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November 5, 2024

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NERC Sends Virtualization Standards to FERC

NERC this week made good on an order FERC issued more than eight years ago, seeking commission approval for a suite of changes affecting nearly every entry in the library of Critical Infrastructure Protection (CIP) standards that ERO staff have said are designed to “future-proof” the electric grid for emerging technologies (RM24-8). 

The submission comprises 11 new standards, along with four new and 18 revised definitions for the NERC glossary. They represent the final product of Project 2016-02 (Modifications to CIP standards), and were adopted by NERC’s Board of Trustees at its most recent open meeting in Washington, D.C. (See Christie, Clements Praise NERC’s Honesty at Board Meeting.) 

Project 2016-02 arose from FERC’s Order 822, issued Jan. 21, 2016. The order called for NERC to address several emerging issues related to the increasing use of cyber assets to control the grid, including virtualization, temporary devices connected to grid cyber equipment, and protection of communications both between control centers and between control centers and cyber assets. 

In its filing, NERC explained that as the “technology supporting and enabling the industrial control systems that operate the [grid] has evolved rapidly … the risks facing the [grid] and the methods for mitigating those risks have also evolved.”  

Virtualization, which the National Institute of Standards and Technology defines as “the process of creating virtual, as opposed to physical, versions of computer hardware to minimize the amount of physical hardware resources required to perform various functions” (the definition cited in NERC’s filing) is one such advance. NERC said the changes to the CIP standards and to the glossary will allow entities to make full use of the “concepts and efficiencies,” as well as security techniques, made possible by virtualization.  

The standards filed by NERC this week are: 

    • CIP-002-7 (Cybersecurity — BES cyber system categorization) 
    • CIP-003-10 (Cybersecurity — security management controls) 
    • CIP-004-8 (Cybersecurity — personnel and training) 
    • CIP-005-8 (Cybersecurity — electronic security perimeters) 
    • CIP-006-7 (Cybersecurity — physical security of BES cyber systems) 
    • CIP-007-7 (Cybersecurity — systems security management)  
    • CIP-008-7 (Cybersecurity — incident reporting and response planning) 
    • CIP-009-7​ (Cybersecurity — recovery plans for BES cyber systems)
    • CIP-010-5 (Cybersecurity — configuration change management and vulnerability assessments) 
    • CIP-011-4 (Cybersecurity — information protection) 
    • CIP-013-3 (Cybersecurity — supply chain risk management)​ 

The current versions of these standards are “designed around the concept that devices have a one-to-one relationship between software and hardware,” NERC said, an approach that prevents entities from taking advantage of some recent software advances. For example, security models such as zero-trust architecture can be improved with virtualization techniques that allow for more granular management of communication than traditional perimeter-based security models. 

These new CIP standards permit the use of virtualization and also account for risks associated with its use, such as cyberattacks that use virtual systems on the same hardware to attack each other. NERC said the standards were structured around security objectives that focus on “essential elements” of reliability rather than specific technology approaches.  

In addition, the developers recognized that many utilities do not use virtualization. By using security objectives, they hoped to create “a framework that could adapt to newer technologies and innovative security models” as the use of virtualization spreads through the ERO Enterprise. 

2024 already has seen several changes to the CIP standards. Last month, NERC submitted CIP-015-1 (Cybersecurity — internal network security monitoring) for FERC approval; the new standard would require utilities to monitor communications within their internal networks, with the goal of preventing attacks like the SolarWinds hack of 2020. (See NERC Submits INSM Standard for FERC Approval.)  

In addition, FERC approved CIP-012-2 (Cybersecurity — communications between control centers) in May. (See FERC Accepts NERC’s New Cybersecurity Standard.) The standard will require entities to mitigate the risk of lost communications between control centers, as well as the loss of real-time intra-control center assessment and monitoring data. 

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NYISO Monitor: NYC Capacity Costs Rose 221% in Q1

New York City saw a 221% increase in capacity costs in the first quarter because of the retirement of over 600 MW in peaker plants and the increase of more than 300 MW in the local installed capacity requirement, NYISO’s Market Monitoring Unit told stakeholders July 10.

Capacity costs elsewhere in the state rose “modestly,” Potomac Economics said in presenting its first-quarter State of the Market report to the Installed Capacity Working Group.

Overall, the MMU found that the market performed competitively in the first quarter. But spot capacity prices rose by 311% in New York City over the first quarter of 2023. The city’s ICAP requirement was increased because of higher load forecasts.

All-in prices ranged from $38/MWh in the North Zone to $81 in New York City. Prices rose west of the Central-East interface and the city while falling in the rest of Eastern New York. Potomac attributes this partially to falling natural gas prices.

Across the state, gas prices fell between 8 and 29% compared to a year ago because of the mild winter and continued growth in gas production. But the city was left behind in this trend and saw a 10% increase.

“The last two winters had much lower gas prices than in the previous winter. … That’s virtually true everywhere,” said MMU’s Pallas LeeVanSchaick.

New York City’s experienced modest increases in energy prices driven by congestion from transmission outages, while NYISO day-ahead congestion revenues fell 47%. The completion of several transmission projects increased transfer capacity over the Central-East and UPNY-SENY interfaces.

“Congestion revenue shortfalls during the quarter were pretty small,” said LeeVanSchaick. “They’re way down from the previous couple years because the amount of outages was really reduced quite a bit.”

The city also accounted for a higher level of congestion this quarter, most of which occurred during a period of low temperatures in January that coincided with the outage of a transmission line, reducing the import capability. That outage alone led to $5 million in congestion shortfalls during the cold snap.

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NEPOOL Markets Committee Restarts Work on Capacity Market Changes

After a brief pause following FERC’s approval of another delay to ISO-NE’s 19th Forward Capacity Auction (FCA 19), the RTO presented the initial scope of its work to coordinate resource capacity accreditation improvements with proposed capacity market timing changes at the NEPOOL Markets Committee meeting July 9-10. 

The potential changes have been an extended work-in-progress for the RTO and its stakeholders. ISO-NE launched its resource capacity accreditation (RCA) project almost exactly two years ago, while the RTO has been discussing moving to a prompt and seasonal capacity market for over a year. (See ISO-NE Starts its Capacity Accreditation Journey and ISO-NE Considers Major Capacity Market Changes.) 

Moving to a prompt and seasonal auction would reduce the time between the auction and the capacity commitment period (CCP) from over three years to likely just a few months, while also breaking up the yearlong CCP into seasons.  

“With the FERC approval of the further delay filing, we will turn our attention to working with stakeholders on [capacity auction reform] and will not continue to study accreditation in a forward, annual framework,” said Chris Geissler of ISO-NE. (See FERC Approves Additional Delay of ISO-NE FCA 19.) 

Geissler said the key considerations for the project scope are making sure the work is finished in time to implement for the 2028/29 commitment period (CCP 19), prioritizing the highest-value reforms and avoiding adding components that jeopardize the overall timing or development of the key aspects.  

The new capacity market design “likely needs to be completed, filed and approved well in advance of CCP 19,” Geissler said. “Expect that this will require hard decisions because even the most narrow project scope that achieves a prompt and seasonal market with accreditation reforms requires enormous design and implementation efforts.” 

The core aspects of the capacity auction reform (CAR) will include defining the exact timing of a prompt and seasonal auction, determining how entering and retiring resources will be treated under this construct, developing seasonal demand curves and incorporating the work that already has been completed on capacity accreditation into the new auction format.  

Geissler said ISO-NE and stakeholders already have made “significant progress” on developing a new accreditation method, but “outstanding areas remain and further changes are necessary with a prompt and seasonal capacity market.” 

The project likely will include work on a new approach to accounting for gas constraints, along with an update to the current cost of new entry value, since “accreditation reforms and modeling changes would impact this value, which is used to derive the capacity demand curves,” Geissler said. 

Geissler said ISO-NE also is contemplating moving from a descending clock to a sealed bid auction format, developing simultaneous seasonal bidding to account for resources that could receive an obligation for just one season, and accounting for resource startup times in accreditation.  

ISO-NE is considering whether to submit CAR’s resulting tariff changes as a single filing or a series of filings. For changes that ISO-NE is unable to complete for CCP 19, Geissler noted that the RTO could explore “improvements and enhancements for later commitment periods, after CAR has gone into effect.” 

Internal Market Monitor Report

Wholesale market costs were down in 2023 relative to the prior year, falling back to the levels seen prior to the spike in natural gas prices, Donal O’Sullivan of the ISO-NE Internal Market Monitor said in presenting takeaways from the Monitor’s 2023 annual markets report.

The lower costs were in part spurred by the lowest loads experienced in the region “since at least 2000 due to mild weather conditions and the growth in behind-the-meter solar generation,” O’Sullivan said. 

He added that renewables have grown gradually in the region over the past five years but said “the combined impact of behind-the-meter solar and wholesale market solar on load and pricing [time-of-day] profiles is noticeable.” 

The annual report found that the energy market accounted for about 51% of wholesale costs, followed by transmission at 28% and the capacity market at 13%. The Mystic cost-of-service agreement accounted for about 5% of total costs.  

While transmission costs were high, “the market impacts of investments are evident in terms of low congestion, fewer local reliability and voltage commitments, and [fewer] local market power issues,” O’Sullivan said. 

Looking at the resource mix, natural gas generation continued to increase despite the historically low loads. It accounted for 48% of total supply in 2023, compared with 45% in 2022 and 39% in 2019.  

In contrast, imports to the region were down, in part because of an approximately 20% reduction in imports from Canada because of lower reservoir levels, O’Sullivan said.  

Hourly Tracking Proposal Fails to Pass

A proposal by Constellation Energy to enable hourly tracking of generation by the NEPOOL Generation Information System failed to pass the MC with 65.1% in favor, falling just short of the two-thirds majority needed to pass.  

The company has argued that enabling hourly tracking would cost ratepayers relatively little and would help boost the market for carbon-free generation that matches load. 

NEPOOL estimated that upgrading the system to accommodate the proposal would cost $75,000.  

Opposition to the proposal came from members of the end user sector and the publicly owned sector. Opponents made the case that the proposal would benefit companies selling certificates at the expense of ratepayers and is not required by regulation. 

The proposal now heads to the NEPOOL Participants Committee. 

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3 OSW Proposals Submitted to NJ

It’s deja vu all over again as the window closes for New Jersey’s fourth offshore wind solicitation: The three developers that delivered proposals by the July 10 deadline all submitted bids to the state previously. One of the proposals contains a rebid of a project that already holds a New Jersey contract, and the other two possibly are reboots of proposals that derailed in New York. 

Atlantic Shores Offshore Wind won a contract for the 1,510-MW first part of its self-named proposal in June 2021. It now is submitting both Project 1 and Project 2 — a combined 2,800-plus MW — in a single proposal. 

Also submitting bids were Attentive Energy, for a project of unspecified capacity, and Community Offshore Wind, for a 1,300-MW project. 

New Jersey is seeking 1.2 GW to 4.0 GW of nameplate capacity in its fourth solicitation, which it opened April 30. 

The Garden State, like most other East Coast states, has ambitious goals for the emissions-free power sector starting to take shape in U.S. waters.  

And like most of the other Northeastern states, New Jersey is scrambling to recover from a confluence of macroeconomic factors over the past two years that led to cancellation of more than half the contracts awarded for proposed wind farms. 

In late 2023, New Jersey suffered the first and so far only outright project cancellation in the current wave of offshore wind development, when Ørsted scratched Ocean Wind 1 and 2. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) 

Among New Jersey’s responses to this setback was to allow developers who had been awarded a contract in the first or second solicitation to submit a rebid for that project in the fourth solicitation, to account for rising costs. 

Atlantic Shores Project 1 was the only project that still fit this definition, and the company apparently took advantage of the opportunity. 

In its announcement July 10, Atlantic Shores made no mention of the fact that its proposal was partly a rebid, nor of any proposed cost increases. 

Instead, it emphasized the ability of its proposal to be the state’s first mover in the offshore wind sector. It is a mature project, receiving a positive record of decision July 1 from the U.S. Bureau of Ocean Energy Management. (See BOEM Approves NJ’s Atlantic Shores OSW Project.) The company anticipates full state and federal permitting by the end of 2024. 

Attentive Energy also announced submission of a proposal July 10, but offered limited detail. 

Attentive Energy Two (1,342 MW) won a New Jersey offshore renewable energy certificate (OREC) contract in January 2024 as a result of the state’s third offshore wind solicitation. 

Attentive Energy One (1,400 MW) won a provisional contract in New York in November 2023, but that contract and two others collapsed six months later, after GE Vernova halted development of the 18-MW wind turbine that was to be used. (See NY Offshore Wind Plans Implode Again.) 

The end of the Attentive Energy One contract in New York was announced April 19, shortly before the start of New Jersey’s fourth solicitation. 

Attentive’s lease area in the New York Bight is 11 miles closer to New Jersey than to New York. 

Community Offshore Wind, 24 miles closer to New Jersey than to New York, also has a history with both states. 

It submitted a proposal in New Jersey’s third solicitation in 2023, then withdrew it when it determined it could not deliver an affordable proposal under the framework of the solicitation. 

It won a provisional contract for Phase 1 in New York’s third solicitation, then saw that evaporate six months later because of GE Vernova’s turbine strategy shift. 

It submitted a bid for Phase 2 in New York’s fourth solicitation but was “waitlisted” in February 2024 as the state chose instead to focus on two mature projects being rebid, which could get steel in the water much sooner and help rebuild lost momentum in the state’s quest for an offshore wind sector. 

The New Jersey Board of Public Utilities expects to decide on contracts in the fourth solicitation in December. 

As of mid-July 2024, the Garden State’s portfolio of offshore wind contracts consists of Atlantic Shores Project 1, Attentive Phase 2 and the two-phase, 2,400-MW Leading Light. The Attentive and Leading Light contracts were awarded in January 2024. (See NJ Awards Contracts for 3.7 GW of OSW Projects.) 

In a prepared statement, Community Offshore Wind said this latest New Jersey solicitation represents another chance to help that state’s economy and environment: “Our proposed project would generate 1.3 GW of clean wind energy and create programs to benefit communities for decades, including creating jobs for New Jersey workers and supporting new clean energy career pathways for future generations,” President Doug Perkins said. “New Jersey is well-positioned to become a hub of the U.S. offshore wind industry, and we look forward to working with our partners in Trenton and communities across the Garden State.” 

In a prepared statement, Atlantic Shores Offshore Wind CEO Joris Veldhoven said: “Our proposal serves to expand and enhance existing strategic partnerships while growing our portfolio of economic development initiatives across the Garden State. Working with our host community partners, we are keen to continue securing critical supply chain investments that will create great-paying union jobs, support local workforce development and contribute to economic prosperity across New Jersey.” 

Atlantic Shores is a partnership of Shell New Energies US and EDF-RE Offshore Development. 

Attentive is a partnership of TotalEnergies, Rise Light & Power and Corio. 

Community is a partnership of RWE and National Grid Ventures. 

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Startups: Market Will Move New Cleantech Regardless of Election Outcome

The U.S. Energy Association had billed its July 10 virtual briefing as a look at emerging technologies in the energy space, with a panel of industry executives talking about grid-enhancing technologies, nuclear fusion, small modular reactors, long-duration storage and low-carbon natural gas plants. 

But questions from energy reporters at the event quickly shifted the focus to topics of the moment: rising energy demand from data centers and what happens to U.S. energy policy if former President Donald Trump is re-elected. 

Arvin Ganesan, CEO of Fourth Power, a long-duration storage startup, sees the upcoming election as a secondary consideration. “The investment moment we’re in is largely derived by prevailing interest rates,” he said. What is driving the market is “how the electrical system is operated, and that is through, largely, state- and utility-led investments and procurement.” 

The growth in demand from data centers has the potential to shift utilities’ approach to their operations, he said. “The amount of load growth is, for these utilities, beyond stressful; it is a threat that they need to manage. … Utilities are conservative in general with technology deployment, but their need for new electrons is so high, some of that dynamic is changing.” 

Fourth Power’s storage technology turns excess renewable power into high-temperature heat that can be stored in carbon blocks and provide five to 500 hours of power and could be one-tenth the cost of lithium-ion batteries, Ganesan said. 

Like many in the industry, he sees the tax credits for renewable energy and storage in the Inflation Reduction Act as “fairly insulated from partisanship … given the fact that well over 50% of solar and storage installations are in ‘red’ districts, and the employment created by these industries span the breadth of geographies in states and in districts.” 

Alan Ahn, deputy director for nuclear at Third Way, a center-left think tank, similarly argued that advanced nuclear has broad support from Republicans and Democrats, pointing to the recent passage and signing of the bipartisan Accelerating Deployment of Versatile Advanced Nuclear for Clean Energy (ADVANCE) Act (S. 870). 

The law is targeted at providing the Nuclear Regulatory Commission with new authorities to, for example, improve and accelerate the permitting of advanced and micro reactors, and study advanced manufacturing techniques to help build reactors faster and cheaper. 

A range of tech companies ― like Google and Microsoft ― are looking at SMRs to provide clean, dispatchable power to data centers, and Ahn expects “robust support for advanced nuclear regardless of whether we have a Democratic or Republican administration.” 

The Biden administration and Department of Energy have provided strong support for advanced SMRs, with billions in federal dollars for two demonstration projects and, more recently, an announcement of another $900 million to support well designed projects that aim to build out a pipeline of SMRs. But companies have been hesitant to move ahead with projects because of the U.S. industry’s recent history of massive cost overruns and schedule delays that plagued the two new reactors now online at Plant Vogtle in Georgia. (See DOE Announces $900M to Kick-start Small Modular Nuclear Pipeline.) 

“The issue is how can we get users to move first,” Ahn said. “I think the conversation has really shifted towards, are there roles that the federal government can undertake to mitigate some of this first-of-a-kind risk?” 

Possible initiatives might include “some sort of completion insurance program or cost-overrun backstop that the federal government can implement,” he said. 

Fusion by Mid-2030s?

Andrew Holland, CEO of the Fusion Industry Association (FIA), is equally bullish on the development of nuclear fusion, which he said could reach commercial scale by the mid-2030s or before, and similarly pointed to data center and industrial demand as drivers. 

Fusion technologies — which heat hydrogen atoms to extremely high temperatures, causing them to fuse together — promise to produce massive amounts of carbon-free power, according to FIA’s website. Because the process does not produce radioactive waste, permitting fusion plants should be simpler, Holland said, requiring only a permit to operate, rather than the permits to construct and operate required for traditional, fission plants. 

Microsoft signed a contract last year for 50 MW of power from fusion startup Helion, and steelmaker Nucor also is partnering with Helion on a 500-MW fusion plant. These deals “do a good job of helping to advance the technology of fusion … because they show there is a de-risked pathway towards getting this energy on the grid,” Holland said. 

“The need to have always-on, always-available, clean, firm power for these data centers can be a really important part of our network and our capital stack as we develop into the next phase of this [technology],” he said. 

Ashley Smith, chief technology and innovation officer for AES, agreed that power demand from data centers, artificial intelligence and transportation and building electrification is driving a sense of urgency among utilities to figure out “how to get more electricity onto the grid.”  

AES has piloted dynamic line ratings at its utilities in Indiana and Ohio, Smith said, but she defended a go-slow approach to GETs and other emerging energy technologies based on traditional utility imperatives of reliability, safety and affordability. 

The company is also looking at “co-location: figuring out how we site certain large loads in areas where the grid is less constrained” and therefore decrease the time to get power online, Smith said. 

‘If You Build It’

Other speakers at the briefing also focused less on politics and more on the market forces that could provide ongoing momentum for emerging technologies, such as NET Power’s natural gas turbines that can capture 97% of their carbon dioxide emissions. 

“Different technologies … mean a lot of different things” to people, said Akash Patel, the company’s chief financial officer. “Some want to focus on the use of natural gas, which makes it reliable and cheap. Some want to focus on the capturing of all the emissions, to make it clean. So, there’s a lot of overlap.” 

NET’s potential customers include not only the tech giants “who will talk about AI till the cows come home, but also the oil and gas operators that are looking for how to reduce their Scope 3 emissions [and] how to use natural gas responsibly,” he said. “So, the approach we took is, if you build it, they will come.” 

Investors certainly have, and they could provide another hedge against political turbulence. Oxy, Constellation Energy and Baker Hughes are the company’s major investors. 

NET has run a 50-MW test plant in La Porte, Texas, since 2018 and is planning a 300-MW utility-scale project to go online in late 2027 or early 2028, also in Texas. 

Utility investors also have helped TS Conductor gain industry acceptance for its carbon-based advanced conductors, said Charles Bayliss, a long-time utility executive and a member of the company’s board. Both National Grid and NextEra Energy are supporting the company, as is Bill Gates’ Breakthrough Energy Ventures. 

Cleantech advanced during Trump’s previous administration, despite lack of federal support, but the flood of federal dollars during the Biden administration has accelerated the market. 

“It is just absolutely a fact that policy will determine how quickly these technologies get to market,” said John Howes, principal at the Redland Energy Group, an industry consulting firm. “There is an absolute connection between policy and the pace at which new technologies get to market. … Nobody believes that policy changes will destroy these industries, but personally, I find it hard to believe that positive policy won’t accelerate these technologies.” 

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CPUC Refines EPIC Program Strategic Objectives for Decarbonization

SAN FRANCISCO — The California Public Utilities Commission (CPUC) is working to focus the strategic objectives of its utility-funded Electric Program Investment Charge (EPIC) program to better support the state’s ambitious goals to decarbonize its economy. 

“The objectives are important for guiding the next cycle of EPIC investments with clear and measurable targets aimed at supporting clean energy solutions and ratepayer benefits,” CPUC Commissioner Karen Douglas said at a July 9 EPIC workshop.  

Douglas encouraged workshop participants to share thoughts on how to refine EPIC’s objectives in ways that help California meet its zero-carbon goals while addressing “gaps and opportunities to move down these pathways more quickly, best position stakeholders and program participants to lead innovations and innovative investments” and establish “solid targets” for measuring the program’s impacts.  

Established by the CPUC in 2011, EPIC is administered by the California Energy Commission (CEC) and the state’s three investor-owned utilities — Pacific Gas and Electric, San Diego Gas & Electric and Southern California Edison.  

The CEC administers 80% of the funds, leaving 20% to the utilities. The program invests in a wide range of projects, including building decarbonization, cybersecurity and demand reduction. According to the CPUC’s EPIC Strategic Objectives Workshop Report, the program will have invested nearly $3.4 billion in clean energy technology innovation between 2012 and 2030.  

EPIC was renewed in 2020 for 10 years, consisting of two five-year investment cycles. Under the guidance of the fourth EPIC Investment Plan, the CPUC authorized a budget of $147.26 million per year for the first investment cycle, which runs from January 2021 to Dec. 31, 2025.  

In preparation for the fifth cycle, which will run from 2026 to 2030, the CPUC launched a yearlong planning process to develop strategic goals and objectives that could better inform investments. In April 2023, the CPUC issued a decision identifying the need for program-wide goals that could help evaluate the progress of investments and the extent to which investment plan portfolios maximize benefits for ratepayers. The goals were approved this March, and include transportation electrification, distributed energy resource integration, building decarbonization, achieving 100% net-zero carbon emissions and the coordinated role of gas, and climate adaptation.  

The second half of the yearlong planning process for the fifth cycle, launched in March, focused on developing strategic objectives that would support the goals. In its EPIC Strategic Objectives Workshop Report, the CPUC defined strategic objectives as “clear, measurable and robust targets to guide EPIC investment plan strategies to scale and deploy innovation to align with EPIC’s strategic goals.”  

In creating the objectives, program administrators and The Accelerate Group, a consulting firm retained by the CPUC and CEC, invited stakeholders to identify gaps from the strategic goal process. According to Accelerate President Andrew Barbeau, the effort aimed to look “specifically at things that were missing that were critical” to decarbonization in the 2026-2030 time frame and “that were core to the focus of the EPIC program that represented challenges that could be addressed and overcome by the EPIC program and its specific mission.” 

 The working group process identified 13 objectives. Key among them were:   

    • reducing medium- and heavy-duty charging infrastructure costs [Objective A];  
    • overcoming barriers to electric vehicle benefits in disadvantaged and vulnerable communities [Objective B];  
    • reducing the cost of whole-home electrification;  
    • increasing predictability of weather, intermittent resources and load;  
    • providing data input into a “value of DER” framework;  
    • cost-effective grid hardening for long-term climate impacts. 

Stakeholder Input

Since last fall, EPIC administrators have hosted 18 workshops to develop strategic goals and objectives for the fifth investment plan. The July 9 workshop was the last before the CPUC is expected to publish a report and consider adopting the objectives.  

Some stakeholders asked for clarification and provided input on how the objectives could be improved. 

Peter Chen, a supervisor in the transportation unit at the CEC, questioned why light-duty vehicles, which were included in an earlier iteration of Objective A, were removed.  

“The costs associated with light-duty charging [are] still an important gap, especially with public charging infrastructure,” Chen said.  

Barbeau said consideration of light-duty vehicles was woven into other objectives.  

“Earlier in the process, there was a lot of focus on reducing costs in light duty charging infrastructure,” Barbeau said. “I think the cost of light duty infrastructure and its challenges to disadvantaged and vulnerable communities definitely [live] within [Objective] B.” 

Jimmy O’Hare, product manager for R&D operations at PG&E, also questioned why wildfire mitigation wasn’t specifically included in the objectives.  

“It strikes me that language and opportunities, particularly around wildfire mitigation and vegetation management, [are] still omitted from these strategic objectives,” O’Hare said. “At PG&E, about 10 to 16% of money from our bills [goes] to vegetation management and wildfire mitigation, so it seems like there’s a direct link between wildfire mitigation, vegetation management and affordability, and I think there is still a lot of opportunity for innovation demonstrations to happen in that area.”  

Barbeau highlighted that while wildfire mitigation wasn’t completely left out, there was a “strong concern about not encroaching on things that are being addressed in other proceedings” and that EPIC’s role is laid out more broadly in Objective M, which addresses grid hardening.  

“EPIC by itself isn’t going to completely replace the grid,” he said. “The role of EPIC here … was really focused on tools and frameworks to improve long-term planning. That could be grid, it could be prioritization of upgrades, it could be identifying vulnerable equipment. … I think technologies and solutions around wildfire mitigation do go there, as well as vegetation management.” 

Next Steps

The CPUC’s Energy Division expects this summer to publish a staff proposal with stakeholder input on the strategic objectives this summer, though an exact date hasn’t been set. In the winter, the CPUC will vote on the objectives and then turn the process over to program administrators to develop initiatives and solicitations.  

“This has been kind of a long process and it’s still kind of only halfway towards 2026, but what I’m really proud of and excited about is the amount of people that we’ve had participate,” Barbeau said. “We’ve had really good, open, transparent processes provided with a significant amount of input for a question that is actually very hard — not just thinking ahead about what you want to see happen on the energy system and the electric grid, but what does it take to get there, what are the gaps and challenges in the way, and forecasting the innovation needed to overcome it.”  

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Bill to Streamline Transmission Development Advances in Calif. Senate

California lawmakers have advanced a bill aimed at streamlining approval of transmission projects, but not before substantially stripping down the legislation.

The Senate Environmental Quality Committee voted 6-0 on July 3 to pass an amended version of Assembly Bill 3238 by Assemblymember Eduardo Garcia (D). The bill now goes to the Senate Appropriations Committee.

As previously proposed, AB 3238 would have removed a requirement for California Environmental Quality Act (CEQA) review for the expansion of an existing right-of-way for transmission lines and equipment on state land. The provision would have applied to an expanded right-of-way up to 200 feet wide and would have expired on Jan. 1, 2030.

The project to be sited on the expanded right-of-way would still be subject to CEQA, Garcia explained during the July 3 committee hearing. He said the idea was to remove duplicative review where rights-of-way exist and land is already disturbed.

“Let me be clear … if the current version of this bill goes into effect, not one shovel will go into the ground without a CEQA review of the project,” he told the committee.

But the bill was opposed by a long list of environmental and other groups. Some, including committee chair Sen. Ben Allen (D), worried about the impact on state parks.

“I’m personally not going to put my stamp on anything that’s going to make it easier for folks to run big transmission lines in the middle of a state park,” Allen said.

Opponents also objected to a provision in the bill that would have created a rebuttable presumption that the benefits of a transmission project outweighed its environmental impacts – if the project was included in a CAISO transmission plan.

Normally under CEQA, an agency must issue a statement of overriding consideration to allow a project to move forward despite environmental impacts.

Allen expressed concern that “we could be turning CEQA into just a rubberstamp process.”

“Creating a rebuttable presumption would replace the need to provide justification and evidence that the project is truly worth [the environmental impacts],” Allen said. “That’s the concern here.”

The section of the bill creating a rebuttable presumption was removed. It was replaced with a statement that under CEQA, the California Public Utilities Commission (CPUC) “may include CAISO’s factual findings regarding a project’s objectives and benefits in the commission’s statement of objectives and any statement of overriding considerations.”

“Doing so is consistent with CEQA guidelines,” the new language states. “Nothing in CEQA requires the commission to ignore such findings and it is reasonable for the commission to recognize them.”

Meeting Climate Goals

Garcia said the goal of his legislation is to accelerate the buildout of electric transmission infrastructure to meet state climate goals.

“Our state has set these targets for a reason, right?” he said. “We’re not going to meet them if we don’t take these types of bold action.”

The amended bill retained a provision setting a 270-day limit for the CPUC to complete environmental review for a transmission project and decide whether to approve it.

It would also simplify a project applicant’s requirements to submit information at the beginning of the environmental review process.

Supporters of the previous version of the bill include San Diego Gas & Electric, Pacific Gas and Electric, Advanced Energy United and the California Community Choice Association.

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Calif. Agency OKs Plan to Meet Ambitious Offshore Wind Goals

The California Energy Commission on July 10 approved an offshore wind strategic plan that details how the state can reach its goals of 5 GW of offshore wind power by 2030 and 25 GW by 2045. 

The commission voted 3-0 to approve the plan, with Chair David Hochschild and Commissioner Andrew McAllister absent. 

Although the plan was more than two years in the making, Commissioner Patty Monahan called it a starting point. 

“This needs to be a living document,” Monahan said before the vote. “We’re going to learn a lot about offshore wind. There’s a lot of uncertainties on the environmental impacts, and we need to be clear-eyed and engage the right scientific interests to make sure we are carefully moving forward, attentive to reducing the environmental impacts as much as we can.” 

The CEC called the plan’s approval a major step for the state toward reaching its 100% clean electricity goals. Offshore wind is one of the largest untapped sources of renewable energy in the state, the agency said. 

Assembly Bill 525 of 2021 directed the CEC to develop the strategic plan. The plan contains recommendations related to transmission infrastructure, port development, permitting and workforce development. It addresses impacts to marine life, fisheries, Native American tribes and the U.S. Department of Defense. 

A draft version of the plan was released in January. (See Draft Plan Outlines California Vision for Offshore Wind.) 

The commission had been slated to vote on a final version of the plan June 26. But commissioners agreed to postpone the vote so the public would have more time to review the final plan, which had been released less than a day earlier (See CEC Delays Vote on California OSW Plan.) 

Alexis Sutterman, a senior policy manager with Brightline Defense, an environmental justice organization, called the plan “an important step forward in catalyzing offshore wind.” 

“If California does not take action on offshore wind, we’re greatly concerned that we would see prolonged reliance on fossil fuel energy and perpetuate toxic pollution in environmental justice communities,” Sutterman told commissioners. 

Sutterman said Brightline appreciates the plan’s emphasis on engagement with communities and tribes, enforceable community benefit agreements, and the prevention and reduction of pollution. 

Next Steps

With the approval of the offshore wind strategic plan, CEC staff has already started work on additional reports. 

Last year’s Assembly Bill 3 by Assemblyman Rick Zbur (D) requires the CEC to develop a seaport readiness strategy for offshore wind that’s due Dec. 31, 2026.  

Described as a “second-phase plan,” the report will identify feasible seaports for turbine assembly to serve Central Coast and North Coast offshore wind projects. It will evaluate infrastructure investments needed to develop the seaports and prioritize sites that maximize in-state workforce opportunities and minimize impacts to cultural and natural resources. 

Elizabeth Huber, director of CEC’s siting, transmission and environmental protection division, said the agency is already planning workshops and town hall meetings on the topic. 

Previous studies have looked at the need for transmission infrastructure to support offshore wind. Huber said another study will look at the use of long-duration energy storage of the wind energy as it comes onshore. 

AB 3 also requires a report on the feasibility of manufacturing and assembling 50 or 65% of California offshore wind projects in-state. That report is due Dec. 31, 2027. 

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Dominion Issues RFP for Small Modular Reactor at North Anna

Dominion Energy Virginia issued a request for proposals from developers to build a small modular reactor at its existing North Anna nuclear plant in Louisa County, Va., the company announced July 10.

The utility is not yet committing to building an SMR at the plant northwest of Richmond, Va., but the RFP represents a first step to evaluating the technology’s feasibility.

“For over 50 years, nuclear power has been the most reliable workhorse of Virginia’s electric fleet, generating 40% of our power and with zero carbon emissions,” Dominion Energy CEO Robert Blue said in a statement. “As Virginia’s need for reliable and clean power grows, SMRs could play a pivotal role in an ‘all-of-the-above’ approach to our energy future. Along with offshore wind, solar and battery storage, SMRs have the potential to be an important part of Virginia’s growing clean energy mix.”

The announcement was made possible by Senate Bill 454, which was enacted into law earlier this year and allows Dominion and American Electric Power’s Appalachian Power to recover the costs of developing one or more SMRs that do not exceed 500 MW.

As part of the process, Dominion could ask the State Corporation Commission for separate approvals for different development phases of the project. The company expects to file for cost recovery this fall.

The legislation caps any rate increase from developing an SMR at $1.40 per average monthly bill, but the utility said its cost recovery request should come in well below that.

Dominion announced the RFP during a press conference at the North Anna plant that included Virginia Gov. Glenn Youngkin and other state officials.

“The commonwealth’s potential to unleash and foster a rich energy economy is limitless,” Youngkin said. “To meet the power demands of the future, it is imperative we continue to explore emerging technologies that will provide Virginians access to the reliable, affordable and clean energy they deserve. In alignment with our all-American, all-of-the-above energy plan, small nuclear reactors will play a critical role in harnessing this potential and positioning Virginia to be a leading nuclear innovation hub.”

Dominion has been using nuclear power for decades, with the two-reactor North Anna plant producing 17% of Virginia’s power and its Surry Power Station, near the state’s southeastern coast, producing another 14%. The company also runs nuclear plants in Connecticut and South Carolina.

North Anna has pending applications to extend its reactors’ commercial lifespan out to 2058 and 2060, while the SMR facility could come online in the 2030s and help the firm produce firm, carbon-free power to meet Virginia’s net-zero-emission goals.

The legislation caps SMRs at 500 MW, which is less than one-third the capacity of North Anna and Surry. SMRs are produced in a factory and then assembled on-site, a process that is meant to be more efficient than the one-off constructions used in traditional nuclear plants.

Dominion said Virginia has an ample workforce to deal with SMRs because of its existing power plants and the fact that it is home to one of two shipyards in the country that can make nuclear-powered ships. Virginia already has about 100,000 jobs that are directly tied to the nuclear industry.

Siting an SMR alongside North Anna means Dominion already owns the land and would be able to take advantage of the interconnection facilities there. The utility said it was considering “sites across Virginia” for additional SMRs.

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FERC Approves $246K in Reliability Standards Penalties

Dominion Energy will pay SERC Reliability $150,000, and the Long Island Power Authority will pay $96,000 to the Northeast Power Coordinating Council, for violations of NERC reliability standards, according to settlements between the utilities and regional entities recently approved by FERC (NP24-8). 

NERC submitted the settlements to FERC on May 30 in its monthly spreadsheet notice of penalty, along with a separate NOP and spreadsheet NOP regarding violations of the Critical Infrastructure Protection (CIP) standards. Those documents were announced but not made public in accordance with NERC and FERC’s policy on critical electric infrastructure information. FERC said in a filing at the end of June it would not further review the settlement, leaving the penalties intact. 

Dominion’s settlement involves the utility’s Virginia nuclear division, which operates the North Anna and Surry nuclear facilities in Louisa and Surry counties, respectively. According to SERC, the utility notified the RE in January 2022 that it was in violation of VAR-002-4.1 (generator operation for maintaining network voltage schedules), which requires generator operators to provide reactive support and voltage control to protect equipment and maintain reliability.  

Dominion reported to SERC that during preparations for an upcoming audit in December 2021, it discovered the nuclear stations operated outside their assigned voltage schedules for longer than 30 minutes with no notification to the transmission operator as required by the TOP’s procedure. The utility discovered 1,421 instances of noncompliance since 2020. 

According to the filing, Dominion determined the cause was a discrepancy in its voltage data monitoring parameters that caused its control room voltage to read up to four kV lower than the actual voltage. As a result, operators “did not recognize they were operating outside the assigned voltage schedules.” 

SERC determined the noncompliance began in 2007 under the previous version of the standard, VAR-002-1, even though Dominion did not review data prior to 2020 because it “was focused on correcting and mitigating the noncompliance moving forward.” The RE said it determined this date because the transmission owner’s voltage schedules had not changed since 2007 and the discrepancy in the control room parameters had existed prior to the discovery. 

SERC said the violation was caused by deficient procedural guidance, which did not require notifying the TOP when operating outside the voltage schedule for longer than 30 minutes, along with ineffective voltage monitoring controls. According to the RE, the infringement posed a “moderate” risk because the failure to maintain the voltage schedule and inform the TOP of the voltage excursions “could have delayed the TOP’s ability to respond to deviations … potentially resulting in damage to the system or [grid] instability.” 

Dominion’s mitigating actions include modifying the control room monitors to display the correct generator output voltage, revising the voltage schedule bandwidth for its generators to match the PJM default, and implementing auditory and visual alarms to alert control room personnel before generating units reach the voltage schedule limits. 

LIPA Corrects Ratings Mistakes

NPCC’s settlement with LIPA involved a violation of FAC-008-3 (facility ratings). The utility reported the infringement to the RE in November 2020, before the standard was replaced by FAC-008-5. 

LIPA told NPCC that during an extent of condition review, it conducted a walkdown of its facilities subject to NERC standards. The walkdown resulted in LIPA identifying 15 138-kV facilities with ratings that did not consider the most limiting element, as required by the utility’s facility ratings methodology. In addition, nine cables had incorrect seasonal facility ratings, also a violation of FAC-008-3. 

During a later walkdown in 2023, LIPA found an additional two 138-kV cables that were operating in the field in static mode, with incorrect ratings being used in the energy management system for real-time system operation.  

The RE determined the root cause of the misratings in the 138-kV facilities to be “ineffective internal procedures for ensuring the accuracy of facility ratings,” while the cause of the nine cable misratings was a database transposition error. For the 138-kV cables discovered in 2023, NPCC said the root cause was an ineffective detective control that did not alert personnel of a field configuration change. 

LIPA’s mitigation actions have not concluded yet; the utility has promised to correct the ratings for all noncompliant facilities, conduct a field review of all 138-kV transmission support structures and conductor spans, improve an existing tool to facilitate seasonal rating changes and perform field checks on pumping plants that use circulate ratings to ensure they are used correctly.