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November 17, 2024

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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. 

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Massachusetts Overhauls Municipal Aggregation Approval Process

The Massachusetts Department of Public Utilities (DPU) on July 9 approved a proposal to expedite the state’s review process for municipal aggregation plans, while also adding transparency requirements and allowing municipalities to update their plans without DPU approval. 

Municipal aggregation plans enable communities to purchase electricity in bulk and can reduce ratepayer costs relative to basic utility service in Massachusetts. They also can give ratepayers options to increase the number of renewable energy certificates (RECs) over what is required by the state’s Renewable Portfolio Standard (RPS). 

According to a 2023 study by the Green Energy Consumers Alliance, municipal aggregation programs with more RECs than required have reduced costs and emissions in the state. (See Green Municipal Aggregation Cuts Costs and Emissions in Mass., Study Says.) 

Despite the potential benefits, the DPU has faced criticism for yearslong wait times for aggregation applications to be approved.  

Municipal aggregation reforms have been a priority of the DPU under Chairperson Jamie Van Nostrand, who was appointed by Gov. Maura Healey (D) in 2023. The DPU opened a docket on municipal aggregation reform in August 2023, which included draft guidelines, and asked for stakeholder feedback (D.P.U. 23-67-A). 

Public comments largely were critical of the draft guidelines, which ultimately led to the creation of a stakeholder working group that advised a group of consultants in the creation of a new proposal.  

The consultants jointly submitted the resulting proposal in early June with the backing of key stakeholders including the Green Energy Consumers Alliance, the city of Boston, several state agencies and electric distribution utilities. 

“While the joint petitioners did not fully agree on all issues, the joint petitioners agree that the adoption of the guidelines and accompanying documents should significantly improve the effectiveness and efficiency of the department’s review and approval of municipal aggregation plans,” read the proposal.  

The DPU approved these new guidelines with only “clarifying, non-substantive edits,” writing that they will “strike an appropriate balance between administrative efficiency … and transparency.” 

Under the new guidelines, the DPU will be required to respond to municipal aggregation applications within 120 days of their submission. The department has issued a standard application template intended to help facilitate an expedited review process. 

The order also increases the transparency mandates for municipal aggregations, requiring disclosures related to rates, clean energy makeup and certificates, different customer classes, and accessibility. 

These measures will enable “increased public scrutiny,” the DPU wrote, adding that they are an important component of allowing increased discretion to each municipality in developing and updating its aggregation.  

The new rules will allow municipalities to update their plans “in a manner consistent with these proposed guidelines without department approval, provided that it allows at least 30 calendar days for public review of the revised plan,” the DPU noted.

The department wrote that the rules will enable greater flexibility for municipal aggregations “to respond to market conditions in a timely manner.” 

Municipalities filing new aggregation plans also will be required to meet with the Department of Energy Resources to go over their plan and discuss best practices. 

The DPU’s approval was applauded by several stakeholders who have focused on the issue.  

“Reforming the commonwealth’s municipal aggregation process was a priority in the legislature this session,” said Rep. Jeff Roy (D), House Chair of the Joint Committee on Telecommunications, Utilities and Energy. “The DPU’s thoughtful and collaborative engagement with stakeholders over the past few months has resulted in updated guidelines that will allow for greater flexibility and innovation, supporting both ratepayers and the commonwealth’s clean energy transition.” 

Larry Chretien, executive director of the Green Energy Consumers Alliance, said the new guidelines will “help the aggregation movement grow while [continuing] to ensure consumer protections.” 

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10 Northeastern States Sign MOU on Interregional Transmission Planning

Ten East Coast states signed a memorandum of understanding July 9 to set up a framework to coordinate interregional transmission planning and development. 

Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont will explore mutually beneficial interregional transmission to increase the flow of electricity between the ISO-NE, NYISO and PJM, as well as assessing offshore wind infrastructure needs. 

The states have been working on the issues for more than a year, since they sent the U.S. Department of Energy’s Grid Deployment Office a letter asking for help to convene a Northeast States Collaborative on Interregional Transmission. (See Northeast States Detail Early Efforts on Interregional Tx Collaborative.) 

Massachusetts Energy and Environmental Affairs Secretary Rebecca Tepper said her state cannot go it alone to address climate change and that interregional collaboration is a top priority of Gov. Maura Healey (D). 

“Through partnerships like this collaborative, we will be able to advance more cost-effective transmission projects for the residents of the Northeast,” Tepper said in a statement. 

The states agreed to work together on interregional transmission infrastructure and share information. Enhancing ties between the regions should lower prices for consumers by broadening access to the cheapest available power and bolster reliability during periods of extreme weather and system stress, they said in the MOU. 

“New Jersey is not alone in experiencing increasingly frequent extreme weather events and record-breaking temperatures that threaten public health and safety,” New Jersey Gov. Phil Murphy (D) said in a statement. “We are also not alone in our response to the intensifying climate crisis, which provides crucial opportunities to leverage interregional partnerships toward improving our collective resilience and economic vitality.” 

The collaborative has plans to produce a strategic action plan for promoting interregional transmission projects that can cut the cost of bringing offshore wind to consumers. That plan would involve identifying barriers to such projects and how to address them. 

The states intend to provide opportunities for external engagement as they develop the plan. They also want to coordinate on technical standards for offshore wind transmission equipment to ensure interoperability as projects come online in different areas at different times. The states plan to work with DOE, FERC, industry and the three grid operators. 

Any decisions that come out of the collaborative will require mutual consent among the states that said they would maintain their independence. That means nothing in the deal prevents them from independently or collectively seeking support or funding, advocating for or participating in any other planning and cost allocation processes.  

The six New England states and New York have a pending application at DOE to get some funding through the Grid Innovation Program for National Grid’s Clean Resilience Link, a 345-kV line between ISO-NE and NYISO to increase their transfer capability by 1,000 MW. The $10.5 billion GIP program offers a maximum of $1 billion for projects. 

Speaking for himself, Abe Silverman of SilverGreen Energy Consulting, which has been working with the states, said in an interview that the effort helps to formalize a relationship between the states, the federal government and the ISO/RTOs to move transmission forward for offshore wind and interregional transfer capacity. 

While federal efforts on interregional transmission also are important, Silverman said that often, when major interregional and even intraregional lines have actually been built, states have been behind the efforts. 

“There isn’t a lot of it, and what has been built … has often been the result of concerted state efforts,” he said. “Look at the Competitive Renewable Energy Zone lines in Texas, the Long-Range Transmission Planning Program in MISO, the New York [Public Policy Transmission Need process] and New Jersey’s State Agreement Approach; … those were all major transmission efforts that had their genesis in state agreements.” 

The states in the collaborative include only a couple led by Republican governors, and many of the quotes from senior officials on it were focused on liberal policies around offshore wind and addressing climate change, but Silverman argued that interregional transmission has bipartisan bona fides. 

“I often talk about how transmission policy needs to pass the ‘Joe Manchin press release’ test, which is, this is a set of policies that [Sen.] Joe Manchin [I-W.Va.] would be OK promoting,” Silverman said. “And you look at the benefits of interregional transmission: It’s lower cost for consumers; it’s better reliability — particularly in the face of extreme weather — and it’s about American energy independence and dominance.” 

Those factors, which test well with Manchin and others leaning to the right on energy, are enough to justify the investment regardless of the climate impacts, he argued. 

NARUC Weighs in on Interregional Transmission with New Study

The National Association of Regulatory Utility Commissioners on July 9 released a new study called Collaborative Enhancements to Unlock Interregional Transmission, which was prepared by Energy and Environmental Economics (E3).  

The study highlights strategies for increasing transfer capability, which state regulators increasingly have looked toward because of rising demand and ongoing changes in supply. 

“As our existing grid is forced to respond and adapt to emerging needs, regulators are increasingly interested in assessing how new interregional transmission infrastructure can drive value for customers,” Kansas Corporation Commission Chair Andrew French said in a statement. “This timely report provides PUCs a straightforward assessment of existing barriers preventing robust interregional transmission planning and a suite of potential solutions for regulators and other stakeholders to consider.” 

Maria Robinson — director of DOE’s Grid Deployment Office, which helped NARUC with the report — called interregional planning critical for providing reliable and affordable power. 

“Public utility commissions need practical solutions for identifying crucial interregional transmission projects to ensure power gets from where it’s generated to where it’s needed most, when it’s needed most,” Robinson said in a statement. “We are proud to support NARUC in this effort as partnerships at the federal, state and local levels are needed to meet our shared goal of a more reliable and affordable grid in the face of aging infrastructure, extreme weather and changing energy landscape.” 

The study argues that the limited success on interregional lines so far can be attributed to three main issues: the lack of planning motivators, cost allocation, and planning process misalignment and analysis limits. 

Regions could expand coordinated planning to identify joint needs and solutions because once the same needs are identified, they would be motivated to reconcile their differing regional planning processes, or develop new ones, to identify interregional lines, the paper says. 

They also could standardize universal best practices in regional and interregional transmission solutions to ensure the best projects are identified and thoroughly analyzed, while accurately assigning costs to beneficiaries, to cut friction in interregional planning. The regions also should work to reconcile differences in modeling, tools, data inputs and benefit calculation methods, the paper says. 

While projects are planned and cost allocated across multiple states, they are sited by individual state regulators who most often have the final decision on what moves forward. The paper suggests ensuring projects have non-energy benefits to ensure states that bear their physical impact also benefit, which could include jobs, revenue sharing, investment in capital projects and social programs, and economic development opportunities. 

States also could use the same analysis for an interregional line’s “need” and coordinate their evidentiary records to synchronize permitting timelines and standardize data collected to inform decision-making, according to the study. 

“Different states may still have different priorities and may choose to include different types of benefits in what they consider, but standardizing a common set of underlying facts, models and timelines could help expedite project approvals,” the paper says. 

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Report: US Solar Panel Factories Still Will Need Imported Cells

The U.S. solar market may face major domestic supply chain gaps as it heads toward 2030, as incentives from the Inflation Reduction Act spur solar panel manufacturing but leave those factories dependent on imported solar cells, according to a report released July 9.

A joint project of the American Council for Renewable Energy and Clean Energy Associates (CEA), the report estimates U.S. factories may be producing 60 GW of solar panels per year by 2030, but only about 12 GW of solar cells. Further, 97% of the imported solar cells needed to make up the difference are subject to existing solar tariffs, and some soon could have additional duties slapped on them.

If those new duties are imposed, CEA predicts prices for domestically produced solar panels made with imported cells could increase by 10 cents/W, while the price for imported panels could go up 15 cents/W.

“Tariffs increase capital costs, and when you talk about increasing capital costs, [that] increases the cost of delivering electricity, and that of course is going to have an impact on demand” and the country’s ability to meet its greenhouse gas emission-reduction goals, said Daniel Shreve, vice president of market intelligence at CEA.

But during a July 9 webinar launching the report, Shreve said that even with new tariffs and the variability in location and logistics of specific projects, utility-scale “solar is going to be extraordinarily competitive and the lowest-cost source of electricity in most situations,” compared with often volatile natural gas prices.

The report comes just weeks after the end of President Joe Biden’s two-year moratorium on solar tariffs on cells and panels from Cambodia, Malaysia, Thailand and Vietnam. Biden established the moratorium in June 2022, during an International Trade Commission (ITC) investigation of whether imports from those countries were using Chinese components and attempting to circumvent existing tariffs.

The investigation triggered a panic and a spike in prices in the solar market, and Biden justified the moratorium as “a bridge” for the industry to stand up domestic manufacturing. Signed into law in August 2022, the IRA’s solar and clean manufacturing incentives stoked a wave of announcements of new solar factories ― 131 GW of panel factories and 87 GW of cell plants ― but CEA expects “realized capacity” to be significantly lower.

“If we’re talking about what’s holding some of this capacity back, a lot of it has to do with trying to gather finances associated with these very large capital expenditures,” Shreve said. “You need investors; you need off-takers; and these things take time to develop, and folks have to become comfortable with bringing that supply online.”

CEA’s forecast of just 12 GW of cell capacity by 2030 could increase, he said, “but we need to see some more traction from some of these suppliers first before we make that move in our forecast.”

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The U.S. solar market is strong, Shreve said, pointing to a compound annual growth rate of 33% between 2010 and 2023. The market hit new highs last year, putting a total of 32 GW of new solar online, including 22 GW of utility-scale projects and 7 GW of residential installations.

But the rate of deployment must step up to meet Biden’s goal of cutting the nation’s greenhouse gas emissions 50 to 52% by 2030. Total U.S. solar capacity hit 177 GW in 2023, the analysis says, but cites multiple reports calling for a threefold increase to between 500 and 560 GW by 2030 to slash emissions in half.

Standing up a domestic supply chain is seen as a critical factor for market growth as the IRA provides bonus tax credits of up to 10% for solar projects that meet the law’s domestic content provisions. To qualify, projects beginning construction this year must meet a 40% domestic content requirement, which will step up 5% per year to 55% in 2026 and beyond.

Solar tariffs and anti-dumping and countervailing duties (AD/CVD) are seen as major headwinds for the market, according to CEA Senior Policy Analyst Christian Roselund.

The end of Biden’s two-year moratorium coincided with a new AD/CVD investigation, again focused on imported solar cells, whether or not already assembled in modules, and targeting Cambodia, Malaysia, Thailand and Vietnam.

In May, Biden also doubled tariffs on solar cells imported from China, from 25% to 50%, and removed an existing exemption for tariffs on bifacial solar panels.

Roselund said the AD/CVD duties could have a significant impact on the market because of their broad unpredictability. Unlike tariffs with set specific rates, these duties are imposed retroactively; so, a company may not know how much it will be charged for cells it is importing, and the rates may change every year.

Suppliers pay an upfront cash deposit on imported panels or cells, he said, but “if you’re importing goods that are subject to an anti-dumping or countervailing duty order, you won’t know how much you actually owe until an administrative review that will come two, perhaps three years later. … You import goods, and then you get the bill several years later.”

In addition, solar cells from the four Southeast Asian countries currently account for 58% of solar cell imports to the U.S. and 78% of imported panels, making them the biggest source of solar imports for the U.S. market, Roselund said.

Projects Canceled, Delayed

Depending on the ITC’s final decision, new AD/CVD tariffs could be imposed starting in September or, under special circumstances, retroactively from June 2023, he said. While not speculating about any potential outcomes, Roselund noted that when the ITC launched its previous AD/CVD investigation in 2022, solar imports had their slowest quarter in two years.

Roselund expects median rates for the duties, if imposed, to range from 9% to 51%, but he said the unpredictability of the rates potentially is the most dampening for market growth.

“Try to run your financial spreadsheets when you have a variable in one of the columns; it’s just very hard to do,” he said. “It hits buyers and suppliers, and then [photovoltaic] projects and manufacturing facilities. … If you have a U.S. module factory and suddenly you don’t know what you’re going to have to pay for cells, that impacts your operations and what you end up with is projects canceled, projects delayed and supply shifts as the market adjusts.”

Even with the generous incentives in the IRA, Roselund noted that in the past AD/CVD tariffs had not stimulated the buildout of a domestic supply chain. “We saw that supply shifted to other low-cost manufacturing locations,” he said.

Roselund also flagged other market headwinds. U.S. solar prices are about double the average per-watt cost in global markets, and under the pressure of the ITC investigation, suppliers are starting to reopen signed contracts and increase prices for imported cells and panels.

“Suppliers are saying, ‘We can’t deliver the product that you signed a contract for previously,’ and they have to bring the prices back up to account for their risk of what they’re going to have to pay,” he said.

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FERC Must Apply Mobile-Sierra to Western Soft Cap Refunds, Court Finds

The D.C. Circuit Court of Appeals on July 9 directed FERC to apply the Mobile-Sierra doctrine when it reconsiders a series of 2022 orders requiring Western wholesale electricity sellers to refund a portion of the high prices they earned during an August 2020 heat wave. 

At issue in the case — and in the related FERC orders — is the commission’s longstanding policy of maintaining a “soft” price cap for short-term electricity sales in the West to prevent the exercise of market power (22-1116). A product of the Western energy crisis of 2000/01, the policy requires sellers to justify the costs behind power prices exceeding the soft cap of $1,000/MWh, or refund any amount earned above the cap. 

The case dealt specifically with surging prices associated with tight supply conditions stemming from triple-digit temperatures occurring over Aug. 18-19, 2020, when CAISO struggled to prevent the rolling blackouts it was forced to order Aug. 14-15 — the first such blackouts in nearly 20 years. 

Wholesale prices at Arizona’s Palo Verde hub on the Intercontinental Exchange (ICE) hit records of $1,515/MWh on Aug. 18 and $1,750 on Aug. 19. The hub’s average price from June to August of that year, excluding the August price spike, was $52/MWh, according to filings Southern California Edison and Pacific Gas and Electric made with FERC to protest the prices. 

Over the course of 2022, FERC issued a series of decisions rejecting the justifications of sellers who sold electricity at those levels during the period, finding that the ICE index prices reflected scarcity conditions and that the selling companies had failed to justify their premiums based on costs.  

Those decisions rejected the argument by sellers that FERC should apply the presumptions from the 1956 cases United Gas Pipeline v. Mobile Gas Service and FPC v. Sierra Pacific Power — or Mobile-Sierra doctrine — to the sales and hold that the contracts were freely negotiated between the buyers and sellers and did not harm the public interest. Instead, the commission determined the Mobile-Sierra presumption did not prevent it from “enforcing the requirement that sales in excess of the WECC [or Western] soft price cap must be justified and [we]re subject to refund.” 

The commission also held that it had the authority to enforce the soft cap through refunds without conducting a Mobile-Sierra public-interest analysis because the soft cap was part of the sellers’ filed rate, a finding reinforced by the 2002 “Soft-Cap Order” establishing the caps in the West. 

In its decisions, the commission also rejected requests by some sellers to raise the West-wide soft cap to $2,000/MWh, in line with the cap in place in CAISO, saying that was out-of-scope for the rulings. 

Mobile-Sierra Necessary

Dozens of sellers were affected by the decisions, including PacifiCorp, Shell, Mercuria, Tenaska, Tucson Electric Power, Uniper Global Commodities North America, Tri-State Generation and Transmission Association, and Brookfield Renewable Trading and Marketing. (See FERC Tells PacifiCorp to Refund Premiums, Sellers Urge FERC to Raise WECC Soft Price Cap and FERC Orders More Refunds from 2020 Western Heat Wave.) 

Then-Commissioner James Danly dissented in each of the orders, questioning the commission’s authority to abrogate bilateral contracts reached between buyers and sellers in a time of tight supply conditions. Danly wrote that FERC instead should have applied the Mobile-Sierra presumptions to the contract and found that the public interest was not harmed by upholding them. 

The sellers once again used that line of reasoning in their appeal to the D.C. Circuit, contending FERC erred by not conducting a Mobile-Sierra analysis before ordering the refunds — an argument that swayed the court in its decision to remand the orders back to FERC. 

“We agree with the sellers that the commission should have conducted the Mobile-Sierra analysis prior to ordering refunds, and so we grant the sellers’ petitions for review, vacate the orders they challenge, and remand for further proceedings,” the court wrote. “Because of that holding, the commission necessarily will need to change its refund analysis for above-cap sales going forward, and any decision by this court on the validity of that framework would be purely advisory.” 

In its ruling, the D.C. Circuit said FERC’s arguments against administering a public-interest analysis before enforcing refunds “fail for a simple reason.” 

“Even assuming that the Soft-Cap Order was incorporated into sellers’ tariffs and contracts, the commission did not displace the Mobile-Sierra presumption in the Soft-Cap Order itself, and so that presumption continues to apply to the Sellers’ contracts,” it found.  

“More specifically, nothing in the Soft-Cap Order established that the Mobile-Sierra doctrine would not apply to the commission’s review of any above-cap rates,” the court continued. “As such, the Soft-Cap Order left intact the commission’s burden of overcoming the presumption that ‘a freely negotiated wholesale-energy contract meets the “just and reasonable” requirement imposed by law.’”  

The court went on to say that the soft cap “is best viewed as a means for flagging for the commission contracts that may warrant public-interest analysis.” 

“The requirement that sellers ‘justif[y]’ their above-cap prices, in turn, facilitates this review by obligating sellers to supply information showing that the conditions for the ordinary application of the Mobile-Sierra presumption (e.g., the absence of market manipulation) were in place at the time of the above-cap sale,” the court concluded. 

‘Consumers’ Petition Rejected

The court additionally rejected a petition by the California Public Utilities Commission and SCE (called the “consumers” in the ruling), which contend that FERC committed errors in its refund calculations that would lead to higher electricity prices in the future. 

“We have no occasion to engage with the merits of the consumers’ challenge because it is moot,” the D.C. Circuit found, noting that the petitioners had questioned the way in which FERC had calculated the refunds but that the court already determined the commission had “erred in ordering refunds in the first place without applying the Mobile-Sierra public-interest analysis.” 

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ERO Comments on CISA Reporting Proposal

NERC urged the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) to ensure that future rules on reporting cybersecurity incidents are in harmony with existing requirements and that it continue collaborating with utilities and their regulators during the rulemaking process.

Additional ERO Enterprise stakeholders, including the ISO/RTO Council (IRC), the National Rural Electric Cooperative Association and the Electric Power Supply Association, participated in the comment period for CISA’s Notice of Proposed Rulemaking that concluded last week. The agency opened the comment period in April with an initial 60-day deadline, which later was extended to 90 days. (See CISA Seeks Comment on Proposed Cyber Reporting Rules.)

The NOPR stems from the Cyber Incident Reporting for Critical Infrastructure Act (CIRCIA), passed in 2022, which requires entities in critical infrastructure sectors — including energy — to report relevant cyber and ransomware incidents to CISA within 72 hours. CIRCIA left to CISA the authority for defining which incidents would be subject to reporting and which additional sectors, if any, the requirements would cover.

In its proposal, CISA said it would use the authority granted by the law to “fill … key gaps in the current cyber incident reporting landscape” and create a “comprehensive and coordinated approach” to cyber incident reporting.

The NOPR included a web-based form that would be the only official option for submitting incident reports, along with definitions of key terms such as “cyber incident,” “covered cyber incident” and “information system.” It also proposed details of content to be included in incident reports, such as whether victims requested assistance from other entities and their engagement with law enforcement agencies related to the ransomware or cyberattack.

NERC’s response to CISA noted that the ERO’s Critical Infrastructure Protection (CIP) reliability standards already address cybersecurity risks, including requirements for reporting cyber incidents to both the agency and the Electricity Information Sharing and Analysis Center (E-ISAC). Along with the CIP standards, electric utilities also are required to report certain cyber and physical security incidents to the U.S. Department of Energy through Form OE-417; entities may submit their OE-417 reports to the E-ISAC in place of CIP reports.

The ERO said “there are many commonalities between” the CIP reporting requirements, OE-417, and the proposed CIRCIA requirements. Noting CISA’s statement that it is “committed to working with DOE, FERC and NERC” to allow entities to comply with all three reporting regimes through a single report “to the extent practicable,” NERC said it “looks forward to working with its government partners to explore options to reduce regulatory burden and avoid unnecessary duplication.”

NERC also requested that CISA provide a mechanism for sharing CIRCIA reports with the E-ISAC and its counterparts in other industries. The ERO said that “ISACs are uniquely positioned … to amplify CISA’s analysis throughout their respective sectors and to enrich [it] with sector-specific information.”

“The E-ISAC understands that in certain instances there may be privacy-related concerns with sharing attributable information with ISACs without the consent of the submitting entity,” NERC said. “The E-ISAC respectfully requests that CISA develop a process for obtaining consent for sharing attributable information and, where that is not possible, removing identifiable information from the reports and its analysis to be able to share relevant information with ISACs and their members free of any security and privacy-related issues.”

Other Stakeholders Respond

Like NERC, the IRC encouraged CISA to “continue its education, outreach, and collaboration efforts” with NERC and the E-ISAC, other government agencies, and the ISOs and RTOs, specifically by soliciting stakeholder input on future information sharing agreements implemented under CIRCIA. In addition, the IRC suggested CISA hold a technical conference on the design of its web-based reporting form.

EPSA expressed concern about the proposed rule, calling it “extremely broad” and warning it may require “more extensive reporting than the detailed regimes under which EPSA members currently operate.” The association urged CISA to refine its definition of “covered cyber incident” to avoid requiring reports on “less critical incidents” that might take up entities’ time and resources unnecessarily.

NRECA also described CISA’s proposal as too broad, saying it applies “to all electric utilities regardless of size, location or resources, [which] includes hundreds of small distribution cooperatives that serve a relatively small number of meters.” This broad applicability “exceeds Congress’ intent in the CIRCIA legislation,” NRECA said, suggesting CISA limit its criteria to be risk-based so it covers entities that can provide the “most relevant and actionable information.”