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April 7, 2025

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CAISO CEO, Others Point to Reliability Aspect of BPA’s Market Decision

BPA’s day-ahead market decision will have “major reliability and affordability impacts” on electricity customers in the Northwest and across the West, CAISO CEO Elliot Mainzer said in a report to the ISO’s Board of Governors. 

Mainzer’s statement came after BPA issued a draft policy saying it intends to join SPP’s Markets+, the market competitor to CAISO’s Extended Day-Ahead Market (EDAM). (See BPA Selects SPP Markets+ in Draft Policy.) 

As BPA approaches its final market decision in May, energy leaders and experts in the West are focusing on potential reliability issues should the agency choose Markets+ over EDAM. 

“We’ve seen a lot of changes in the last decade in the West, with gas plant retirements and a rapid rise in solar generation in California,” Fred Heutte, senior policy associate at the Northwest Energy Coalition, said in an interview.  

“Coordination between Bonneville and CAISO has been critical in this decade, especially when things get really tough, like under extreme weather conditions. We depend on transmission and strong coordination in the region to keep the lights on,” Heutte said. 

One central concern is that BPA could choose a different reliability coordinator under the Markets+ option. BPA currently relies on CAISO’s RC West as its reliability coordinator, but could switch to SPP’s reliability coordinator, Western RC Services, BPA’s draft policy says. 

“Then the region will have two coordinators,” Heutte said. “How they will work together, especially when demand is high, needs to be thought about in more detail.” 

Having multiple non-contiguous reliability coordinators and market operators in the Pacific Northwest “will pose many operational and commercial challenges,” BPA’s draft policy acknowledges. 

Switching reliability coordinators could come at a price: BPA’s draft shows the total internal implementation cost of Markets+ could be between $53.7 million and $74.2 million, whereas the cost for joining EDAM ranges from $29.9 million to $38 million.  

Estimated internal implementation costs of market options | BPA

The higher cost estimate for Markets+ is driven in part by an assumption that BPA switches its RC from CAISO to SPP, the draft policy says. While BPA’s draft included the estimated costs for changing RCs for transparency, the agency isn’t certain it will make the change, which will depend on future policy development, the document says.  

In an email to RTO Insider, BPA spokesperson Doug Johnson noted that Markets+ comes with higher upfront costs, while production cost modeling analysis done for the agency shows lower revenue in Markets+ compared to EDAM. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.) 

However, Johnson added, the ongoing participation fees “suggest that these upfront costs could level out over time between the two markets, with Markets+ showing potential for significantly lower market operating costs over the long-term. While EDAM’s implementation fee is quite low at $3 million, the recurring annual fee is double that of Markets+.” 

WRAP Key Factor for BPA

From a resource adequacy standpoint, both day-ahead market options include an evaluation for resource sufficiency. BPA said it prefers the design in Markets+, primarily because the SPP also includes a long-term RA requirement, the agency said in its draft policy. 

Markets+ includes a standardized resource adequacy requirement in which all load responsible entities must participate in the Western Resource Adequacy Program (WRAP) administered by the Western Power Pool, while CAISO’s EDAM does not include any such requirement. 

“While the CAISO BAA has its own RA framework, this framework is not extended to other entities outside of CAISO’s BAA in general,” the draft says. “Bonneville believes that Markets+ requiring participation in WRAP, a standardized RA framework, will better meet this [RA] principle.” 

Regardless of its market decision, BPA will be responsible for its system’s reliability, and will do so by acting as transmission planner, balancing authority and transmission operator. BPA will remain responsible for compliance with applicable NERC reliability standards as well. This is because day-ahead markets and market operators do not assume any of the reliability roles of a utility — as in a full RTO, the draft says. 

‘Valued Partner’

In an email to RTO Insider, Mainzer didn’t elaborate on his comment about the reliability impact of BPA’s decision, but reiterated his support for the agency and its ongoing market decision analysis.  

“BPA has been a valued partner to the CAISO for many years and played an essential role in the development of the Western Energy Imbalance Market (WEIM),” Mainzer said. “There is a seat at the table for BPA to remain an active member and architect of a broad, electrically connected energy market that will build on our shared success with WEIM.” 

Irrespective of how BPA ultimately chooses to proceed, CAISO will maintain focus on EDAM implementation and providing technical support to the West-Wide Governance Pathways Initiative (which is working to bring more independent governance to CAISO markets), Mainzer said in his CEO report.   

“We are proud of the fact that the EDAM market design was crafted through an extensive and transparent process with a wide variety of stakeholders before being approved in full by FERC last year,” he said in the report. This message is “a reiteration of the message that … CAISO and many others in the Northwest have been conveying to BPA over the past year,” Mainer told RTO Insider. 

WECC also is following the formation of both day-ahead markets, Kris Raper, the reliability organization’s vice president of strategic engagement and external affairs, told RTO Insider.  

In general, WECC supports the current developments because market structures allow for more effective and efficient dispatch around transmission constraints — leading to a more reliable system, Raper said.  

“However, it is not WECC’s role to evaluate what market, if any, would be better for a utility to join. That said, as a partner in the Western Interconnection with a mission to mitigate risks to reliability, we [will] address any concerns about reliability as the conversation evolves and the markets develop,” Raper said. 

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Data Center Campus with up to 4.5 GW of Gas Generation Planned for Pa.

A data center campus planned in western Pennsylvania would include up to 4.5 GW of on-site gas-fired generation and be the largest facility of its kind in the U.S., a group of developers announced April 2. 

The 3,200-acre Homer City project would stand on the site of what had been Pennsylvania’s largest coal-fired plant, a 1.88-GW facility decommissioned in 2023. 

The effort brings together GE Vernova, Kiewit Power Constructors and Knighthead Capital Management. It carries a price tag expected to surpass $10 billion — not counting the data centers themselves, which would cost billions more. 

Homer City Redevelopment (HCR), which is leading the effort to restore the site to economic productivity, said it would be the largest investment of its kind in state history and is expected to start producing power by 2027. 

HCR indicated that many of the components already are procured for the project, limiting the chances of supply-chain delays. GE Vernova will deliver the first of seven hydrogen-enabled gas-fired turbines in 2026, for example. And critical infrastructure remains in place from the coal-burning plant, including transmission lines to the PJM and NYISO grids, substations and water access. 

There also is the nearby Marcellus Shale formation, one of the most productive U.S. sources of natural gas. Pennsylvania is the No. 2 gas producer in the U.S., after Texas. 

Not discussed in the announcement is the typically slow pace of interconnection and the controversy surrounding co-located large loads. 

“We are fully aware of the project and recently met with the developers,” a FirstEnergy spokesperson told RTO Insider. “We are working closely with them to determine the necessary steps and milestones for them to move ahead with their plans for the site. FirstEnergy is committed to helping to improve the economies of the communities we serve, and we are eager to work collaboratively with the right parties to achieve their visions.” 

A spokesperson said PJM would not comment in detail without seeing more specifics. New resources are important in an era of increasing demand and tightening supply, they said, and the Homer City proposal would be well situated. 

Comeback Planned

When it was built in 1969, the Homer City Generating Station became a physical and economic standout in the rural region 40 miles east of Pittsburgh, providing jobs and boasting a smokestack variously described as the tallest in the state or in the U.S. 

But it ran into regulatory and financial problems as coal-fired generation fell out of favor, and it finally shut down July 1, 2023. The smokestacks and cooling towers recentlywere leveled with explosives. 

The gap of years between shutdown of the old plant and startup of the new plant may factor into the interconnection process. Generation owners can request the capacity interconnection rights held by a retiring resource be transferred to another queue project for up to one year after the unit shutters. That window already has closed. 

The other pathway for new projects to make their way quickly through PJM’s interconnection queue would be by participating in the RTO’s one-off Reliability Resource Initiative, which will allow 50 projects to be added to the Transition Cycle 2 study cluster. PJM said in March it had received 94 applications for the program and will winnow those down to 50 based on several characteristics, including nameplate capacity, in-service date and location. 

Meanwhile, the PJM spokesperson said the issues surrounding large-load co-location await clarification by FERC. PJM recently submitted comments to FERC in the matter in which it expressed reservations about large co-located load configurations participating behind the meter (EL25-49). (See PJM Responds to FERC Co-located Load Investigation.) 

The RTO said its BTM rules were designed for smaller configurations, such as warehouses with on-site solar generation. PJM proposed several configurations that are permissible under the current rules while floating others the commission could consider exploring. 

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ISO-NE’s van Welie Discusses Congressional Testimony with NEPOOL

In a rare address to the NEPOOL Participants Committee on April 3, ISO-NE CEO Gordon van Welie discussed his recent testimony at the U.S. House Energy and Commerce Subcommittee on Energy, emphasizing the important role that states play to reduce price volatility in the wholesale markets.

Representatives of every ISO and RTO testified to Congress on March 25 about grid reliability. (See All 7 ISO/RTOs Send Senior Executives to Update Congress on Reliability.) Van Welie spoke about New England’s pipeline constraints, the value of offshore wind and the importance of “alignment between federal and state policies.”

Much of van Welie’s time in Washington was spent responding to antagonistic questions about renewables. In his written testimony submitted to Congress and addressing the PC, van Welie stressed that markets alone cannot guarantee resource adequacy and urged the New England states to hedge against high market prices.

While ISO-NE’s wholesale markets “are essentially short-term ‘spot’ markets,” van Welie wrote, the states can enter long-term contracts “to protect consumers against undue price volatility in both the energy and capacity markets, and to incent the development of sufficient resources to meet the resource adequacy standard that is priced in the capacity market.”

States have an important role in reducing the barriers to entry for new resources, he said. He acknowledged that recent federal policy changes — including antagonism towards offshore and onshore wind and new tariffs on imports — create significant challenges for renewable energy development.

“Over the past few weeks, we have seen firsthand the impact that shifts in federal policy can have on our region,” van Welie wrote. “If the large amount of offshore wind that has been contracted for by the states is significantly delayed or ultimately does not materialize, the region would need to assess the potential impacts and determine what other options might be needed to meet resource adequacy needs in the future.”

If the struggles of offshore wind development continue, the region could pursue an increase in the dual-fuel capabilities of its gas fleet, or an increase of its gas pipeline import capacity, van Welie said. However, he noted that increasing gas capacity into the region likely is not a short-term solution. Increased pipeline capacity would reduce the constraints that contribute to high gas prices in the region but would come at a significant upfront cost and could create risks of stranded costs as the New England states eye a long-term shift away from natural gas.

One stakeholder referenced a 2017 study by Synapse Energy Economics that found a proposed Enbridge pipeline intended to reduce the region’s gas constraints would cost about $6.6 billion, a price tag that likely would be significantly higher today, given the increased costs of large infrastructure projects.

Operations Report, Votes

Also at the PC meeting, ISO-NE COO Vamsi Chadalavada reported that energy market revenue totaled $456 million in March, up from $256 million in March 2024. The increase corresponded with significantly higher average natural gas prices compared to March 2024.

The monthly peak load was 17,200 MW, and there were no capacity deficiency events to report.

Power system emissions have trended up so far this year relative to 2024, largely because of lower temperatures across the region.

The committee voted to approve the consent agenda, which included tariff changes intended to improve its economic study process and changes to the ISO-NE operating procedure concerning protection outages settings and coordination.

It also approved a slate of three candidates for the ISO-NE Board of Directors. The slate now goes to the board for approval.

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Asthana, Vegas to Headline ERCOT’s Innovation Summit

ERCOT said April 2 that PJM CEO Manu Asthana will join its own CEO, Pablo Vegas, in opening the grid operator’s second annual Innovation Summit on May 6 in Round Rock, Texas.

The two chief executives will discuss how their organizations and others are adapting to and managing the complexities of “rapidly changing grids” in an opening “Energy Insights” conversation during the summit.

ERCOT said the summit will bring together leaders to share ideas and technology advancements and to collaborate on innovative solutions facing grid transformation in Texas and across the country.

The agenda includes ERCOT’s grid-transformation initiatives and panels on data center interconnection, demand response, probabilistic planning methods and industry innovation in other ISOs and RTOs.

“I am excited to join colleagues at the Innovation Summit to explore how we can collectively maintain reliability during rapidly evolving industry dynamics,” Asthana said in a press release.

Ballooning load from data centers has been at the heart of stakeholder discussions and capacity market redesigns at PJM in recent years. The RTO has made changes to its process for transmission owners to submit large load additions and is working with stakeholders to revise its effective load-carrying capability probabilistic modeling of the intersection between system risks and generation accreditation. (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.)

Registration closes April 18.

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NERC Warns Many Inverters’ Information Not Up to Date

NERC will have to issue its highest level of alert to address shortcomings revealed in a recent information request about inverter use, the ERO said in a report issued April 1. 

A Level 3 alert indicates specific steps deemed essential for certain stakeholders to ensure reliable grid operation. The ERO has used it only once before, to set out “essential actions” for utilities to prepare for cold weather in 2023. (See NERC Board May Force Action on Cold Weather Standard.) Issuing a Level 3 alert requires approval from NERC’s Board of Trustees. 

The Aggregated Report on NERC Level 2 Recommendation to Industry summarizes the findings from a Level 2 alert sent to stakeholders in June 2024, inspired by concerns over inverter-based resources and related modeling practices after a series of grid disturbances in recent years involving such generators. (See NERC Targets IBR Modeling Concerns in Level 2 Alert.)  

NERC directed the alert at generator owners (GOs), transmission planners (TPs) and planning coordinators (PCs). GOs that own grid-connected IBRs were required to provide a range of information about them, including:

    • manufacturers of inverters on their systems;
    • model numbers for their inverters and their quantity;
    • nameplate ratings for each model of inverter;
    • inverter- and plant-level voltage and frequency protection settings;
    • inverter- and plant-level reactive power capabilities and control information;
    • model types used to represent facility model data to TPs and PCs; and
    • dynamic and load-flow model files for each facility.

NERC also provided a series of questions for IBR owners, TPs and PCs including whether their organizations have publicly available model submission and quality requirements, what type of generator models are permitted during the interconnection process, and how the organizations verify accuracy of their models. 

The ERO said stakeholder feedback indicated “GOs do not keep the requested data and information readily available and up-to-date and are reliant on [original equipment manufacturer] and consultant support” to provide the information when requested. Not only does this make event analysis more difficult, it calls into question the quality of planning data submitted by GOs. 

GOs’ responses to the question about generator models revealed an overwhelming majority, 78%, submit only standard library models to their TPs and PCs. 15% submit manufacturer-specific models, and only 7% submit both — despite the fact “NERC guidance and FERC Order 2023 indicate that both should be submitted.” 

The top five IBR manufacturers represent more than 83% of the North American fleet by MW. | NERC

A majority of GOs indicated they have publicly available model submission and quality requirements, and believe their requirements align with NERC’s dynamic modeling recommendations. But only 16% of GOs said they require equipment-specific, user-written positive sequence phasor domain generator models to be submitted for interconnection studies, while a slim majority — 97 out of 190 respondents — said they do not require submission of equipment- and site-specific electromagnetic transient (EMT) generator models during the interconnection process. 

78% said they perform EMT model verification, and 70% indicated they do not integrate EMT models into generator interconnection studies. 81% said their organization lacks the tools and personnel to effectively perform EMT analysis. 

The question about inverters’ origins revealed that five original equipment manufacturers account for about 74% of the inverter fleet by generation capacity, and 83.1% by number of inverters. Although the Level 2 alert did not mention cybersecurity concerns, the dominance of a small number of manufacturers has caused concern in the cybersecurity community because inverters produced by the same company may share common vulnerabilities that make infiltration and sabotage easier. 

NERC has not said what would be in a potential Level 3 alert, but the ERO emphasized that it would contain “only voluntary essential actions, [with] the mitigation of risk … left up to individual stakeholders.” 

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ISO-NE Releases Longer-term Transmission Planning RFP

ISO-NE has published the request for proposals for its first longer-term transmission planning (LTTP) procurement, which is focused on increasing North-to-South transmission capacity in New England and interconnecting onshore wind resources in Northern Maine.

The March 31 RFP is the culmination of months of work between ISO-NE, the New England states and stakeholders from across the region, and it could set the precedent for future procurements to meet anticipated transmission needs. (See FERC Approves New Pathway for New England Transmission Projects.)

The main objectives and requirements of the RFP were established by the New England States Committee on Electricity (NESCOE) in December. (See ISO-NE to Work on State-backed RFP for Northern Maine Transmission.)

NESCOE defined the objectives as “strengthening the connection between northern and southern New England,” and “facilitating the integration and deliverability of additional affordable generation resources located in Maine.”

At a minimum, proposed projects must increase the transfer limit of the Maine-New Hampshire interface to 3,000 MW, the limit of the Surowiec-South interface to 3,200 MW and establish new infrastructure in Central Maine to facilitate the interconnection of 1,200 MW of onshore wind. The RTO wrote that applicants could propose upgrades that go beyond the minimum requirements.

The Maine-New Hampshire interface currently has a transfer limit of 2,000 MW, and the Surowiec-South interface has a limit of 1,800 MW.

“All three of these needs must be addressed by Dec. 31, 2035, unless a QTPS [qualified transmission project sponsor] respondent can demonstrate supply chain issues that warrant a later in-service date,” ISO-NE wrote in the RFP.

The two interfaces were identified as high-likelihood concerns in ISO-NE’s 2050 Transmission Study. The focus on onshore wind is driven by its significant potential for low-cost renewable energy production in Northern Maine. (See Long Road Still Ahead for Aroostook Transmission Project.)

The deadline for project submissions is Sept. 30. ISO-NE expects to take about a year to evaluate proposals and select a preferred solution.

Applicants will be required to submit a $100,000 deposit, which will be used to cover study costs. Project sponsors can submit solo or joint proposals, but all proposals must be complete solutions. ISO-NE plans to publish a summary of every proposal received for the RFP.

The RTO wrote that project developers can include in their proposals “corollary upgrades” to infrastructure in the service territory of a different participating transmission owner (PTO).

“As part of the corollary upgrade, the PTO may install new facilities only to interconnect the QTPS respondent’s longer-term proposal to the PTO’s existing transmission system. Any other corollary upgrades must only be upgrades or replacements of existing facilities,” ISO-NE wrote.

The RTO noted that corollary upgrades could include “reconductoring an existing line, rebuilding an existing line, rebuilding a single existing circuit in a double-circuit configuration … multiple-circuit tower separation, operating voltage changes or replacement of circuit breakers with higher-rated breakers.”

Other than infrastructure to interconnect the project, applicants cannot propose new infrastructure in another TO’s service territory without an agreement or joint proposal with the TO.

To screen proposals, ISO-NE will perform steady-state, stability and short-circuit analyses, as well as a transfer analysis “to confirm that the required minimum interface capabilities on the Maine-New Hampshire and Surowiec-South interfaces in the future year are met.”

The RTO also will conduct energy and capacity tests to assess whether the solution will facilitate the required onshore wind interconnection.

If a project passes all the screening tests and meets all the requirements, ISO-NE will conduct a cost-benefit analysis, calculated based on “an independent capital cost estimate, using a consistent capital cost estimating methodology, to ensure consistency in its review of the longer-term proposals and their cost estimates.”

To be eligible for selection, the cost-benefit analysis must show that the project would provide the region with net cost benefits. If no projects pass this threshold, one or more states could opt to cover the costs that exceed the benefits.

The analysis will include capacity expansion, production cost and resource adequacy models to calculate benefits, which it will evaluate over a 20-year period after a project’s in-service date.

ISO-NE also will calculate the benefits of avoided transmission investments “based on the extent to which the project eliminates the need for projects already included on the [Regional System Plan] project list, replaces assets that are already planned to be replaced due to asset condition and included on the Asset Condition List, or replaces assets that are likely to be replaced due to equipment age.”

For all projects that pass the cost-benefit threshold, ISO-NE will “holistically” consider both quantitative and qualitative factors to select the preferred solution. The highest-priority factors in this evaluation will include life-cycle costs, cost-containment provisions, permitting challenges, potential to interconnect additional resources and incorporate future needs, and impacts on system performance.

Lower-priority factors will include operational, environmental and winter reliability impacts, project constructability, and the use of advanced transmission technologies.

ISO-NE will present its preliminary preferred solution to the Planning Advisory Committee for feedback. After ISO-NE posts the preferred solution, NESCOE will have the opportunity to terminate the process or submit an alternative cost allocation methodology.

In a press release, Advanced Energy United wrote that the RFP “demonstrates that with the right planning and collaboration, we have the will and means to build the transmission infrastructure necessary to power a clean energy future,” adding that “it is critical to ensure that this RFP results in well vetted, competitively sourced projects getting built quickly to bring net benefits to New England.”

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Brattle Report Stresses Need for Southeast Regional Tx Plan

A new Brattle Group report spotlights the Southeast as the only major U.S. region without thorough transmission planning and recommends it develop a portfolio of projects or risk failing to keep up with the times.  

The April 2 report — prepared for the Carolinas Clean Energy Business Association, Clean Energy Buyers Association and the Southern Renewable Energy Association (SREA) — concludes “the status quo approach for planning and building the future region-wide Southeast grid is insufficient” to meet load growth and growing reliability risks brought on in part by weather extremes.  

“Transmission development today is driven by utilities planning their systems in isolation, focusing primarily on their service areas (or in some cases the joint network within a state) instead of taking a broader, regional approach to grid expansion,” authors J. Michael Hagerty, Peter Heller and Evan Bennett write. They asked Southeastern utilities to “think larger and embrace regional solutions that supplement utility-specific upgrades.”  

The Brattle report says a bolder planning approach is a must, especially since meaningful regional transmission projects have failed to materialize for more than a decade through the utility-created Southeastern Regional Transmission Planning Process (SERTP). It concludes that recent Southeast transmission projects conceived separately by utilities or even small groups of utilities such as the Carolinas Transmission Planning Collaborative and the Georgia Integrated Transmission System are lacking.  

“Without a regional, forward-looking strategy that maximizes the value of transmission investments, Southeast utilities risk inefficiently investing in lower-value local reliability projects within their respective systems, resulting in rising transmission rates without achieving the greatest return on their transmission investments,” the authors said. “Instead of maintaining existing systems, utilities should prioritize regional upgrades that supplement necessary local reliability upgrades and support a reliable grid, new energy generation and long-term load growth.”  

In an April 2 webinar to review the report, Hagerty pointed out that the Southeast’s big players — Southern Co., Duke Energy, Louisville Gas & Electric and Kentucky Utilities Co. — have quadrupled spending on local transmission needs since the early 2000s, when they collectively spent about $500 million per year. Now, those utilities have spent nearly $2 billion annually in the past five years. He and the two other report authors said the spending mostly was to replace aging infrastructure, connect new generation and support “moderate” load growth.  

The report warned that conducting transmission planning largely in isolation leads to missing out on opportunities to build larger, more cost-effective projects and their resilience benefits.  

The report said a $5 billion investment in three 500-kV lines that SERTP evaluated in 2024 could save $2.9 billion conservatively on production costs, $3.3 billion on load diversity and $1.6 billion on resilience benefits. However, the report said SERTP adopted an “overly narrow view of cost savings” and found no benefits of increased transfer capability among Duke Energy, Southern Co. and the Tennessee Valley Authority due to the three major upgrades.  

However, the report said the Carolinas Transmission Planning Collaborative’s in-progress Multi-Value Strategic Transmission Study could show promise for the two states and be replicated on a larger scale in the region.  

‘Lifelines’ for SERTP

SREA Executive Director Simon Mahan said the Southeast’s unprecedented projected load growth means new transmission “lifelines” are necessary. Without them, the Southeast grid risks higher energy costs and reliability disruptions.  

“At the end of the day, lives are on the line without enhanced transmission solutions,” Mahan said.  

Lead author Hagerty said by 2035, the Southeast’s electricity demand is expected to rise by 25% to 21 GW. He and the other authors noted that amount is similar to a doubling of New York City’s demand, and said the Southeast will need regionally planned transmission to connect the estimated 80 GW in new generation to keep up while maintaining reliability.

Hagerty said SERTP planning is inadequate to take on the modern needs of the Southeastern grid. The report criticized SERTP’s planning structure — composed of 10 sponsor utilities from 12 states with no independent staff — as too narrow to be effective. Mahan said the process, which isn’t open to the public and state regulators aren’t involved in, is mysterious.  

Hagerty also said SERTP’s single model doesn’t produce a realistic future resource mix and the group should reach out to states to get a better view of future generation.  

“The proof is in the pudding,” Hagerty said, adding that over the last 11 years, SERTP hasn’t proposed a single regional upgrade. He said the process is “unlikely to support the investment needed in the Southeast” as demand rises and that a lack of regional planning would correlate with higher costs, delays in serving new load and reliability troubles as more extreme weather stresses the grid.  

Carolinas Clean Energy Business Association Executive Director Chris Carmody said Southeastern utilities are building “very tall silos” of new generation that could burden ratepayers with higher costs.  

“Without transmission, it’s going to be dressed up with nowhere to go,” Carmody joked. He said the Southeast should adopt Eisenhower’s attitude when trying to get the interstate highway system built.  

Carmody added that “one weather event after another” seems to strike the Southeast, and regional transmission could stand in for hard-hit areas that lose service on lines.  

The report said FERC’s Order 1920 could provide the Southeast with an opportunity to create proactive planning that exceeds the federal rule’s parameters. SERTP could use the multi-value and scenario-based planning that exists in other planning areas in the country and incorporate load forecasting to land on portfolios of transmission solutions or even interregional projects, it said.  

Hagerty said the Southeast should view Order 1920 as a “floor” and go beyond the rule’s requirements for an even more dependable grid.  

The Brattle report asked SERTP to shed more light on its planning and share input assumptions, study results and project costs publicly. It also recommended SERTP adopt a “beneficiary pays” method for cost allocation of regional lines.  

Carmody said Southeast utilities should ignore the instinct to build up their islands and work together to avoid leaving their systems vulnerable or missing out on a new manufacturing plant. He said utilities can either choose to continue driving a 1950s Rambler or “accept that that’s not going to be safe or efficient for us” and make investments.  

“Proactive transmission planning supports a growing economy,” Clean Energy Buyers Association’s Katie Southworth added.

SREA previously criticized SERTP’s planning and said Order 1920 could nudge SERTP “away from a process that studies regional transmission lines to justify not building them.”  

SERTP did not respond to RTO Insider’s request for comment on whether there is room for improvement in its regional planning or its still-developing plans to comply with Order 1920.  

Recent calls for stronger transmission planning in the Southeast also extend to MISO South.  

Stakeholders at MISO’s Board of Directors Week in March lined up during a public comment period to ask the RTO to engage in long-term planning in the RTO’s South region. While MISO has designated two long-term portfolios at a combined $32 million in the Midwest, grid planners have yet to prescribe any long-term projects for the South region. (See MISO Fields Divergent Calls for Stronger South Planning, IRA Reversal in Tx Futures.)  

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NY Floats Initial Grid of the Future Plan

New York on March 31 issued the first iteration of a plan to move the state toward greater use of flexible resources to meet future power needs while preserving reliability and affordability.

The plan is part of the Grid of the Future proceeding (Case 24-E-0165) initiated by the Public Service Commission in April 2024. (See NY PSC Launches Grid of the Future Proceeding.) It is intended to guide development of a more expansive process for distributed system implementation plans (DSIPs) prepared by the six investor-owned utilities as they implement a distributed system platform (DSP). The second iteration of the plan is expected by the end of this year.

Earlier this year, as part of the same effort, Volumes 1 and 2 of the Grid Flexibility Study prepared by The Brattle Group were released by the Department of Public Service and New York State Energy Research and Development Authority. (See Study Finds Considerable ‘Grid Flexibility’ Potential in New York.)

The First Iteration of the Grid of the Future Plan was prepared by DNV Energy Insights USA and was released along with Volume 3 of Brattle’s Grid Flexibility Study, which provides supplemental analysis.

A central goal of the Grid of the Future proceeding is to meet the state’s ambitious clean energy goals at a manageable cost while maintaining system reliability. Flexible solutions such as distributed energy resources and virtual power plants are potential means to accomplish this.

The plan seeks to develop a DSIP process better aligned with the Grid of the Future proceeding, and to provide short- and long-term recommendations to ensure that DSIP filings are aligned with the state’s 2030 and 2040 goals.

After a series of reviews, DNV offered several conclusions:

    • The DSIPs as currently prepared do not provide outcome- or goal-oriented information and do not contain clear objectives or metrics, so it is difficult to assess whether a utility is progressing toward a functional DSP.
    • Reporting, detail and organization are inconsistent among the DSIPs, and some answers to complex questions are incomplete; collective action among the utilities resulted in more comprehensive answers.
    • New York’s regulatory environment is not an undue obstacle to development of a DSP; instead, the most significant headwinds are grid investment costs and market design, which hinder efficiency and slow adoption. The most significant tailwinds are data access and standardized interconnection requirements.
    • Some of the capabilities critical to a DSP are fully deployed and integrated but many have not been automated, are not well-integrated or are not deployed utility-wide.

DNV offered recommendations along the themes of reorganization, clarity and standardization:

    • Department of Public Service staff should clarify their guidance to utilities to elicit clearer and more consistent responses, and to reduce the inconsistencies between DSIPs.
    • Multipronged questions should be eliminated; content organization should be prescribed; and explicit expectations about answers should be offered.
    • Technical topic areas can be further streamlined and reorganized to better reflect the evolving needs of a DSP.

DNV also offered recommendations to transform the DSIP process from a regulatory check-in to a strategic tool to guide utilities, regulators and stakeholders:

    • Future versions of the DSIPs could focus on the value and intended outcomes of the processes and activities rather than just documenting them, and could include specific metrics to track progress.
    • More detailed and streamlined guidance that includes standardized templates and metrics would make DSIPs more consistent and digestible, as well as easier to compare.
    • Addressing gaps identified by the capabilities in the DSP framework will ensure DSIPs are comprehensive; including a focus on market design and implementation will allow reporting on grid edge capabilities.

The authors expect the Second Iteration of the Grid of the Future Plan to provide more specific recommendations. It is due to be released by Dec. 31, although the First Iteration and the Grid Flexibility Study both were delivered after their original target dates.

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NYPA to Buy Former Power Plant Site for $206M

The New York Power Authority plans to buy a New York City site where a power plant once stood and reuse it for clean energy infrastructure. 

The state-owned entity is working to expand its generation and transmission portfolio as part of New York’s long-term efforts to generate more electricity with less carbon emissions. 

The 15.7-acre site in Astoria, near the waterfront in the northwest corner of Queens, could support that initiative: It is adjacent to existing NYPA assets, zoned for utility infrastructure and situated within a load pocket. 

NYPA’s Board of Trustees in late March approved its purchase for $206 million; the deal is expected to close in June. 

The recent history of the site reflects the changing nature of New York’s power portfolio. 

A subsidiary of NRG Energy sought to refurbish its aging 558-MW peaker plant with a new 437-MW turbine but was denied permission by state regulators, who determined the move would not comply with greenhouse gas emission limits. (See New York Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits.) 

So instead, NRG decided to demolish it and sell the land to an entity created by bp and Equinor. (See NRG to Demolish Astoria Plant, Sell Site to OSW Firm.) They planned to build the Astoria Gateway for Renewable Energy there, as a landing site for electricity from their Beacon Wind project. 

But Beacon Wind ran into economic trouble in 2023 and canceled its New York offtake contract. Equinor and bp dissolved their partnership, with bp taking full ownership of the Astoria site. 

More recently, bp withdrew its request for state authorization of the Beacon Wind export cable. A spokesperson noted that New York now is considering coordinated offshore transmission for multiple projects, an approach the company supports. (See Beacon Wind Withdraws Export Cable Request.) 

The sale of the Astoria site is conditioned on the Public Service Commission declaring it is not subject to review under Public Service Law. A petition to that effect was submitted March 20 (Case 25-E-0192). 

NYPA did not indicate a specific plan or intended use for the site, only that it would be used for future energy system enhancements and energy infrastructure to support integration of clean energy in New York City, where NYPA now operates multiple fossil fuel-fired plants — including in Astoria. 

The same legislation that expanded NYPA’s authority to develop renewables also mandated that it stop using fossil fuels to run its peaker plants by 2030. 

“Acquiring this land adjacent to our existing Astoria energy complex is yet another step forward to support New York’s clean energy future,” NYPA Chair John Koelmel said in a press release. “This strategic investment enables the Power Authority to explore options for reliable, sustainable energy infrastructure that aligns with the state’s ambitious decarbonization goals while also ensuring resiliency of the state power grid.” 

New York City is heavily reliant on fossil-fired generation even as a large percentage of upstate New York’s power comes from emissions-free sources. Emissions from power plants and vehicles in high-traffic areas degrade the air quality significantly in some city neighborhoods: Astoria and adjoining areas are known as “Asthma Alley,” for example. 

As a result, even incremental steps toward decarbonization of the city’s grid are celebrated by neighborhood leaders such as state Rep. Jessica Gonzalez-Rojas, whose district includes the Astoria site. 

“Acquiring this land in Astoria is a significant achievement and a major step toward New York’s ambitious — but achievable — environmental goals,” she said in NYPA’s release. “Transforming a former fossil fuel site into a space for sustainable energy is especially redemptive for the Queens communities, which have long faced some of the highest rates of pollution-related illnesses.” 

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Citing Inflation and Load Growth, Dominion Asks Virginia for Higher Rates

Dominion Energy Virginia has filed for its first base rate increase in decades, citing pressure from inflation and the need to reliably serve a growing customer base.

The request would raise the typical residential customer’s bill by $8.51/month starting Jan. 1, 2026, and another $2/month starting Jan. 1, 2027, Dominion said in an application filed March 31 with the State Corporation Commission (PUR-2025-00058). The new rates would mark the first increase in base rates since 1992. Dominion said its residential rates have increased by 40% lower than the rate of inflation over the past decade.

“We’re focused on providing exceptional value for our customers every single day,” Ed Baine, Dominion president of utility operations, said in a statement. “Outside of major storms, we deliver uninterrupted power 99.9% of the time, and we’re significantly reducing storm-related outages as well. This proposal allows us to continue investing in reliability and to serve our customers’ growing needs.”

The last biennial rate case came in 2023, and since then the company has faced higher costs of labor and materials including cables and wires, poles, transformers and power generation equipment.

In a separate application to the SCC (PUR-2025-00059), Dominion asked to move higher power capacity costs from its base rate to the annual fuel rate that would take effect July 1 and raise the monthly fuel rate paid by a typical residential customer by $10.92. The higher bills also include the fuel cost from extended cold weather this January and a $3.99 fuel credit from a previous rate case. Dominion passes through those costs and does not earn a profit on them.

Moving capacity expenses to fuel will increase the fuel factor by $1.98 for the typical residential customer, but it leads to a drop in base rates of $6.22 starting Jan. 1, 2026, according to the firm’s public application with the SCC.

Separating out PJM capacity prices into base rates and energy market costs in its fuel rates predates Dominion’s membership in the RTO and likely would not be done today given how much the company has to pay under the Reliability Pricing Model.

The delays in running auctions also prompted Dominion to make the request as it cannot accurately forecast what the price will be through the end of 2027, with two more auctions yet to run and one that will come after its rate case, it told the SCC.

On top of the new rates, Dominion also proposed creating a new rate class for high energy users that would cover data centers, and ensuring that those high-use customers pay their full cost of service and others are protected from stranded costs. Under the proposal, high energy users would have to make a 14-year commitment to pay for their requested power, even if they use less.

The Piedmont Environmental Council said that because the General Assembly failed to pass any meaningful reforms to how data centers are handled, the SCC’s review of Dominion’s rate case and its integrated resource plan are important to ensuring their growth is handled while keeping prices reasonable and environmental goals within reach. The group said it would work to ensure data centers pay their fair share.

“Virginia is in danger of falling behind and becoming the ‘how not to’ example that other states are using to avoid what has happened here. Ohio, Georgia, Texas, Indiana, Washington and Maryland are doing what Virginia’s policymakers and regulators have failed to do thus far,” PEC President Chris Miller said in a statement. “The SCC has the opportunity to take action now — and ensure data centers won’t overwhelm the power grid, drain statewide water resources and further intrude on areas never meant to be industrialized.”