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November 5, 2024

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FERC Approves PJM Capacity Auction Delay

FERC on Feb. 26 accepted PJM’s request to delay the 2025/26 Base Residual Auction (BRA) from June 12 to July 17 to give stakeholders time to understand new capacity auction rules (ER24-1242). 

The commission said PJM acted in good faith and that the request was limited in scope, as it was for the specific purpose of educating market participants on changes to how the RTO will calculate effective load-carrying capability (ELCC) ratings, approved by FERC in January. (See PJM Seeks Waiver to Postpone 2025/26 Capacity Auction.) 

“Granting the waiver addresses a concrete problem because it will allow sellers to better understand the implementation of the new ELCC values and modeling methodologies before they are required to submit unit-specific offer caps,” FERC said. “We find that granting the waiver request will not have undesirable consequences, such as harming third parties, because it is a limited to a short delay of one BRA and will facilitate an orderly administration of the auction.” 

The commission approved changes to PJM’s risk modeling and accreditation in January but denied a second proposal to revise components of the market seller offer cap in early February. PJM’s Planning Committee has held two special sessions to discuss the changes this month and presented updated class ratings that varied as much as 20% for some resources from preliminary figures shown last year. (See FERC Rejects Changes to PJM Capacity Performance Penalties.) 

In comments supporting the delay, LS Power Development argued 35 days is the minimum market participants would need to understand the impact of the new approach to accrediting resources. The company noted it had asked the commission to delay implementation of the ELCC changes to the 2026/27 auction, scheduled for December 2024, because of the tight time frame between PJM’s proposals and the start of preauction activities for the 2025/26 auction. 

It also said it “was especially concerned that PJM had released few details of its ELCC methodology to stakeholders and had provided very little information regarding the accredited [capacity values] that would result from the application of that new methodology. LSP Development’s concerns became increasingly pressing as preauction deadlines approached and PJM still had not released necessary information for market participants to make informed business decisions regarding participation in the 2025/2026 BRA.” 

Stakeholders also need time to verify the results PJM has presented, LS Power said. The RTO has arrived at “noticeably different” accredited unforced capacity values for two resources located at the same site and with similar characteristics, but members have not received explanation for the reason, it said. “Not only does PJM need to provide ‘additional education,’ but market participants must also have the opportunity to review the underlying data so that any errors in PJM’s accreditation determinations may be corrected.” 

The PJM Power Providers Group also submitted comments in support of the delay, arguing the need to ensure accurate accreditation values warrants a delay. 

No comments were filed in opposition. 

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PSEG Awaits Federal Nuclear Plant Tax Credits

PSEG is urging the U.S. Treasury Department to speedily release rules for the program that could provide Production Tax Credits to support the utility’s three South Jersey nuclear plants, but the effort has yet to yield results, CFO Daniel J. Cregg said in the company’s fourth-quarter earnings call Feb. 26. 

Cregg said the utility last spoke two months ago to Treasury officials about the PTC program; it is part of the Inflation Reduction Act, and it awards tax credits of up to $15/mWh for electricity produced by existing nuclear plants. PSEG is the sole owner and operator of the Hope Creek plant and the operator and majority co-owner of Salem 1 and Salem 2 plants. 

“We made them aware, as we do every time that we can, that it’s important for them to try to get the rules out sooner rather than later,” Cregg said, referring to Treasury officials. “But as we sit here today, they have not issued a date by which they will provide that guidance. So we are just awaiting their answer.” He said his team nevertheless has “done a lot of work” trying to prepare for the different scenarios so the utility is ready when they’re released. 

The utility on Nov. 22 told the New Jersey Board of Public Utilities (BPU) it would withdraw from the state’s Zero Emission Certificate (ZEC) program, which since 2019 has awarded PSEG $300 million a year to ensure its three plants remain operating to help the state meet its clean energy goals. (See NJ Closes Nuclear Subsidy Process as PSEG Looks to Feds.) PSEG said it withdrew to “preserve PSEG’s rights” to federal tax credits. 

CEO Ralph LaRossa, responding to a question on the call, said knowing the framework of the tax credits will help shape the utility’s decision-making on economic development plans for the plants. “The PTC rules need to come out, and once all of that comes together, we’ll be able to look at a plan, optimize the revenues from those plants,” he said. 

Shifting Customer Use

LaRossa said company initiatives over the past 12 months have aligned with New Jersey’s goals of cutting gas use by 0.75% and electricity use by 2%.  

A key element of the effort was PSEG’s $3.1 billion energy efficiency investment program filed with the BPU in December, which, if approved, would run from January 2025 to June 2027. In a second key component of the effort, LaRossa said, the utility in November requested an extension of the current energy efficiency program, which would cost $300 million and run from July 2023 to December. 

“Our [energy efficiency] programs continue to create value by lowering customer bills, reducing energy use and emissions, and providing shareholders with a return of, and on, the energy efficiency spending,” he said. 

LaRossa added the utility is “proposing new time-of-use rates that will allow customers to save on their bills by shifting usage to off-peak periods, a rate option that can benefit all customers, incentivizing residential customers to charge their electric vehicles during these off-peak hours.” The utility provided no further specifics on the strategy. 

PSEG’s fourth-quarter results for 2023 fell short of those in 2022, but the full-year results improved on 2022. The company reported fourth quarter 2023 net income of $546 million ($1.10/share), compared with $788 million ($1.58/share). Non-GAAP operating earnings were $271 million ($0.54/share), compared with $318 million ($0.64/share) in the same period in 2022. 

The company reported 2023 net income of $2.563 billion ($5.13/share), up from $1.031 billion ($2.06/share) in 2022. Non-GAAP operating earnings in 2023 were $1.742 billion ($3.48/share), compared to $1.739 billion ($3.37/share) in 2022. 

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AEU Grades ISO/RTO Queues as Order 2023 is Implemented

Advanced Energy United has released a scorecard that ranks the seven domestic ISO/RTOs on their generator interconnection processes, finding room for improvement in every one. 

Brattle Group and Grid Strategies prepared the Generator Interconnection Scorecard for AEU, as they did for a similar project on transmission planning last year. (See Transmission Report Card Grades MISO “B,” Southeast “F”.) 

The scorecard, released Feb. 26, comes after FERC issued Order 2023 and is meant to help track how those and other reforms are implemented, Grid Strategies President and report co-author Rob Gramlich said in an interview. (See FERC Updates Interconnection Queue Process with Order 2023.) 

“We’re hopeful that those reforms happen and further reforms get done,” Gramlich said. “And we’re hopeful that in a year or two, if and when we do this again, all of the grades will improve. But the idea was just to kind of take a snapshot at this time.” 

The flawed interconnection processes have more than 2 million MW of renewable power and storage waiting to connect to the grid, said Advanced Energy United Managing Director Caitlin Marquis. 

“This scorecard confirms what we know about the interconnection process, that grid managers have moved too slowly to adapt to changing market conditions, allowing the process of connecting new electricity to the transmission grid to become dysfunctional,” Marquis said. “Without urgent improvement, the U.S. grid may struggle to keep up with growing energy demands, threatening our ability to keep the lights on and reach our climate goals. Strong implementation of FERC’s recent reforms will be an important first step toward improving the interconnection process, and it’s also clear that additional reforms will be needed.”  

None of the ISO/RTOs managed to get an A, but both CAISO and ERCOT got Bs, with Gramlich saying one reason they did better was that they’ve proactively planned their transmission systems to add new resources. 

“That has been a little bit less of a case recently in ERCOT,” Gramlich said. “And so ERCOT used to be great from a developer perspective, but they got marked down a little bit because of a lack of transmission. Because you can connect, but there’s a lot of congestion once you connect. California has always done proactive transmission planning pretty consistently … so the grid has been prepared in advance to accommodate more generation.” 

Both also scored highly on giving developers a sense of certainty, with ERCOT assigning limited costs to interconnection customers and CAISO being credited with good transparency. 

No other market scored above a C- on AEU’s scorecard, which highlights the need for changes to meet rising demand from new large loads, electrification, and state policies and customer demand driving more renewables onto the grid. 

“Currently, most of the regions are undergoing significant efforts to reform their interconnection practices and policies in response to stakeholder concerns and FERC Order No. 2023,” the report said. “The scorecard is not an assessment of those ongoing or recently adopted reforms that have not yet impacted the generator interconnection processes.”  

The growth of wind, utility-scale solar and storage has resulted in interconnection projects popping up everywhere, Gramlich said.

“Twenty years ago, when the current rules were designed, everybody was building just gas plants,” he added. “They were large and lumpy. You could put them at the intersection of a pipeline and a transmission line. And so, the rules were designed just with one technology in mind.” 

The scorecard measures six categories, the first of which is interconnection process and results, which measures an interconnection’s success rate, cost reasonableness and uncertainty. It also grades prequeue information, queue design, assumptions and criteria, availability of interconnection alternatives, and whether transmission planning takes future generation needs into account. 

That final category is the only one where the graders looked at rules now in place, which have not impacted the queues yet.  

Along with CAISO, MISO scored well there due to the Long-Range Transmission Planning process Tranche 1, with two other tranches being developed. None of those lines have impacted the queue yet, but interconnection customers view them favorably, as one of the benefits studied was transmission projects’ ability to bring the lowest-cost generation to market. 

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PJM Seeking Expedited Approval of Energy Efficiency Changes

VALLEY FORGE, Pa. — PJM presented the Markets and Reliability Committee with an expedited proposal to revise how it measures and verifies the capacity contribution of energy efficiency (EE) resources, drawing alarm bells from market participants that the RTO is moving too fast and making changes outside the stakeholder process. 

The proposed changes shown during the Feb. 22 MRC meeting would focus on how a baseline estimate of energy consumption is determined to measure the load reduction provided by an EE installation. It would require that the providers use the most recent relevant Technical Reference Manual (TRM) published within the past three years when conducting studies of current baseline load or use meter data if standards are not available or applicable. It also would have to be demonstratable that the project was initiated with the goal of wholesale market participation and the equipment being replaced was fully operational and would have continued to be in use. 

EE providers also would be required to demonstrate that the installation of the more efficient technology was completed and that they had exclusive rights with end users to enter the installation into the capacity market to prevent double counting. 

Pete Langbein, PJM’s manager of demand side response operations, said staff saw value in seeking improvements to the EE measurement and verification processes prior to the next Base Residual Auction, scheduled for June 2024. The proposal was brought under an issue charge at the Market Implementation Committee to broadly look at EE participation in the capacity market and consider if any changes are needed ahead of the next auction. (See “Stakeholders Begin Review of Energy Efficiency Resources,” PJM MIC Briefs: Dec. 6, 2023.) 

Equipment replacements that go beyond the standards outlined in TRMs would continue to qualify as EE, but the amount of compensation they receive might change under the proposal, Langbein said. 

Several stakeholders argued PJM is bypassing the stakeholder process by introducing a proposal at the MRC without first going through the typical package formation and endorsement process at the MIC. PJM first presented the changes during a Feb. 21 MIC special session. 

Luke Fishback, of Affirmed Energy, said the MIC issue charge was brought in part to ensure the definition of EE resources in the manuals reflects tariff language, an effort he does not believe would be advanced by PJM’s proposal. He argued the redlines are hasty and would introduce conflicts between the manuals and governing documents. 

Requiring EE providers to enter into contracts with each end user to guarantee that installations are participating in only one program would add a substantial barrier to participation, Fishback said. He agreed with PJM that it’s critical that double counting be prevented, but he said more stakeholder deliberation is needed to find a workable solution, particularly given how little time there is because contracts need to be finalized ahead of the next capacity auction. 

Several market participants and state regulators, plus Independent Market Monitor Joseph Bowring, argued the language requiring that installations be dependent on capacity market revenues is unverifiable and questioned what evidence PJM would find acceptable. 

Angela Fox, Affirmed Energy’s chief markets officer, said requiring end-use customer information could conflict with privacy laws and obstruct program participation. 

Exelon Director of RTO Relations Alex Stern said it’s important that states be informed of the changes being recommended and how they may impact any EE programs in their states. State-sponsored programs may find they are no longer eligible for capacity market revenues, which may impact the ability to continue to offer EE benefits to low-income consumers if those programs use wholesale market revenues to offset the cost to taxpayers. 

Asim Haque, PJM senior vice president of governmental and member services, said staff are scheduling a briefing with the states to discuss the changes. 

Without a full stakeholder process during the formation of the proposal, CPower Senior Vice President of Regulatory and Government Affairs Ken Schisler said the changes have not been vetted by members and they are not addressing a problem that has previously been articulated. He presented a proposal built off PJM’s redlines which he argued would resolve many of the issues stakeholders identified with the changes. 

The CPower proposal would eliminate the requirement that projects be tied to capacity market participation, the end-use consumer data collection language and the three-year requirement for TRMs — instead using the most recent manual. 

Highlighting the challenges with PJM’s proposal, Schisler gave the example of an EE project to replace insulation in the home of an individual with a respiratory illness. He argued the dual benefits of reducing electric heating load paired with reducing health risks that may be present could make it difficult to show the causal link between the project and capacity market revenues that PJM’s language would require. 

He also stated many of the TRMs in use would be deemed ineligible due to the age of their last update, which would constrain the ability to administer EE programs in many states under PJM’s proposal. 

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SPP Markets+ Stakeholders Prep Tariff for Approval

Potential participants in SPP’s Markets+ day-ahead offering endorsed another batch of tariff revisions in preparation for a March filing at FERC. 

During a Markets+ Participants Executive Committee meeting Feb. 20, stakeholders approved dozens of pages of revisions related to market monitoring, state greenhouse gas emission programs and transmission usage. Assuming the entire tariff package is approved in March by the Markets+ independent panel of SPP directors and the RTO’s board, it will be submitted to FERC. 

MPEC Vice Chair Brian Cole, with Arizona Public Service, praised the “amazing effort” by all involved in the tariff’s development, which began in August 2022. “To get to where we are is amazing. I know we’ve got a long way to go, but to get to a tariff filing is really great,” he said. 

The various revisions were approved unanimously against some abstentions. However, a motion to endorse the updated tariff as approved by MPEC and move it to the governing process’ next step for filing at FERC drew four no votes from Western Resources Advocates, the Natural Resources Defense Council, the Sierra Club and the NW Energy Coalition. 

“It’s not us saying we do not believe in Markets+,” said Kylah McNabb, speaking for the NRDC. “It’s a product that should go forward. It just needs more work before filing at FERC.” 

“Procedurally, we need this vote to move it forward to [the Interim Markets+ Independent Panel],” SPP’s Carrie Simpson, director of western services development, said. “We’ve got the pieces. This is the full package. We need endorsement to get to IMIP.” 

“The tariff is notably incomplete. More time is needed,” agreed WRA’s Vijay Satyal, deputy director of regional markets. 

McNabb pointed to MPEC’s discussion over the remaining tariff revisions to the greenhouse gas (GHG) market’s design. PowerEx’s Mark Holman suggested language assigning resources to load was “watered down” and asked to strengthen an action item directing the Markets+ Development Working Group (MDWG) and SPP staff to evaluate tools for monitoring and tracking GHG programs. 

“We’d like to strengthen it if other participants are supportive because we feel there needs to be a strong push coming out of this phase to develop the ability to attribute resources to load and have the comprehensive reporting that I think ourselves and others have envisioned,” Holman said. 

MPEC approved the action item and revisions related to the assignment of resources to load and GHG market design settlements.  

SPP staff is surveying Markets+ participants on WRA’s suggestion for an external market monitoring consultant over a three-year period before and after the market’s deployment and to gauge their appetite for a hybrid market monitoring option that could cost an additional $2.5 million. The advocacy group pointed to tariff language that would expand the monitoring structure to include an external adviser to SPP’s Market Monitoring Unit, given the market’s new design approach. 

WRA has suggested the developmental phase of the market should include guidance on “areas of focus” by the external consultant. Satyal used a seams and joint operating agreement with CAISO’s Extended Day-Ahead Market (EDAM) as a relevant example. 

“The WRA simply feels this is an insurance policy,” he said. 

The IMIP meets virtually March 1. It will take up the tariff package and hear any appeals. Assuming IMIP’s approval, the tariff will be considered by the board during a March 25 conference call. 

SPP is hoping for FERC approval in October or November and work to begin on Markets+’s implementation early in 2025. That would put the RTO a year behind CAISO’s EDAM, the other competing market offering in the West. The commission approved the EDAM filing in December. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.) 

Under SPP’s current timeline, shortened by three months, Markets+ would go live before summer 2027. 

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Québec, New England See Shifting Role for Canadian Hydropower

With the days of endless cheap hydropower in Québec coming to an end, and the Northeastern U.S. hoping to rapidly scale up intermittent renewables, the two regions may be forced to fundamentally reconsider the role of hydropower on the grid. 

Power has historically flowed south, and just a decade ago, government-owned corporation Hydro-Québec actively sought two contracts to send large quantities of power to the U.S. It eventually reached deals with Massachusetts and New York that led to a pair of major new transmission projects: the 1,200-MW New England Clean Energy Connect (NECEC) and the 1,250-MW Champlain Hudson Power Express (CHPE). 

NECEC and CHPE are aiming to be in service by 2025 and 2026, respectively, and are tied to long-term supply contracts that will ensure that baseload power will flow from Québec to the Northeast well into the 2040s. 

At the same time, increasing power demand in Québec has forced Hydro-Québec to re-evaluate the role of hydropower going forward while spurring concerns in the U.S. that it will not have enough power to fulfill the contracts. 

While Hydro-Québec has maintained that it will be able to meet the NECEC and CHPE contracts, the corporation acknowledges that a paradigm shift is on the horizon for its hydro fleet. 

“When you look forward, we don’t have more surpluses that we could do another two [contracts] tomorrow — not like that, not in that same fashion,” Serge Abergel, COO of Hydro-Québec’s U.S. operations, told RTO Insider. 

Instead, the company is eyeing a long-term change in the role hydropower plays on the grid, transitioning from baseload to a long-duration storage resource that can help balance and firm up the growing amount of wind and solar resources. 

“We’re at a point in time where the traditional way of how we’ve been doing things in the past — sending [from] north to south large blocks of energy 24/7 — is completely changing,” Abergel said. The proliferation of intermittent renewables “will create a very strong need for a balancing resource, and that’s where our hydropower will be able to play a different role.” 

Enough Energy, or Enough Capacity?

In 2021, a group of MIT-affiliated researchers published a study modeling the optimal configuration of a high-renewables grid in 2050, aimed at better understanding the role of large Canadian hydro resources. 

The researchers initially expected to find hydropower to be “this very flexible baseload resource, something like nuclear, but even more flexible,” co-author Emil Dimanchev told RTO Insider. 

“But what we found from our modeling was something very different,” Dimanchev said; “specifically, the fact that if the system was operated optimally, the best thing to do would be to do a two-way trading of electricity,” with Canadian hydro operating “more as a battery rather than this flexible source of energy.” 

The modeling found that increasing the transmission capacity between Québec and New England would help expedite the decarbonization of the power sector while reducing the need to overbuild intermittent renewables. The analysis also found that Québec did not need to add any hydropower for it to play a substantial balancing role, noting that investments in new hydro plants “are deemed uneconomical by our model” compared to investments in new wind and solar. 

“Québec already has this huge battery, so intermittency is not a problem,” Dimanchev said. New wind and solar resources “can be immediately firmed up with existing hydro.” 

To prevent short-term power supply issues, Hydro-Québec is planning to spend $90 billion to $110 billion CAD by 2035 to increase its generating capacity by 8,000 to 9,000 MW, largely through new wind resources, demand reductions, upgrades to existing hydro generators and new hydro facilities. 

The study’s findings also speak to more recent questions of whether Québec has enough power to justify additional transmission projects, Dimanchev said. 

“The question that people are raising now is, ‘Is there enough energy to serve all the contracts and new transmission lines?’” Dimanchev said. “Well, that might be a problem in the short term, but what our study shows is that in the long term, we should think of this resource as a battery, so the question is not so much, is there enough energy, but is there enough transmission capacity to use that battery?” 

The potential of Canadian hydropower as a long-duration storage resource is the basis for another potential transmission line, the Twin States Clean Energy Link, a proposed 1,200-MW two-way connection between New England and Québec. 

Aiming to come online in the early 2030s, the National Grid-led project touts its potential “to balance New England’s renewable resources during times of peak demand, while also sending surplus renewable power generated in New England — such as offshore wind — to Québec when it’s not needed.” 

The project has already received a vote of confidence from the U.S. government: In September, the Department of Energy committed to purchasing a significant portion of the line’s capacity to minimize the project’s overall development risk. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) 

South-of-the-border Constraints

Although added transmission capacity between Québec and New England could help unlock the balancing potential of hydropower, the benefits are largely contingent on reaching a high level of surplus renewables. 

“This doesn’t apply today because we are just in the early stages of this deployment of intermittent renewables,” Hydro-Québec’s Abergel said. However, by 2035, “we believe there’ll be sufficient intermittent resources in the Northeast to start having a viable concept.” 

Reaching a high level of renewable power in New England will require significant investments in local transmission infrastructure to interconnect new solar and wind resources, said Francis Pullaro, executive director of RENEW Northeast. 

“The biggest challenge of getting renewables or land-based wind built in Maine has always been the lack of adequate transmission,” Pullaro said, adding that southern New England also desperately needs transmission upgrades to interconnect large-scale offshore wind projects. 

Regarding the NECEC line, the baseload power it will send could end up undermining the development of wind and solar resources in Maine by using up headroom on the existing system and causing more frequent curtailments of renewables, Pullaro said. 

“If the states are going to be investing in new transmission, another line to Canada shouldn’t be the top priority,” Pullaro added. 

While the New England states have long struggled to reach an agreement on how to allocate costs for new forward-looking transmission projects within the region, Pullaro expressed measured hope about recent discussions among the states, ISO-NE and NEPOOL stakeholders over a new longer-term transmission development process. (See NEPOOL Nears a Vote on Order 2023 Compliance.) 

“I think there’s a lot riding on it,” Pullaro said, adding that for years, “we just haven’t been able to get the region to galvanize around internal transmission to benefit our clean energy buildout. And maybe we’ve finally arrived at the moment where this new process can help.” 

Long-term Contracts

While the contracts for NECEC and CHPE will run for 20 and 25 years, respectively, the need for significant additions of clean balancing resources could arise sooner, assuming the states can overcome significant hurdles related to internal transmission and the deployment of offshore wind. 

“In [the] short term, it might be helpful to have the baseload contract, but I think it’s worth raising the question of whether it can be renegotiated in 10 years, for example, to allow for two-way trading,” Dimanchev said. 

While the current contracts will keep the power flowing north-to-south, the NECEC and CHPE lines will be able to operate bidirectionally, although some system upgrades might be needed to facilitate south-to-north transmission. 

Operating the lines bidirectionally would also require new types of contracts or major changes to the existing contracts. 

“It will involve some way of ensuring that one region commits to selling onto the market when prices are at a certain point, whereas the other region [exports] when prices are below a certain point,” Abergel said. “Developing the business model for this new way of doing things is critical.” 

Abergel added that some regulatory changes may also be needed to enable more efficient two-way power flow, pointing to the “considerable” exit fees that apply to power sent from New England to Québec. 

“We have the contracts that we have right now; we’re committed to them; but when we look to the future, working back and forth with our partners and sending energy over the border when needed really is the wave of the future, and that’s what we’ll be working on,” Abergel said. 

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RTOs Jointly Call for Improved Gas-electric Coordination

The four RTOs released a white paper Feb. 21 calling for improvements to the coordination of the electric and natural gas systems to benefit customers of both. 

ISO-NE, MISO, PJM and SPP jointly produced the paper, which includes recommendations that could be tailored to regional specifics along with a few overarching issues that would benefit from national coordination. While the paper calls for additional changes, the RTOs noted that progress has been made, as the grid’s performance in winter storms this January was notably better than earlier events. 

“These more recent experiences underscore the value of better aligning both the purchase of commodity and delivery of natural gas,” the paper said. “If anything, these most recent positive experiences underscore the value of focusing on additional enhancements — building on the work of each of the regions — to better align these two industries. The initiatives suggested herein aim to enhance that coordination, ultimately benefiting customers in both systems through improved reliability and market efficiency.” 

The paper breaks up its recommendations into three broad buckets: gas market enhancements to improve supply and pricing options to ensure a reliable generation fleet as it rapidly evolves; operational enhancements aimed at specific needs; and regulatory coordination of state and federal authorities to address emergencies. 

The recommendations are aimed at different groups including state regulators, FERC, gas pipelines, gas marketers, generators, the ISO/RTOs, the North American Energy Standards Board, the Pipeline and Hazardous Materials Safety Administration, and state and federal lawmakers. 

The report calls for changes like increased transparency in secondary natural gas markets overseen by the states; enhancing weekend and holiday gas supply and liquidity (both from pipelines and any excess sold by local distribution companies); developing additional reserve products in the electricity markets; and addressing emergency authority to address shortfalls either through the Defense Production Act or new legislation. 

The RTOs also call for “targeted permitting reforms,” which have been a hot topic on Capitol Hill for more than a year. 

“However, permitting reforms for transmission versus pipelines are being considered in separate silos that largely ignore the interdependent nature of these two systems,” the paper said. “The electric industry and gas pipeline industry should coordinate so as to better educate policymakers on the interdependencies of these two systems and the need for permitting reform to address these co-dependencies in a comprehensive manner.” 

Targeted expansion of the pipeline system is needed for reliability, the paper said, but faces challenges because of environmental regulations, permitting complexities and local opposition to siting. 

“While the joint RTOs support targeted expansion of the pipeline system, we believe that in the interim, increased reliability of the electric system can be achieved from optimizing both the operation of the existing infrastructure and the liquidity of gas markets,” the paper said. 

Much of the coordination with the gas industry involves working with pipelines; their main trade group, the Interstate Natural Gas Association of America, said it was still reviewing the RTO’s proposal and could not offer specific comments. 

“However, natural gas has a critical role in ensuring electric reliability, and INGAA is committed to working with end users, including [local distribution companies] and electric generation customers, to ensure they have the natural gas they need to keep American homes and businesses running, especially during winter storms,” CEO Amy Andryszak said. 

INGAA worked with the Natural Gas Supply Association and the Electric Power Supply Association to craft recommendations to improve coordination of the two industries that were filed before FERC’s technical conference on reliability last year. (See FERC Conference Highlights Challenges of Evolving Grid.) 

Making the gas system more flexible is important to getting more renewables onto the grid, and the RTOs’ suggestions can help that happen, Michael Jacobs, senior energy analyst with the Union of Concerned Scientists, said in an interview. Renewables will make more and more of the generation stack, but natural gas will still be needed to help balance that, absent advancements in other technology. 

“That actually will require a lot of change in the way the gas pipelines and the gas generators do their business,” said Jacobs. “So, I picture a consolidation of gas pipelines, because we won’t need as many. They need to keep pressure in their system, so they need to have some level of utilization. And so, to do that with fewer pipelines can be more viable than doing it with the same number of pipelines we have.” 

He noted that the RTOs’ paper assigns specific policy changes to the entities that would need to make them, something that has not been done in earlier reports. 

“The four RTOs that put this together deserve some credit for saying those things and putting out an actionable document,” he added. “They still have work to do, but they clearly name other organizations that have work to do. And that’s the kind of thing that’s sort of been missing … this kind of public discussion about how to coordinate across these agencies and deal with the authorities that are needed.” 

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MISO, SPP to Conduct Interregional Study in 2024

MISO and SPP have agreed to conduct another coordinated system plan (CSP) study along their seam this year, as their joint operating agreement requires.  

Five previous studies have failed to produce a single interregional joint project over differences in how to allocate costs. The 2022 study focused on solutions that might qualify as targeted market efficiency projects (TMEPs), a construct MISO and PJM use on their seam. However, no projects met the criteria. (See MISO, SPP Fall Short in 5th Try for Interregional Projects.) 

The MISO-SPP joint operating agreement requires a CSP study at least every two years. 

During an Interregional Planning Stakeholder Advisory Committee meeting Feb. 22, several stakeholders offered suggestions on improving the CSP study process. 

“Even if problems are identified, cost allocation ends up disrupting the ability to actually progress to building projects that might address these issues,” Xcel Energy’s Madeleine Balchan said during the conference call. 

Xcel recommended that instead of looking at two different models and then trying to reach agreement with different sets of numbers, the grid operators look at the historical cost to the market of binding transmission lines along the seam. 

“Everybody can agree on the financial costs that have already happened,” Balchan said. 

“I never really could understand why we don’t hold up historical examples and try to figure out a way to learn from them,” North Dakota Public Service Commission analyst Adam Renfandt said. 

Natalie McIntire, representing the Sustainable FERC Project and Natural Resources Defense Council, urged the RTOs to use a more proactive, comprehensive interregional planning process with an agreed-upon single model and common benefit metrics. She called for employing scenario-based planning that addresses “credible ranges” of uncertain future conditions and a 15- to 20-year planning horizon, given the time it takes to develop multistate transmission. 

Missouri Public Service Commission economist Adam McKinnie drew support for his recommended focus in and around Southwest Missouri, home to numerous congestion issues. He suggested a three-way study among SPP, MISO and Associated Electric Cooperative Inc. The cooperative participates in the Southeastern Regional Transmission Planning process but conducts joint planning with SPP. 

“It seems like it would be beneficial if there was some way that we could get all three of those parties to study that area,” American Electric Power’s Jim Jacoby said. “It has had some severe problems that we’ve seen in past winter storms.” 

Ashleigh Moore, with MISO’s planning coordination and strategy team, said the two RTOs’ staffs will use the feedback to determine the CSP’s scope. Future IPSAC meetings will be scheduled to talk through the process. 

Separately, SPP on Feb. 22 filed a new revision request (RR620) to implement cost-allocation policies already approved by the RTO’s Regional State Committee for the Joint Targeted Interconnection Queue (JTIQ) project with MISO. The rule change would memorialize and define how the JTIQ would be deployed and applied once executed and is coordinated with changes to the JOA. 

SPP’s Clint Savoy said once RR620 is filed at FERC, staff will be able to work with MISO on TMEPs projects. 

Comments on RR620 are due by the close of business March 14. 

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Insurer: Majority of BESS Failures are in First Two Years

An insurer specializing in renewable energy infrastructure reports that battery energy storage system (BESS) failures are ramping up with the spread of the technology, and most often occur in new systems. 

It calls for developers and operators to take steps including creating spacing standards for units within a BESS, conducting comprehensive root cause analyses of failures, establishing a liability framework within the market and involving manufacturers through the entire project lifecycle. 

GCube issued the report, “Batteries Not Excluded: Getting the Insurance Market on Board with BESS,” on Feb. 21. CEO Fraser McLachlan said insurers experience uncertainties in supporting coverage for the rapidly expanding market.  

“GCube is a pioneer in the BESS field, and has learnt the hard way, having handled some of the largest losses in the market to date,” he said in the announcement of the report, which is designed to reduce market uncertainty. 

The report draws on details of 63 publicly reported failures. Among the findings: 

    • Systems rated at 5 to 50 MWh accounted for more than half of the failures and those rated at less than 5 MWh accounted for about a third. 
    • Solar-plus-storage installations accounted for 48% of reported failures; while this may be due to the frequency of such pairings, it also may point out challenges and risks created by pairing two complex systems. 
    • Nearly half the reported failures were in South Korea and nearly a third in the United States; this is likely due to the large number of systems in the two countries and the diligent reporting in both. 
    • Systems in their first year of operation accounted for 38% of recorded failures and 21% occurred within the second year. 

This last statistic is a red flag — GCube notes that the BESS failure rate within the initial operation phase is markedly higher than seen in other energy systems. 

“The high incidence of failures within the first two years of operation poses a serious cause for concern, warranting a closer examination of the potential ramifications if this trend continues,” the report warns. 

A report issued earlier in February flagged the same phenomenon from a different perspective: Engineering services firm Clean Energy Associates noted that 18% of its BESS factory quality control audits found issues with thermal management systems and 26% found faults with their fire detection and suppression systems. (See Engineering Firm Finds Quality Problems in BESS Manufacturing.) 

GCube said the risk as BESS systems get progressively larger is that failures will cause progressively larger damage, increasing the losses incurred by developers, operators and insurers. 

The 2012 fire at the First Wind/Xtreme Power wind-storage facility in Hawaii underwritten by GCube resulted in a $27 million loss, and that was only a 15-MW battery bank — a small fraction of the capacity of some of the BESS installations being planned and built. 

“We don’t want to repeat the mistakes of the past of allowing growth in deployment and technological scale to take priority over quality control, and the large-scale losses and market destabilization that result from that,” McLachlan said. 

Energy storage is a linchpin of the clean energy transition, and its rapid buildout reflects this. Batteries vastly outnumber other forms of storage. GCube expects that by the end of this year, BESS will account for as much as 30% of the asset value in its insured portfolio, which now exceeds 100 GW capacity. 

“Among the main challenges of BESS underwriting is the scarcity of data and insights on how BESS works, performs and fails,” McLachlan writes in the introduction to “Batteries Not Excluded.” 

“Consequently, underwriters continue to exercise caution when it comes to BESS technologies. While market data is limited, we must begin harnessing what information is presently available to start unravelling the risks and prospects associated with this nascent technology.” 

Beyond the financial and physical dangers of BESS failures, the sense of unknown danger stokes public opposition to installation of these facilities. (See Battery Storage Developers Bump Against Perception of Risk.)  

Jurisdictions such as New York state are moving to address the threat to public safety and perception by quantifying and reducing those risks as much as possible. (See NY Fire Code Updates Recommended for BESS Facilities.) 

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Entergy Highlights Data Center and Industrial Load Growth in Q4 Earnings

Executives focused on Entergy’s booming industrial load growth during a year-end earnings call Feb. 22.  

Entergy CEO Drew Marsh said that Entergy companies signed 61 new electric service agreements in 2023, representing 1.3 GW in capacity. 

“Data centers are a hot topic and, as you know, we’ve seen interest in our service area,” Marsh said, noting Amazon’s $10 billion arrival in Mississippi and Gov. Tate Reeves’ (R) signing bills in late January to authorize the data center investment along with $44 million in state incentives.  

Entergy has framed the Amazon Web Services data centers as a win for the state and touted its role in recruiting the company to the location. 

Marsh predicted “very strong growth” among Entergy companies going forward, due in part to new natural gas, blue hydrogen and EV battery production projects. 

“In addition to the data centers, our growth story continues to develop and diversity,” Marsh said, adding that Entergy has a “unique industrial growth opportunity in front of us.”  

Entergy’s load growth has been responsible in part for an unprecedented number of expedited project requests to MISO for transmission facilities. (See MISO to Re-examine Schedule for Reviewing Expedited Tx Projects.) 

Marsh said Entergy companies are pursuing loans and grants from the U.S. Department of Energy to offset the costs of much-needed grid upgrades. He said Entergy companies have applied for loans totaling $4.7 billion “for a variety of projects related to the clean energy transition” and have submitted eight preliminary proposals under DOE’s Grid Resilience and Innovation Partnership program. 

Entergy plans to invest $20 billion over the next three years to “make our fleet cleaner, to make our system more reliable and resilient,” Marsh said. That amount includes $11 billion in transmission construction, including big-ticket projects from MISO’s 2023 Transmission Expansion Plan. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.) It also includes $8 billion in new generation, including the more-than-$1 billion, 1.2-GW Orange County Power Station in southeast Texas and $2 billion for solar installations. 

Marsh said despite record-breaking heat last summer, Entergy achieved its lowest forced outage rate since 2011. 

“Not only did we meet our customers’ demands, but we also exported power to other utilities in MISO in the moments that mattered,” Marsh said. 

Marsh said Entergy’s year-end earnings of $1.4 billion ($6.77/share) signified “steady, predictable results.” Earnings over 2023 were slightly higher than 2022’s $1.3 billion ($6.42/share).  

Entergy CFO Kimberly Fontan said, “weather was a benefit for the year,” with an exceptionally hot summer boosting financial performance. 

Fontan said 2023’s retail sales volume was relatively flat overall, with industrial growth offset by a decline in residential and commercial demand. 

However, she said, industrial sales were not as “robust” as Entergy anticipated in the fourth quarter, although the utility remains optimistic about growth propelled by large industrial customers specializing in metals, gases and petrochemicals.  

“We continue to be confident in our industrial growth expectations, as sector margins and commodity spreads remain strong. And we continue to grow our backlog of signed electric service agreements,” she said.