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December 25, 2024

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CPUC Fines PG&E $45M for 2021 Dixie Fire

California regulators approved a $45 million penalty against Pacific Gas and Electric on Jan. 25 for the utility’s role in the 2021 Dixie Fire, the second-largest wildfire in state history.

The California Public Utilities Commission voted 3-2 to approve the penalty as part of a settlement negotiated between PG&E and the commission’s Safety and Enforcement Division (SED).

The penalty includes a $2.5 million fine that will be paid to the state’s general fund. PG&E will pay another $2.5 million to tribes whose land was impacted by the fire.

In addition, the utility agreed to spend $40 million to transition to electronic recordkeeping for inspections of overhead and underground distribution equipment. PG&E has agreed to not seek recovery of the $40 million through customer rates.

As part of the settlement, PG&E denied any fault in connection with the Dixie Fire, which was sparked by a tree falling on one of the utility’s distribution lines in the Sierra Nevada foothills.

5-county Blaze

The Dixie Fire started July 13, 2021, when a Douglas fir tree fell onto PG&E distribution lines, a Cal Fire investigation determined. The fire spread across 963,309 acres in five Northern California counties and destroyed about 1,300 structures.

The proposed settlement went to the commission for a vote Nov. 30. But two commissioners — Darcie Houck and Genevieve Shiroma — said they needed more information, and the vote was postponed.

Following the Nov. 30 meeting, SED provided written responses to the commissioners’ questions.

But during the Jan. 25 meeting, Houck and Shiroma said they weren’t satisfied with the answers. They voted against approving the settlement agreement.

Houck questioned whether the relief provided by the settlement was enough given the magnitude of the fire.

“In light of the enormous impact this fire had on the state of California and the five counties impacted, the relief that is being proposed here, based on the information and reports we have today, I still believe is inadequate,” Houck said.

Houck also said she was worried about the impact of the agreement in a future cost-recovery proceeding. Under terms of the agreement, PG&E retains the right to pursue recovery of costs associated with the Dixie Fire.

“There’s still a concern about how the information and the fact that the settlement was there with no admission of fault would be looked at when we’re looking at things like cost recovery,” she said.

Role of Recordkeeping

Several of Houck’s questions during the Nov. 30 meeting were related to the $40 million for electronic inspection records. She asked for more specifics on what information would be digitized and how that would improve safety.

In its written response, SED said digitization “is important for speed and efficiency at the commission and across other agencies responsible for wildfire safety.”

“The continued and accelerated improvement of inspection processes by PG&E pursuant to the [agreement] will support public safety and facilitate commission oversight,” SED wrote.

Commissioner John Reynolds, who voted in favor of the $45 million settlement, emphasized the importance of digitizing records during the Jan. 25 meeting.

“Modernizing records related to the condition of PG&E’s assets may not sound exciting to the public,” he said. “But better information about the condition of electrical assets is vital to improving inspection and preventive maintenance procedures, which are bread-and-butter wildfire safety activities.”

Commissioners also noted that PG&E has taken steps to reduce wildfire risk since the Dixie Fire.

CPUC President Alice Busching Reynolds said the utility now has a system that shuts down distribution lines when it detects a fault, such as one caused by a tree falling on the line.

In a release issued after the vote, the CPUC said it has “taken many actions to hold PG&E accountable for safely serving its customers.”

Those include a $150 million penalty for the 2020 Zogg Fire, a $1 million penalty for the 2019 Easy Fire and a $125 million penalty for the 2019 Kincade Fire.

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Offshore Wind Reset Complete in New York

The churn in New York’s offshore wind industry reached a crescendo Jan. 25, with ownership changes, contract cancellations and new proposals announced. 

The cancellations effectively reset the state’s offshore development pipeline almost to zero, albeit briefly, as thousands of new megawatts are in advanced negotiations, and bids for thousands more were submitted this week. 

The day’s highlight reel went like this: 

    • Ørsted announced plans to buy out Eversource’s 50% stake in Sunrise Wind if the project goes forward. 
    • Equinor and bp announced they are dividing up their joint projects, with Equinor taking full ownership of Empire Wind and bp taking full ownership of Beacon Wind. 
    • Ørsted and Eversource pulled out of their offtake contract with the state for Sunrise and submitted a new bid on an updated version of the proposal. 
    • Equinor and bp, which previously cancelled their Empire Wind 2 contract, also now have canceled Empire Wind 1. They submitted a rebid for Empire 1 but are holding off on Empire 2. 
    • Equinor and bp also reached a deal to cancel the state contract for Beacon Wind 1. They did not indicate what would become of that project, or of Beacon Wind 2, which had not been awarded a contract. In its news release, bp said only that it would independently pursue future U.S. offshore wind opportunities.  
    • Finally, the National Grid Ventures-RWE joint venture Community Offshore Wind — which the state chose in late 2023 for a 1.3-GW offtake contract — announced Jan. 25 it had submitted a proposal for a second 1.3-GW offshore wind farm. 

The afternoon of Jan. 25 was the deadline for proposals in New York’s fourth offshore wind solicitation. Details were not immediately available, except for the limited information from those developers that chose to publicize it. 

Attempting A Rebound

Renewable energy development in New York reached a crisis point in 2023, as long-running review and permitting processes combined with soaring costs to make previously contracted proposals unprofitable and unable to proceed to construction.  

Offshore wind was the most visible example because of the huge sums of money involved, but onshore wind and solar had similar financial pressures. 

New York declined in October to provide more money to those projects, triggering mass cancellations. (See NY Rejects Inflation Adjustment for Renewable Projects.) 

With Sunrise, Empire and Beacon (combined capacity 4,230 MW) now gone, the only offshore project with a New York contract is South Fork Wind, which is nearing completion but will produce a maximum of only 132 MW. 

New York has scrambled to rebound from this potentially disastrous setback to its clean energy goals. (See New York Scrambles to Maintain Momentum in Energy Transition.) 

In late October, it announced provisional contracts for three offshore projects totaling 4 GW and 22 onshore projects totaling 2.4 GW. The three offshore wind proposals — Attentive Energy One, Community Offshore Wind and Excelsior Wind — then went to final contract negotiations. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) 

The state also announced expedited solicitations for new projects and allowed developers to rebid existing proposals at higher cost if they first canceled their earlier contracts. (See New York Issues Expedited Renewable Energy Solicitations.) 

The deadline for offshore bids was 3 p.m. on Jan. 25. 

The deadline for large-scale onshore bids is 3 p.m. on Jan. 31. Sixty-eight onshore renewable projects totaling more than 5.6 GW were submitted by the prequalification deadline, Dec. 28. Sixty of those were existing projects whose developers canceled their previous contracts. 

Churn Continues

Ørsted and Eversource have suffered amid the offshore wind industry’s growing pains in the United States. Both have recorded billions in impairments, and Eversource has been searching for more than a year for a buyer for its share of the venture. 

Ørsted’s takeover of Sunrise is conditioned on the 924-MW wind farm plan being chosen for an offtake contract and on regulatory approvals. But Sunrise is a rare commodity in a struggling market — a mature project with supplier and labor agreements in place, state approvals in hand and final federal approval anticipated later this year.  

Construction could be completed by 2026 if it is chosen in the solicitation that closed Jan. 25, Ørsted said. 

Ørsted and Eversource also are a known commodity, currently completing South Fork and starting work on Revolution Wind, a Connecticut-Rhode Island project. 

Ørsted Americas CEO David Hardy said: “Following a thorough risk review of our U.S. portfolio, we’re comfortable with taking full ownership of Sunrise Wind if the project is awarded in New York 4. This transaction is a value-accretive opportunity for Ørsted and the best path forward for the project.” 

The price tag of the buyout was not disclosed. 

Eversource would remain contracted to lead onshore construction of Sunrise. 

Meanwhile, Equinor and bp also have had financial problems trying to move forward with offshore development.  

Along with the offshore assets, they are divvying up their onshore efforts: 

Equinor will take over bp’s 50% interest in the lease for the South Brooklyn Marine Terminal, which is planned for development as a hub for offshore wind activity in the New York Bight. 

And bp will take Equinor’s 50% interest in the Astoria Gateway for Renewable Energy site, which will host a converter station where electricity from offshore wind will be connected to the New York grid. 

Their agreements are cash neutral. 

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FERC, NRC Examine State of the Nuclear Industry

FERC and the Nuclear Regulatory Commission convened a joint meeting Jan. 25 to examine issues of common interest, including the rollout of advanced reactors and grid reliability.

FERC Commissioner Mark Christie said nuclear power has two advantages.

“No. 1, it’s carbon free, and that’s great,” Christie said. “No. 2, it runs all the time. Not two weeks, but two months, three months, six months — it runs all the time. So that’s great. So basically, any future where you want to have … reliable power and reduce carbon emissions, it’s got to include nuclear.”

The future of the technology seems to be centered on small modular reactors, he added. The NRC is expecting 25 applications involving SMRs in the next five years, said Andrea Kock, deputy office director for engineering for the agency’s Office of Nuclear Reactor Regulation.

“Those are potential applicants that have come to us and stated that they intend to submit an application, and it spans technologies from things that look a lot like what we currently have, but smaller, to some really advanced designs,” Kock said.

The regulator has resolved more than 35 technical and policy issues and issued more than 60 guidance documents to support those reviews, Kock said. NRC is also using a graded approach that will focus on the most significant safety issues.

“The NRC is doing things differently to yield timely and cost-effective reviews without compromising on safety,” she added.

FERC Commissioner Allison Clements asked about the impact of the recent decision by NuScale Power and Utah Associated Municipal Power Systems to end the development of the SMR-based Carbon Free Power Project in Idaho. (See Pioneering NuScale Small Modular Reactor Canceled.)

Kock said the NRC is still reviewing that reactor design to allow it to be used by another project in the future if it winds up being approved.

SMRs and even smaller “microreactors,” which adapt the technology used to fuel submarines and aircraft carriers to civilian uses, present new issues the NRC has encountered before, Kock said. Such reactors will be built in a central factory and transported to where they are used, presenting novel regulatory issues, she added.

The smaller reactors also bring up questions about how much staff is needed to safely operate them, with many designed to be much more passive than traditional nuclear plants, Kock said.

Another issue is how to keep existing plants running as the country transitions to a greener grid, leading FERC Chair Willie Phillips to ask about California’s quest to keep the Diablo Canyon nuclear plant running and what factors policymakers should consider to keep existing plants online. (See Diablo Canyon Secures $1.1B DOE Award to Support Operations.)

One factor influencing the decision is how much energy a plant is producing, said David Ortiz, director of FERC’s Office of Electric Reliability.

“Nuclear plants are essentially energy resources because they’re on all the time,” Ortiz said.

“The next [factor] is the services that those provide,” he said, noting that the impact on voltage control is the transmission system support function that planners typically assess when a nuclear plant seeks to retire,

It will be important to study more than just voltage in the future because retirements can lead to other system issues, he added.

NRC is expecting to field a significant number of license renewal applications that would extend plant operations to 80 years, in part because of federal support for existing nuclear under the Inflation Reduction Act with the Civil Nuclear Credit Program, Kock said. (See DOE Opens IIJA Nuclear Credit Program to Recently Closed Plants.)

“We’ve received interest in the potential restart of the Palisades plant in Michigan, which is now looking to restart by August of 2025,” she said.

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Reports Detail Causes, Impact of Local Opposition to Renewables

Two new reports quantify the local opposition renewable energy developers are facing with many of their U.S. projects and offer insight on how to address it.

The first-of-its-kind Berkeley National Laboratory’s report, “Survey of Utility-Scale Wind and Solar Developers,” finds that a third of siting applications submitted by developers in the past five years have been canceled and about half have been delayed by at least six months, in many cases because of local pushback.

Four out of five developers were at least moderately concerned that community opposition will get in the way of decarbonization goals.

“Good Fences Make Good Neighbors,” a collaboration by researchers at Berkeley Lab and Michigan universities, focuses strictly on large-scale solar systems. It is based on 54 interviews with a broad range of stakeholders examining the concerns about these facilities.

Pattern of Delays

The wind and solar survey by three Berkeley Lab researchers drew responses from 123 people at 62 companies that collectively are responsible for about half of U.S. wind and solar development from 2016 to 2023.

Among the findings:

    • Most projects take four to six years from initial public announcement to commercial operation date; about 20% take longer.
    • Local ordinances or zoning regulations, grid interconnection and community opposition are the leading causes of project delays and cancellations in the past five years.
    • Project delays and cancellations are slightly more common for solar than for wind and most often occur during the permitting process.
    • Project cancellations result in average non-recoverable costs of more than $2 million each for solar projects and $7.5 million each for wind.
    • Community opposition to wind and solar is cropping up more frequently and becoming more expensive to address; it delays solar projects 11 months on average and wind projects 14 months; developers expect it to become even more prevalent in the next five years.
    • About 95% of respondents say opposition often is caused by a vocal minority; about half find opposition is driven by outsiders; middle- to high-income communities are more likely to push back on proposals than low-income areas.
    • Less than a third of developers say it is easy to predict opposition, but most agree that larger proposals are more likely to be contentious.
    • Visual impact is the most likely root of community opposition for both solar and wind, followed by impact on community character and property values; additionally, noise is a frequent concern with wind proposals and loss of agricultural land with solar plans.
    • Developers typically begin community engagement after securing site control; most developers find it effective in addressing concerns and reducing opposition and say it results in fewer cancellations; in-person meetings with stakeholders are ranked the most effective means of engagement.
    • Many respondents said earlier engagement might have been a good idea with their most recently canceled project, but a few said earlier engagement allowed more effective opposition to form.
    • The most common design changes in response to community feedback on solar projects are changes to vegetation screening, exclusion of properties and increased setbacks; for wind projects, it is revised turbine placement, increased neighbor compensation and exclusion of properties; for both technologies, increase of community subscription or ownership was the least common change.
    • Community engagement boosted costs approximately $1,100 per megawatt on successful wind projects and $700 on solar.

Building Trust

The report “Good Fences Make Good Neighbors: Stakeholder Perspectives on the Local Benefits and Burdens of Large-Scale Solar Energy Development in the United States” was prepared by the same three researchers from Berkeley Lab and two each from the University of Michigan and Michigan State University.

They note that a rapid increase of solar and wind generation is needed to meet national decarbonization goals and that the Energy Information Administration predicts 63 GW of solar capacity to be installed in 2024 alone.

This effort often relies on residents willing to host these systems, the authors write, and depends heavily on permitting approval by local and state officials and policymakers.

These officials and local residents offer far less support for large-scale solar (LSS) projects than national surveys suggest, the authors say. They interviewed nine developers, 32 people who live near solar facilities, seven government officials and six utility representatives to try to understand why.

They identified eight typical concerns and a set of recommendations to address them:

    • Public meetings have little positive effect on residents’ perceptions of LSS; many people are unaware of the processes and feel left out. Policies should be considered to require developers to engage in one-on-one conversations to identify and address concerns.
    • Residents use the term “developers” as a catchall for builders, owners and operators, leading to confusion and distrust; also, residents should have more opportunity to provide feedback when construction is complete and the facility is online. Officials should better delineate and communicate organizational responsibility over the life of the project.
    • Rural communities may be overwhelmed by a sudden influx of LSS construction workers and their needs. Developers should contract with local businesses to meet the needs of their project and of the community before starting construction.
    • Residents living near LSS projects often are ignored in subscription efforts. Developers should, at a minimum, advertise such opportunities via direct mail and at public meetings.
    • Residents often are unaware of the LSS impact on tax revenues or have a negative impression of it. Officials should tie specific services to the tax benefits or replace tax revenue with predictable, scheduled payments.
    • The visual impact of interconnection infrastructure often is ignored during pre-construction community engagement. Developers should provide detailed renderings of substations and other infrastructure, not just the solar arrays; they should provide tours of nearby LSS sites.
    • Previously developed land in rural areas may not be perceived as more suitable than greenfields for LSS developments. Developers should not assume LSS will be seen as a beneficial use of disturbed land.
    • The costs of not developing solar rarely are a conversation point. Developers and officials should discuss the more permanent infrastructure that could occupy the same land with potentially greater impact on neighbors, such as subdivisions and trailer parks.
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NERC Board to Vote on Rule Changes for IBRs

A set of proposed changes to NERC’s Rules of Procedure (ROP) that would create a process for registering owners and operators of inverter-based resources (IBRs) will go before the ERO’s Board of Trustees for a vote in February, the organization announced this week. 

NERC developed the proposed ROP changes last year as stage 1 of its three-stage registration process, which FERC approved in May (RD22-4). (See FERC Approves NERC’s IBR Work Plan.) The process specified that NERC would submit the first stage to the commission within a year after approval; the second stage, identifying candidates for registration, is to be completed within two years, with registration to be finished within three years. 

The rule changes will affect Appendices 2, 5A and 5B of the ROP; respectively, these concern definitions of terms used in the ROP, NERC’s Organization Registration and Certification Manual, and the compliance registry criteria. 

In Appendix 2, NERC intends to update the definitions of generator owner (GO) and operator (GOP) to include “entities that own and maintain or operate [grid]-connected … IBR.” The proposed changes would also update the definition of “reserve sharing group” (RSG) to be consistent with what was proposed in Project 2022-01 (Reporting ACE definition and associated terms), which passed its final ballot in December. 

The RSG changes are part of NERC’s planned changes to Appendix 5B as well. In addition, the ERO proposed to add a new category to the GO and GOP registry criteria for entities that own and maintain or operate IBRs with aggregate nameplate capacity of at least 20 MVA, working through a common point of connection with a voltage of at least 60 kV. Further changes will clarify which entities are candidates for registration and have access to NERC’s review panel process. 

Finally, Appendix 5A will be updated to “reflect NERC’s scope of authority to register entities that own, operate or use [grid] assets consistent with the revisions in Appendix 5B,” and to clarify the type of review to be applied to registration appeals. 

NERC posted the proposed changes for industry comment from Sept. 13 to Oct. 30. The final ROP changes before the board next month will reflect the feedback the ERO received through this process. 

In response to a comment from Advanced Energy United expressing concern about a supposed lack of specificity regarding which facilities are to be registered, NERC said it would update the definition in Appendix 2 with more detail about whether IBRs outside the Bulk Electric System (BES) — and therefore not subject to NERC’s reliability standards — would be required to register. 

The Edison Electric Institute and Evergy also expressed concern about the “unintended consequences” that could arise from the use in the proposal of the term “bulk power system” (BPS), which refers to the entire electric grid, including facilities not subject to the ERO’s standards. The respondents explained that while BES is “well understood [and] used in the context of the applicability of reliability standards,” BPS is less well defined and consequently could “lead to ambiguity and confusion.” 

NERC replied that the ERO “is not modifying its approach to ensure that reliability standards … support an adequate level of reliability,” and that the ROP updates will not impact its standards development or compliance enforcement efforts. 

In addition, NERC incorporated clarifications to Appendix 5B in response to a concern from AEU that the proposal lacked a means to appeal registration decisions for non-BES facilities. The final proposal will reflect that the “registration review panel process is available to owners, operators and users of the BPS, not only BES.” 

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NextEra: Disruption Only Strengthens the Company

Noting “disruption often presents opportunity at NextEra Energy,” CEO John Ketchum said Jan. 25 the company relied on 25 years of experience with renewable energy to navigate “clear headwinds for renewables” over the past two years.

Ketchum told financial analysts during NextEra’s quarterly earnings call that its competitive, clean energy business, NextEra Resources, had its best year yet by adding about 9 GW of new renewable and storage origination to a backlog that now exceeds 20 GW. About 5.6 GW of renewables and storage were commissioned during the year, NextEra said.

“We successfully managed through the disruption,” Ketchum said. “We believe that the disruption over the last two years has made NextEra Energy an even stronger company. Our business model is more resilient. Our development platform is even more advanced, and our supply chain is more diversified than it has ever been.”

Ketchum noted inflation and inflation rates have declined from their peaks, solar suppliers have been provided with more certainty around rules for imports and new solar supply chains have led to lower panel costs that have declined by about 25% from their peak over the past 24 months.

“Ultimately, all these tailwinds are great for customers, and we believe that should drive greater renewables demand in 2024 and beyond,” he said.

NextEra reported year-end earnings of $7.31 billion ($3.60/share), up from $4.15 billion ($2.10/share) the year before. Fourth-quarter earnings were $1.21 billion ($0.59/share), compared to $1.52 billion ($0.76/share) for the same quarter in 2022.

Ketchum expressed frustration with NextEra’s stock performance this year. The company’s share price closed at $57.98 Jan. 25, down $4.94 from a Jan. 8 peak of $62.92.

“We recognize and are disappointed by the underperformance in the share price, and as we start 2024, we remain steadfast in our continued focus on execution and creating long term value,” Ketchum said. “Bottom line, we believe NextEra Energy is well positioned headed in the 2024.”

Xcel: Coal Closures to Continue

Xcel Energy also reported year-end and fourth-quarter earnings Jan. 25. Annual earnings were $1.77 billion ($3.21/share), compared with $1.74 billion ($3.17/share) for the same period a year ago.

For the quarter, earnings were $409 million ($0.74/share), compared with $379 million ($0.69/share) during the same quarter in 2022. Xcel reaffirmed its 2024 EPS guidance of $3.50-$3.60.

Xcel CEO Bob Frenzel | © RTO Insider LLC

CEO Bob Franzel told financial analysts that the retirement in December of the first of three coal-fired units at the Sherburne County Generating Station (Sherco) sets the stage to retire all of its coal plants by 2030. Sherco’s other two units are targeted for closure in 2026 and 2030. (See Xcel Says Coal Retirements on Track Despite South Dakota PUC’s Plea for Extensions.)

“This is a milestone as we work to exit coal by 2030 and another sign that we’re leading the nation’s clean energy transition,” Franzel told financial analysts.

Xcel plans to replace the units with 2.1 GW of wind and 2.5 GW of solar with what it says will be the largest solar facility in the Midwest.

The company’s share price closed at $58.89, up 67 cents on the day. Xcel opened the year at $63.47.

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MISO to Re-examine Schedule for Reviewing Expedited Tx Projects

CARMEL, Ind. — MISO’s Planning Subcommittee this year will tackle possible modifications to the RTO’s expedited project review process, which allows transmission developers to begin construction earlier than MISO’s annual approval process usually allows.  

The RTO’s Planning Advisory Committee on Wednesday voted to allow the subcommittee to begin deliberations in March on a new schedule for the study process to better manage the increasing number of requests.  

At a Jan. 24 PAC meeting, expansion planning engineer Amanda Schiro said expedited requests until recently have been few enough not to burden MISO resources.  

“However, in the past three years, we have seen large load additions that increase the volume and complexity of expedited requests,” Schiro said, adding that requests often are driven by “spot load growth,” such as data centers.  

MISO late last year said it’s become inundated with expedited review requests and that it likely needs to overhaul how it handles transmission projects that can’t wait until the usual December board approval to begin construction. (See MISO Board Approves $9B MTEP 23; Members Deliberate on New Expedited Review Rules.)  

Schiro said the expedited requests and their “isolated processes” are causing a “strain” on MISO’s planning staff to study all expedited requests alongside the RTO’s annual Transmission Expansion Plan (MTEP).  

Schiro said MISO held 17 meetings over 2023 to review individual projects and the RTO needs to reduce the frequency of meetings. She said MISO might contain project submission times and introduce a timeline to accomplish a more streamlined process.  

“We’d like to reduce that number both for us and our stakeholders,” she said.  

Schiro said when conducting outreach on the issue, stakeholders urged MISO to keep the “valuable” expedited process. She said MISO has no plans to discontinue expedited reviews.  

However, the Union of Concerned Scientists’ Sam Gomberg said he thought MISO’s plan to focus only on the expedited review timeline “misses an opportunity” for the RTO to plan for load additions more proactively.  

Under the existing process, MISO conducts individual studies on expedited requests to confirm the projects won’t result in reliability violations before allowing them to proceed ahead of the usual MTEP cycle.  

Stakeholders have suggested MISO enact voltage or cost thresholds so small projects don’t have to go through an expedited project review.  

Generally, projects must rate at least 100 kV or cost at least $1 million to be considered candidates under MTEP and compelled to apply for expedited treatment when necessary.  

This month, MISO analyzed an expedited need from Jonesboro City Water and Light, which proposed an $874,000 rebuild of a 69-kV line in northeastern Arkansas due to state Department of Transportation work. Some stakeholders at a Jan. 16 South Technical Study Task Force questioned whether MISO should have devoted time to examining such a small project.  

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CPower Event Charts the Future of Virtual Power Plants

NATIONAL HARBOR, Md. — The demand response business has changed so much in recent years that the term has fallen out of favor for “virtual power plants” (VPPs), and the trend is only going to continue as residential customers adopt more distributed energy resources. 

The only thing aggregators like LS Power subsidiary CPower used to deal with was actual customer demand, CEO Michael Smith said in an interview on the sidelines of an event his company hosted on Jan. 23. 

“Now we have on-site solar and storage,” Smith said. “Now we have a lot of backup generation fuel cells. We have interruptible computing loads, so we talked about data centers, or Bitcoin mining, that can change their load profile and actually change their operations. So, all of these things give us more tools in the toolbox. At the same time, the needs of the grid have become more complex.” 

With residential customers getting more involved in the electric grid with the adoption of electric cars, distributed solar and batteries, and smart appliances, that shift is only going to accelerate. 

“I think that the overall residential market just in terms of gigawatt-hours is going to be larger than the C&I [commercial and industrial] market, if you think about water, heaters, AC, that kind of thing,” Smith said. “But getting to it is a challenge; it’s a data challenge. But it’s also a controls challenge that has to be highly, highly automated.” 

Many of the large C&I customers that CPower serves trim their demand at least in part by having an employee flip a switch, but residential customers need to have that process, Smith said. 

That looming change has caught the attention of the U.S. Department of Energy, which is increasingly focused on helping VPPs roll out across the country, said Loan Programs Office Senior Adviser Jennifer Downing (no relation to reporter), who wrote the department’s “Pathways to Commercial Liftoff” report for the technology. (See DOE Report Lays out Commercialization Path for VPPs.) 

“Well, a big reason why now is that we are about to experience a tsunami of DER adoption,” Downing said in public remarks. “And that’s true across three categories of DERs.” 

Generation DERs like solar; flexible loads like smart thermostats and water heaters; and distributed batteries are all rolling out over the next decade with almost 25 GWh of capacity by 2030, she said, which pales in comparison to the amount of new load from electric vehicles over the same time period that will add hundreds of megawatts of batteries to be served by the grid. Not all the EVs will be plugged in at once, and often they will be unable to shift when they charge. 

“But if even a fraction of this capacity is available to virtual power plants to help balance supply and demand of the grid, that’s an enormous potential,” Downing said. 

The ability to orchestrate when some of those cars are charged will be key to supplying them with power reliably and affordably, and VPPs can make that happen, Smith said. 

All the changes going on now are transforming the grid, which has generally operated the same way it has since the days of Thomas Edison and Nikola Tesla, she said. 

“But now with increased distributed generation, we’re finally changing the physicality [of] the grid, which is what we’re experiencing right now,” she added. “So, it’s a balance: We’re always going to have central station generation, [but] we’re going to have less of it relative to the overall kind of load demand needs of the grid. More of that demand will be satisfied via on-site generation.” 

Solar is the main agent of change, but storage and fuel cells and other technologies will also play a part. That change is going to impact how much transmission and distribution grids are operated, Smith said. 

FERC Order 2222

FERC Order 2222 was meant to set the stage for that transition, and while it does represent a major step forward, Smith and other CPower executives at a media briefing said that its implementation has fallen short of what the VPP industry would have liked. The implementation was dogged by questions about cost and jurisdiction, said Kenneth Schisler, CPower senior vice president of regulatory and government affairs. 

“But it was a very positive step in the right direction,” Schisler said. “So, let’s recognize that regulation gets to where it needs to be over a period of time. I think we have to acknowledge that even in the markets where we’re not as happy with the result of the implementation of Order 2222, it’s a positive step in the next direction.” 

FERC left a lot of discretion on the details up to the ISO/RTOs and their utilities, which has led to uneven implementation and will likely require a follow-up “Order 2223,” he added. 

No regulator or politician is going to be able to stop the tidal wave of DERs that Downing spoke of, and that transition would be better served by having them play well with the wholesale markets, Schisler said. 

“The question is, do you want these resources operating in the underbrush?” Schisler said. “Or do you want them aggregated where you have visibility and a level of control, and you can begin to model and plan around their expected behaviors? And that’s, I think, where we have a very positive contribution to make.” 

NYISO is the only organized market that has changed its participation model, with all the others using the old DR participation model that does not reflect the major changes the industry has seen in recent years, he added. 

One common issue with ISO/RTOs is they still tend to plan around large, central-station power plants, said CPower Senior Director Aaron Breidenbaugh. 

“If the only tool you have is a hammer, every problem looks like a nail, and to them every problem looks like a 500-MW power plant,” he added. “So, of course, you have to have six-second telemetry. So, of course, it has to be nodally located, or it’s going to completely screw up the price. Of course, it has to be individually metered.” 

While FERC has some work left to do on VPPs and DER integration, the bulk of the activity is going to happen at the state level, where regulators have primary jurisdiction over the distribution system, Schisler said. State laws are helping to drive increased adoption of DERs, and even once skeptical states have started to embrace the role aggregators like CPower can play in coordinating those new resources. 

FERC Order 719 required ISO/RTOs to remove barriers to DR, but it also let states opt out of letting their customers participate in wholesale markets as DR. That was included in the 2008 order because some states felt that DR could be a backdoor way into federally mandated retail competition, Schisler said. 

The commission could end that opt-out now after some recent court findings; it has a pending complaint before it asking it to do so (EL21-12), while U.S. Rep Sean Casten (D-Ill.) has introduced legislation requiring that step. But Schisler argued that the issue should not be forced onto states. 

“I think the opt-out is not constructive, and I would prefer it not be there; taking it away is a different proposition,” he added. “And our approach has been to work with states in the Midwest, and we’ve enjoyed a fair amount of success in the last year. We’re seeing great progress and in states like Michigan, Missouri and Indiana.” 

Missouri especially was a landmark case in part because it never even considered endorsing retail competition, but now it has opened to third-party aggregators like CPower. It is also split between multiple wholesale markets. 

“If a state like Missouri that has figured out a model to make it work, you know, I think other states will follow suit,” Schisler said. 

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Report: Biden Admin to Evaluate LNG Terminal’s Impact on Climate

The Biden administration is planning to delay its decision on approval of a major LNG export terminal in order to evaluate the project’s climate impacts, The New York Times reported.

The delay could extend through the elections in November and could affect 16 other proposed export terminals, the Times reported, citing three unnamed sources. [Editor’s Note: The Department of Energy announced the delay on Jan. 26.]

The decision comes on the heels of an extended pressure campaign from climate activists to stop the projects, with focused opposition on the Calcasieu Pass 2 (CP2) project in Louisiana. If approved, CP2 would be the largest LNG export terminal in the country, with a capacity of about 20 million tons of natural gas per year.

CP2 needs to be first approved by FERC, which evaluates projects’ direct environmental impacts, before it moves to the Department of Energy, which decides whether the export of the fuel is in the public interest, which includes the consideration of upstream and downstream GHG emissions.

But those evaluations do not include any estimate of those emissions’ cumulative impact on climate change. The Times reported that the White House has asked DOE to analyze that, as well as the project’s impact on the economy and national security.

CP2 would essentially be an expansion of an existing export terminal in Cameron Parish, La. FERC approved the first terminal in May 2019, though not without debate among the commissioners over the climate issue. Former Commissioner Richard Glick (D) insisted that FERC had been directed by the D.C. Circuit Court of Appeals to evaluate proposed gas projects’ impacts on climate change, and he dissented on the approval. (See Glick Disputes FERC ‘Breakthrough’ on LNG Projects.) The commission had reached a compromise in which it quantified the upstream and downstream emissions but made no determination as to their impact on climate change.

FERC has continued to insist it cannot “determine credibly whether the reasonably foreseeable GHG emissions associated with a project are significant or not significant in terms of their impact on global climate change”; Commissioner Allison Clements (D) has continued to disagree. (See related story, FERC Approves Pipeline to Supply New TVA Cumberland Gas Plant.)

Climate activist and author Bill McKibben, one of the project’s leading opponents, called the delay “the biggest thing a U.S. president has ever done to stand up to the fossil fuel industry.”

A December letter to the Biden administration signed by 170 scientists said the current queue of LNG export terminals “could lead to 3.9 billion tons of greenhouse gas emissions annually, which is larger than the entire annual emissions of the European Union.”

The letter cited preliminary research from climate scientist Robert Howarth of Cornell University that found lifecycle carbon emissions of LNG are between 24 and 274% higher than coal.

While scientists and climate activists have applauded the decision, it has been met with outcry from the fossil fuel industry. The American Petroleum Institute reposted an opinion from The Wall Street Journal Editorial Board arguing that the delay “won’t reduce global emissions” but “would be a gift to America’s adversaries and show Europe that the U.S. isn’t a reliable ally.”

Senate Minority Leader Mitch McConnell (R-Ky.) called the delay “a functional ban on new LNG export permits,” adding that the administration’s “deference to climate extremists continues to sell out American consumers and U.S. allies.”

A report from ClearView Energy Partners noted that the climate review requirement seems likely to extend to all 17 proposed LNG export projects, although this has yet to be announced. ClearView added that the delay is unlikely to be well received by the U.S.’ European allies, who have relied on LNG exports amid Russia’s invasion of Ukraine.

“If a pause is in the offing, the issue would seem more a political matter than an economic or diplomatic one — that is, mobilizing young, climate-focused voters who could make a difference in closely contested ‘swing’ states,” ClearView said.

According to the Times’ report, the White House is unconcerned about CP2’s contribution specifically, as the U.S. is already exporting so much gas.

A new report from Friends of the Earth, Public Citizen and BailoutWatch pushed back on the narrative that increased LNG exports are needed to support European allies.

“Contracts with European customers represent the smallest share (18%) from pending LNG facilities,” the report found. “Contracts with Asia Pacific customers account for 30% of total volume, with the remaining 52% going to commodity firms and other portfolio buyers.”

The report also said Europe is on track to reduce gas consumption in half by 2030 compared to 2019 levels and concluded that “long-term infrastructure is a poor solution to short-term supply needs.”

Ultimately, the outcome of the pending projects may hinge on the results of the 2024 election. The two remaining Republican contenders, former President Donald Trump and former Ambassador to the U.N. Nikki Haley, have both expressed strong support for increasing domestic fossil fuel production.

“We will export as much liquefied natural gas as we can,” Haley told a New Hampshire crowd in the days leading up to the state’s primary Jan. 23. Shortly after, she was interrupted by several climate activists who criticized her for taking money from the fossil fuel industry.

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Industry Approves New Cold Weather Standard in Final Vote

The impasse over the ERO’s latest cold weather standard has ended, with EOP-012-2 (Extreme cold weather preparedness and operations) finally receiving enough votes from industry stakeholders this week to pass its third formal comment and ballot period. 

The standard went before industry Jan. 16, with voting wrapping up Jan. 22. It received 205 votes in favor and 30 against, for a segment-weighted value of 81% for passage. Fifty-six respondents either abstained or cast no vote. 

NERC’s Standards Committee approved the shortened ballot period at its meeting last month, in hopes of passing the standard before a February deadline imposed by FERC. (See Standards Committee Authorizes Shortened Ballots.)  

The commission ordered NERC to file the standard within a year when it approved the predecessor, EOP-012-1,last February, citing shortcomings in the standard including “undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods.” 

NERC’s Board of Trustees will now consider the standard for approval and submission to FERC. A spokesperson for NERC confirmed that the standard will be on the agenda for next month’s board meeting in Houston.  

The positive result means the board will not have to exercise its authority under section 321 of NERC’s Rules of Procedure to approve a standard without a successful ballot. Board Chair Ken DeFontes warned at the board’s last meeting in December that such action might be necessary to meet FERC’s deadline. (See NERC Board May Force Action on Cold Weather Standard.) 

Voters Focus on Clarity

The margin for EOP-012-2 marks a significant turnaround from the standard’s last ballot round, which closed Nov. 30 with a 58% weighted vote in favor of passage. An earlier vote fared even worse, with only a 44% segment-weighted vote for approval. 

Comments from participants in the most recent ballot round indicated that most stakeholders had come around on the standard. Martin Sidor with NRG Energy said the standard drafting team’s most recent changes would “generally address the issues raised by industry” in previous rounds. Edison Electric Institute said the standard “provides sufficient clarity to allow EOP-012-2 to be auditable.” 

However, ACES Power disagreed, casting one of the few votes against the standard. The energy management company’s comment, which was endorsed by several other participants, expressed “grave concerns” with the proposed standard’s definition of “generator cold weather constraint.”  

The standard defined the term as “a limitation that would prohibit a generator owner from implementing freeze protection measures” in at least one generator component. ACES took issue with the standard’s use of the word “reasonable,” warning that such a vague word could “lead to inconsistent application throughout the … regions.” Other unclear words and phrases cited by ACES included “broadly implemented” and “areas that experience similar winter climate conditions.”  

Donald Lock of Talen Generation cast another “no” vote, similarly fearing that the wording of the standard was not sufficiently clear. As an example, he noted that the expression “reasonable cost consistent with good business practices” could be interpreted to deem “all existing plants to be acceptable since they were winterized per the … business practices of the owner.” 

Lock suggested that “rather than continue to adjust semantics,” NERC should make winterization criteria for new facilities “explicit” — with a list that is actively updated as technology progresses — while urging FERC to allow owners of existing plants to be reimbursed for upgrades. He said the ERO should limit mandatory actions for existing facilities, to include identifying conditions under which forced outages and derates may occur. 

“Above all else, good business practices require that winterization capabilities … must be done right the first time, nor should the goalposts move about over the years,” Lock said.