allow non-commercial resources to participate in auction qualification and intends to set the latest possible deadline for resources to demonstrate they have achieved commercial operation.

He emphasized that the fundamentals of the demand curve and bid formulation will stay the same in a prompt market.

“Under either a forward or a prompt auction, a resource’s competitive capacity offer price should consider the incremental costs associated with taking on a CSO,” Geissler said.

He noted that some costs that would be included in offers in a forward auction — such as investment costs for a new resource — could not be included in offers in a prompt market. While this could lower some offer prices, Geissler said he does not expect this to lower overall market prices.

“Resources that are considering investment costs will only incur those costs if they expect to recover them via the markets, whether those markets are forward or prompt,” Geissler said. “We would therefore expect similar quantities of capacity to be sold in a forward or prompt market, producing comparable capacity prices.”

Seasonal Market Update

Jennifer Engelson, supervisor of resource qualification at ISO-NE, provided additional information on the RTO’s plans for the seasonal divide of the CCP.

ISO-NE would split the annual CCP into six-month summer and winter seasons beginning and ending at the ends of April and October, respectively. These periods would be aligned with the seasons used in NYISO’s capacity market. ISO-NE would run separate seasonal auctions for the next CCP each spring.

Dividing the CCP into two seasons is intended to help ISO-NE mitigate growing winter reliability risks, driven by heating electrification and gas supply issues. While ISO-NE considered using more than two seasons, it determined that “two longer seasons with clear peaks would be more economically efficient for the region” because of the concentration of risks in the winter and summer, Engelson said.

Resource Deactivations

Under ISO-NE’s existing tariff, the resource retirement process is tied to the FCM, and resources planning to retire signal their intent about four years prior to their exit from the market.

Because a prompt auction would provide little time to address potential system issues caused by the retirement, ISO-NE plans to decouple the retirement process from the capacity market. (See NEPOOL Markets Committee Briefs: Feb. 11, 2025 and ISO-NE Introduces Proposed Resource Retirement Changes.)

Under the new process, deactivation notices would be due two years prior to each CCP. Notices would be binding and set off a review process to evaluate potential reliability and market power issues created by the resource’s retirement.

The reliability review — triggered for all resources with more than 20 MW of capacity — would include an evaluation of local transmission security. If issues are identified, ISO-NE could retain the resource through an out-of-market agreement. The RTO has said repeatedly it plans to consider resource retentions only to address local transmission security issues and will not retain resources for energy security.

To evaluate and mitigate market power, the ISO-NE Internal Market Monitor would review deactivation submissions “to determine whether the retirement is justified by economics or potentially motivated by benefits to a portfolio.”

Retiring resources would be subject to a conduct test to evaluate the economics of the retirement and a net portfolio benefits (NPB) test to assess whether retiring a profitable resource would increase revenue for the resource owner’s remaining portfolio.

“When a participant fails both the conduct and the NPB test, this suggests that the deactivation represents an exercise of market power,” said Zeky Murra-Anton, an economist at ISO-NE.

When market power is identified, ISO-NE plans to impose a 1.5-times multiplier on the projected increase in portfolio-wide revenue caused by the retirement. Murra-Anton said this multiplier is intended “to effectively deter deactivations for market power purposes without being excessively punitive.”

Treatment of Repowering Resources

ISO-NE also discussed how the CAR changes would affect resource repowering efforts.

The RTO’s interconnection procedures and FCM have mechanisms for evaluating changes to existing resources. Both the interconnection process and the FCM are undergoing major reform efforts, which will necessitate changes to the treatment of resource repowering.

Alex Rost, director of transmission services at ISO-NE, assured stakeholders that the RTO is committed to retaining “a path for repowering projects as the CAR design is set.”

“At a fundamental level, [interconnection customers] with repowering projects that seek to change/replace an original generating facility with a new generating facility, where the new generating facility assumes its needed interconnection service from the original generating facility, will maintain the ability to do so,” Rost wrote in a memo issued prior to the meeting.

NEPGA Tie Benefits Concerns

Bruce Anderson, general counsel for the New England Power Generators Association, presented some concerns about how ISO-NE’s capacity market accounts for tie benefits, which the RTO has defined as “the assumed amount of emergency assistance from neighboring control areas that New England could rely on … in the event of a capacity shortage.”

“The current market design ‘assumes away’ approximately 2,000 MW of capacity demand based on the belief that system energy from neighboring control areas is equivalent to ‘firm capacity,’” Anderson said, adding that these assumed tie benefits reduce the region’s installed capacity requirement.

Because tie benefits are not subject to the same obligations, audits and nonperformance charges as resources with CSOs, Anderson said treating tie benefits as “equal to actual capacity” creates risks of price suppression and capacity under-procurement.

Anderson added that price suppression increases the likelihood of “uneconomic retirements of resources important to system reliability.”

He said NEPGA will propose alternatives intended to improve ISO-NE’s tie benefits accounting methodology in the coming months.

Flexible Response Services

Also at the meeting, Matthew White, vice president of market development and settlements at ISO-NE, discussed the RTO’s long-term plan to improve its flexible response capabilities “to address greater operational uncertainties with an increasingly weather-dependent resource mix.”

In a memo issued prior to the meeting, White wrote that ISO-NE is “assessing a combination of new probabilistic forecasts and enhancements to the co-optimized energy and reserve markets.”

On March 1, ISO-NE launched a new day-ahead ancillary services market, which procures reserves to help grid operators cope with load variability and fill any energy gaps that arise between the day-ahead energy market and the load forecast. (See FERC Approves ISO-NE’s Day-Ahead Ancillary Services Initiative.)

Looking forward, ISO-NE is considering how to improve its real-time forecasting of ramping needs and may look to procure “dynamically determined incremental quantities” of 10- and 30-minute reserves and new longer-response reserve products, potentially in the 60- or 90-minute range, White said.

“New England’s power system is becoming increasingly dynamic, and extending conceptually familiar market designs with new probabilistic modeling capabilities appears to be a promising next step to reliably address increasing operational uncertainties,” White wrote.

“By carrying less incremental reserves when net load uncertainty or ramping needs are forecast to be low, unnecessary costs can be avoided; and by increasing incremental reserves when net load uncertainty or ramping needs are forecast to be higher, reliability can be maintained,” he added.

Fall Markets Report

Finally, the IMM’s Kathryn Lynch presented the Monitor’s fall quarterly markets report, which found that wholesale market costs during the quarter increased by 8% relative to fall 2023, up to nearly $1.5 billion in total costs.

Market costs increased despite a 13% decrease in natural gas prices and the lowest recorded fall season power demand.

The increase was driven by increased emissions costs for the Regional Greenhouse Gas Initiative and decreased imports and domestic nuclear generation, Lynch said. Average hourly nuclear generation decreased by about 423 MW compared to the prior fall “due to planned and forced outages,” while net imports dropped by an hourly average of 892 MW because of “dry weather in Québec and a nuclear generator outage in New Brunswick.”

Overall, market pricing outcomes were competitive, and “there was no evidence of impactful capacity withholding,” Lynch said.

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Ahead of Crossover Day, Energy Bills Stalled in Md. General Assembly

State energy policy was supposed to be a top priority for the Maryland General Assembly’s 2025 session, but it appears to be taking a backseat to more pressing fiscal matters.  

With lawmakers in Annapolis mostly focused on producing a budget that can fill the state’s projected $3 billion deficit, many energy bills appear stalled in advance of “crossover day” on March 17, when bills introduced in one house must be approved in that chamber and cross over to the other.  

Dozens of energy bills have been introduced in both houses, but few have taken the first step of being approved by their appropriate committees, let alone moved to a floor vote. 

The budget is taking up a lot of time and “mental space,” said Kim Coble, executive director of the Maryland League of Conservation Voters. But the bigger issue is the complexity of the energy issues addressed by the bills state delegates and senators are considering. 

“There’s a lot of need to educate members and to bring them along, and the number of bills and topics that are trying to be addressed [is] major,” Coble said. “They are getting lots of phone calls from constituents about their electricity bills; they’re getting lots of calls about clean energy and trying to balance it all.  

“So, I am trying to stay optimistic,” she said. “The fact that things haven’t moved yet is not a delay tactic. It’s because it is a tough, complicated topic that they want to get right.” 

Both Coble and Katie Mettle, policy principal for Maryland at Advanced Energy United, also note that any bills not crossing over by March 17 still can move forward in the legislature via a special vote in the Rules Committee in either house. 

“I think they honestly just are not sweating the crossover deadline for their top, most important bills, because they know they can take longer if they want to,” Mettle said. “They just want to make sure that everything is to their liking. … There [are] still negotiations going on.” 

Coble pointed to the Abundant, Affordable Clean Energy (AACE) Act (HB 398, SB 316), sponsored by Del. Lorig Charkoudian (D) and Sen. Benjamin Brooks (D). The bill’s multiple provisions include a mandate for the Maryland Public Service Commission to open two rounds of applications each for 150 MW of distribution-tied energy storage and 1,600 MW of front-of-the-meter, transmission-tied storage, as well as incentives for 3,000 MW each of utility- and small-scale solar projects.  

The bill also seeks to support the state’s existing nuclear plants via license extensions and zero-emission credits, and calls for coordinated planning for transmission to bring offshore wind energy to the homes and business that need it. It requires prevailing wage standards for workers employed on energy storage projects. 

The goal, Charkoudian said is “to ensure resource adequacy, with protecting ratepayers and with clean energy.” 

As of March 13, the bill was sitting in committees in both houses, but both Coble and Charkoudian said negotiations are underway to incorporate parts of AACE into another major bill, the Next Generation Energy Act, which is one of three major energy bills being supported by House and Senate leadership. 

The Leadership Package

Referred to as “the leadership package,” the three bills include: 

    • The Energy Resource Adequacy and Planning Act (SB 909), which would require the PSC to establish an Integrated Resource Planning Office, which would conduct a 25-year comprehensive energy forecast aimed at meeting state clean energy and emission reduction goals, while ensuring reliability and affordability. 
    • The Renewable Energy Certainty Act (SB 931), which would set rigorous standards for solar and storage projects seeking a certificate of public necessity and convenience from the PSC, to ensure careful siting and community engagement. The bill also would prohibit city or county governments from passing zoning or other laws blocking solar and storage projects. 
    • The Next Generation Energy Act (SB 937), which would promote the development of nuclear energy, and the extension of the licenses of existing reactors, as a matter of state policy, while also encouraging regional collaboration between states to share costs on the development of new reactors. The bill also calls for the procurement of 3,100 MW of “dispatchable energy generation capacity” and a temporary expedited permitting process for these projects. 

Advocates like Mettle have raised red flags about those 3,100 MW of dispatchable generation, which she presumes would be natural gas. “The thing about gas [is] we just don’t need it,” she said. “I just don’t think from a technological standpoint or an economic standpoint that it’s remotely necessary.” 

Mettle would first like to see PJM clear the solar and storage projects sitting in its interconnection queue and then ensure the state is ready to support projects as they are approved for interconnection. She supports SB 931 and the AACE Act as ways to “turbocharge” the solar and storage industry.  

Both Charkoudian and Coble are concerned any expedited permitting will strip out requirements for community engagement and attention to environmental justice issues. 

Charkoudian is working on amendments that will incorporate parts of AACE into SB 937. “So, I think what you’re going to see, when they kind of come out or start going through the process in committee, is just a lot of amendments to add, to improve, take the best ideas and move them on,” she said. “I think it’s possible that that won’t happen before crossover.” 

Crossovers So Far

The Maryland Clean Energy Center tracks energy and climate bills in the General Assembly and issues weekly reports. As of March 13, the following bills have crossed over: 

    • SB 37, another Charkoudian bill, would require utilities to report to the PSC on their votes at all PJM stakeholder and other meetings. Its House counterpart, HB 121, still is in committee. 
    • HB 270 calls for a state-level data center impact analysis report to be developed by the Department of the Environment, the Maryland Energy Administration and the University of Maryland School of Business, and to be submitted to the governor and General Assembly by Sept. 1, 2026. 
    • SB 120 and HB 4, approved in both houses, prohibits community or condo associations from putting restrictions on solar installations that would increase the cost of the projects by 5% or reduce their electrical output by 10%. 
    • HB 61 would require the design for any new school construction or major renovation to evaluate installing solar parking canopies.  
    • SB 399 would allow transmission lines to be run through certain state-designated “wildlands.”  

Maryland LCV is opposing the bill, which Coble said is tailored to the Mid-Atlantic Resiliency Link, which is being developed by NextEra Energy. Wildlands are particularly pristine areas and account for less than 1% of the state’s land, she said. 

“This would be the first time the state of Maryland has ever opened up wildlands from new transmission lines. So that, in and of itself, is bad,” she said. “These wildlands are pretty special lands, and they do need and deserve extra consideration.”