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April 3, 2025

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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 only used it 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 that 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 that 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 that “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 that 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 among 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 on March 31 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 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 will also 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 will also 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 that “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 was mostly 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 purchase 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 is now 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 that 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 on March 31 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 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 on 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 just 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.”

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Wash. Relaunches Cap-and-trade Rulemaking to Link with Calif., Quebec

Washington state has relaunched rulemaking that will pave the way for linking the state’s cap-and-trade program with the already-linked programs of California and Quebec. 

The new rulemaking will replace previous linkage rulemaking for Washington’s cap-and-invest program, which is the state’s name for cap-and-trade. The latest rulemaking will cover a wider range of topics, the Washington Department of Ecology announced March 31. 

The earlier rulemaking started in April 2024. The Department of Ecology held public meetings and released draft rules July 1. Comments and information gathered during the previous linkage rulemaking will be used as part of the new rulemaking, the department said. 

The potential rule changes will help Washington’s cap-and-invest program align with cap-and-trade programs in California and Quebec, although a new rule won’t create a linkage among the programs on its own. 

In cap-and-trade programs, major greenhouse gas emitters must buy allowances that correspond to the amount of their emissions; the state also imposes an emissions cap that decreases over time. The state may use proceeds from allowance auctions to fund climate projects. 

Linking carbon markets of multiple jurisdictions allows for joint allowance auctions, a common allowance price and trading of allowances between jurisdictions. With a larger pool of buyers and sellers, the linked markets generally have more consistent pricing and fewer price swings, the Department of Ecology said. 

California and Quebec linked their cap-and-trade programs in 2014. Washington launched its cap-and-invest program in January 2023, and last year, the state legislature passed Senate Bill 6058, intended to facilitate the linkage with the California-Quebec market. 

“We believe linkage will strengthen our respective efforts to fight climate change and reduce air pollution, while also encouraging more governments to adopt scalable, market-based climate policies in the future,” the three jurisdictions said in a joint statement issued in September.  

Topics Covered

The new Washington state rulemaking involves changes to two rules: the Climate Commitment Act Program Rule and Reporting of Emissions of Greenhouse Gases Rule. 

The previous rulemaking considered a range of topics, including compliance period length, program registration requirements and allowance purchase limits. 

Electricity sector topics included reporting for electric power entities, coverage for imported electricity from unspecified sources, participation requirements for federal power marketing administrations and greenhouse gas emissions reporting methods. 

Additional topics will be considered in the new rulemaking, including: 

    • imported electricity associated with centralized electricity markets; 
    • the amount of allowances allocated at no cost to electric utilities that must be consigned to auction during the second compliance period; and 
    • adoption of allowance budgets for the second compliance period (2027-2030) to ensure that emissions reductions are aligned with the state’s greenhouse gas emissions limits for 2030, 2040 and 2050. 

The rulemaking topics may continue to evolve, the Department of Ecology noted, as California and Quebec work on potential changes to their cap-and-trade regulations. And legislation enacted in Washington state this year could prompt further rule changes. 

The department will hold public meetings for the new rulemaking this spring through fall. The department expects to release a proposed rule early next year and adopt rule changes in summer 2026. An environmental justice assessment will also be conducted as part of the rulemaking. 

The department previously projected that a linkage agreement could be in place in 2026, with linked markets beginning to operate in 2026 or 2027. 

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Reliability Projects Dominate CAISO’s $4.8B Draft Transmission Plan

CAISO’s 2024/25 draft transmission plan recommends 31 new projects at an estimated cost of $4.8 billion, slanting heavily toward reliability needs.

The plan is based on California Public Utilities Commission forecasts projecting the state must add more than 76 GW of new capacity by 2039, the ISO said in the draft.

“This reflects greenhouse gas reduction goals and load growth, including the potential for increased electrification occurring in other sectors of the economy, most notably in transportation and the building industry,” CAISO wrote.

The new capacity needs include 30 GW of solar generation spread throughout the state, 7 GW of in-state wind resources in existing wind development regions, and more than 4.5 GW of offshore wind in the Morro Bay and Humboldt call areas.

The plan also factors in the need to import an additional 9 GW of wind energy from Idaho, Wyoming and New Mexico, which will require “enhancing corridors from the ISO border in southeastern Nevada and from western Arizona into California load centers.”

The plan additionally considers the transmission access needs of co-located battery storage projects across California, as well as for standalone projects close to major load centers in the Los Angeles Basin, the Greater Bay Area and San Diego.

“Our draft plan reflects the ISO’s proactive approach to transmission planning and underscores our ongoing collaboration with local, state and regional partners to ensure California has the necessary infrastructure to deliver clean energy reliably and cost-effectively to consumers,” Neil Millar, CAISO vice president for transmission planning and infrastructure development, said in a statement.

The ISO noted some of the projects would use grid-enhancing technologies.

Mostly Reliability

Twenty-eight reliability-driven projects account for nearly all the proposed spending, at roughly $4.56 billion.

“While the resource planning needs have not increased materially from those reflected in last year’s transmission plan, the increased rate of load growth reflected in the most recent load forecast associated with building and other electrification, data center growth and transportation electrification results in significant reliability-driven needs in this year’s transmission plan,” the plan says.

The 2024/25 plan assumes the state’s peak demand will increase at a 1.53% yearly rate, compared with a 0.99% forecasted growth rate in the previous plan. Peak demand in the Greater Bay Area is now expected to grow by 2.14% annually (up from 1.22%), translating into a 2,000-MW increase in the region’s 2035 peak load forecast, “with most of the growth coming from electrification of the transportation and building sectors of the state’s economy and an anticipated increase in data centers associated with artificial intelligence.” (See Data Centers Contribute to 60% Increase in San Jose Load Forecast.)

The Bay Area would host the priciest reliability projects in the plan, including Pacific Gas and Electric’s North Oakland ($1.13 billion) and Greater Bay 500-kV transmission ($700 million) reinforcement projects. San Diego Gas & Electric’s Downtown Reliability reinforcement project comes in third at $500 million.

Three policy-driven projects would entail about $289.5 million in spending.

All three recommended policy projects are in PG&E’s territory, including two in Fresno and one in the North Coast/North Bay local area. “They are needed to meet the renewable generation requirements established in the CPUC-developed renewable generation portfolios,” the ISO said.

CAISO said the plan identified no economically driven projects, representing those that would reduce costs for ratepayers but are not needed for reliability.

The ISO said the 31 recommended projects “represent significant investments that are phased in over lead times of up to eight to 10 years, which are reasonable for some of the projects to be completed.”

Costs would translate into about 0.5 cents/kWh over the life of the projects and will be phased in as lines come into service, the ISO said.

CAISO will hold an April 15 public stakeholder call on the draft plan and is taking comments through April 29. The ISO’s Board of Governors is expected to vote on the plan at its May meeting.

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Maine Floating OSW Negotiations Halted

Negotiations on what could have become the first floating offshore wind array in the U.S. have halted amid the uncertainty that has gripped the country’s offshore wind industry. 

The Maine Public Utilities Commission on March 28 granted the request of Pine Tree Offshore Wind to suspend talks on a contract to support construction of a research project with up to 12 turbines with a capacity of up to 144 MW. 

The move is the latest setback for the state of Maine’s long-running ambitions to exploit the windy waters off its coast for environmental and economic benefit through installation of wind turbines and creation of a new commercial/industrial sector:

    • The depth of the Gulf of Maine dictates that floating turbines be used there, and floating wind technology is still in development.
    • The state lost out on a $456 million federal grant to develop an offshore wind port; also, the chosen site is a nature preserve, and development is strongly opposed by some advocates. (See Maine Chooses Nature Preserve for Floating Wind Port.)
    • The first-ever Gulf of Maine commercial lease auction was a lackluster affair, with four of the eight offered lease areas drawing just $22 million in combined winning bids and the other four going unsold. (See Gulf of Maine OSW Auction Results in Four Leases Worth $21.9M.)
    • And of course, Donald Trump was elected president on a platform that included halting offshore wind development. Pine Tree is only the latest of several developers to pause their efforts in U.S. waters amid Trump’s efforts to follow through on his campaign pledge.

The state of Maine requested the research lease in October 2021 and designated Pine Tree as its operator. The U.S. Bureau of Ocean Energy Management executed the research lease (OCS-A 0553) in August 2024. (See Maine Approved for Floating Wind Research Lease.) 

The zone totals nearly 15,000 acres roughly 28 nautical miles southeast of Portland. 

The Maine PUC opened the docket (Case 2022-00100) for consideration of Pine Tree’s contract in April 2022. In December 2024, Pine Tree requested and received an extension to March 31, 2025, of the deadline to submit a proposed contract supporting the offshore wind research array. 

The negotiations apparently were fruitless: Pine Tree subsequently requested that they be suspended “due to recent shifts in the energy landscape that have in particular caused uncertainty in the offshore wind industry.” 

On March 28, the PUC approved the request for suspension, finding that “good cause exists” and noting that no objections were raised by the other negotiating parties: the governor’s Energy Office, the Office of the Public Advocate, Central Maine Power and Versant Power. 

The suspension will continue until Pine Tree requests that negotiations resume. 

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Newsom Issues Order to Speed Undergrounding of Lines in Los Angeles

California Gov. Gavin Newsom has suspended environmental laws to accelerate the undergrounding and hardening of utility equipment in communities ravaged by the Los Angeles wildfires.  

Newsom’s executive order removes requirements under the California Environmental Quality Act and the California Coastal Act in an effort to speed up “the rebuilding of utility and telecommunication infrastructure, including the undergrounding of equipment,” according to a March 27 news release. 

A previous executive order similarly suspended the environmental laws and applied to infrastructure damaged in the wildfires. However, that order was limited, and projects to move equipment underground or upgrade existing infrastructure may not qualify under the previous suspension, the most recent order stated. 

“We are determined to rebuild Altadena, Malibu and Pacific Palisades stronger and more resilient than before,” Newsom said in a statement. “Speeding up the pace that we rebuild our utility systems will help get survivors back home faster and prevent future fires.” 

In a Feb. 27 letter, Newsom urged Southern California Edison and Los Angeles Department of Water and Power to develop plans by the end of March on how the utilities can rebuild safer and resilient electric infrastructure, including by placing electric distribution infrastructure underground. 

Jeff Monford, a spokesperson for SCE, told RTO Insider the utility appreciates “Gov. Newsom’s action to help expedite permitting so the fire-damaged communities can rebuild stronger. We look forward to continuing our work with federal, state and local officials to shorten permitting times under this executive order.” 

SCE has already launched efforts to underground several miles of lines in Altadena and Pacific Palisades, “and some sections of the grid will be completed in a few months,” Monford said. 

Monford could not share specific cost information but noted that undergrounding costs significantly more than building the grid with power poles. 

“There’s a lot going on in these burn areas, and the expedited permitting, siting and permitting that the governor’s order will allow will certainly help move that along,” he added. 

Local utility Pasadena Water and Power, which operates in the Altadena region that was devastated following the Eaton fire, said in an email that “nothing in the orders change any policy direction and capital projects that we have planned.” 

The Eaton Fire began shortly after 6 p.m. Jan. 7 and burned more than 14,000 acres and killed 17 people. The deadly fire engulfed parts of the Altadena community, with thousands of structures either damaged or destroyed, according to Cal Fire. 

The Pacific Palisades fire burned 23,448 acres, destroyed 6,837 structures and killed 12 people. 

SCE faces several lawsuits, alleging the utility’s lines started the Eaton fire. SCE has said it is investigating possible links between its equipment and the fire. (See SCE Probes Link Between Equipment and Eaton Fire.) 

SCE utility has previously acknowledged that its equipment may have sparked the Hurst Fire, which burned roughly 799 acres and damaged two homes. There were no reports of fatalities or injuries associated with the fire. SCE has said it is cooperating with a Los Angeles Fire Department investigation.