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November 14, 2024

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NextEra Reports Continued Growth in Renewables

NextEra Energy reported solid quarterly earnings July 24, and its renewables business turned in its second-best quarter ever, signing agreements for more than 3 GW of new renewables and storage.

Data center agreements with Google totaling 860 MW and other additions brought the NextEra Energy Resources backlog to 22.6 GW, even as it placed more than 1.6 GW into service in the second quarter.

During a conference call July 24, CEO John Ketchum updated financial analysts on other aspects of the company’s business landscape, including the figurative elephant in the room: The political party that has embraced the pachyderm as its symbol.

A week after the Republican Party formally designated a truculent renewable energy skeptic as its standard bearer, one of the world’s largest operators of wind, solar and storage might be concerned about the shape of things to come.

But Ketchum reeled off a list of reasons why he is not alarmed by the prospect of a second Trump presidency:

    • Money from Democrat-backed clean energy programs is going disproportionately to Republican-leaning states.
    • Republican lawmakers increasingly are embracing IRA tax credits when they see the impact in their districts.
    • Tax laws are difficult to change.
    • Party majorities are likely to remain narrow in the House and Senate.
    • Renewables create jobs, they sidestep fuel price volatility, they bring down constituents’ power bills and they help meet the growing demand for electricity.

“We’ve always been able to work with both sides of the aisle in the 22 years that I’ve been at NextEra, and I don’t think this time around is any different,” Ketchum said.

The company expects 6 to 8% annual growth in earnings per share through 2027.

NextEra Energy Resources benefits from multiple growth paths, Ketchum said:

There is the replacement cycle, by which higher-cost, lower-efficiency generation is replaced by renewables and energy storage. The company says with its affiliates, it is the world’s leading generator of electricity from wind and sunlight and one of the leading storage operators.

There also is rising demand.

Most markets have seen stagnant demand for decades, Ketchum said, with one of the exceptions being Florida, where NextEra’s FPL operates as the nation’s largest electric utility.

But now, growth is coming across multiple sectors in multiple markets.

“We expect the demand for new renewables to triple over the next seven years vs. the prior seven to help meet this increased power demand,” Ketchum said.

NextEra is ready to help meet the rising demand for clean energy, but it is not ready to turn off its fossil generation — an all-of-the-above solution is needed, he said.

“As the owner and operator of a large natural gas-fired fleet in Florida, we are also conscious of the importance of natural gas-fired generation as a bridge fuel,” Ketchum said.

That said, building new gas-fired generation has become challenging, he added — more expensive and time-consuming in many states.

An analyst asked about the other emissions-free part of NextEra’s portfolio: nuclear. Has there been any thought to restarting the Duane Arnold Energy Center in Iowa?

Its license had been extended to 2034, but it shut down in 2020 after sustaining wind damage.

Yes, Ketchum said — but only thought.

“Sure, we’re looking at it, but we would only do it if we could do it in a way that is essentially risk-free with plenty of mitigants around the approach, and there are a few things that we would have to work through,” he said.

NextEra Energy reported second-quarter 2024 net income of $1.62 billion, or $0.79 per share, on $6.07 billion in revenue.

This compares with net income of $2.8 billion, or $1.38 per share, on revenue of $7.35 billion in the second quarter of 2023.

NextEra Energy stock closed 4.6% higher in trading July 24. It is part of the S&P 500, which was down 2.3% for the day.

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Order 1920 Debated at House Hearing with All 5 FERC Commissioners

At full strength for the first time since the beginning of last year with the addition of Judy Chang this month, all five FERC commissioners appeared at a House oversight hearing July 24 during which representatives questioned them on Order 1920. 

Rep. Jeff Duncan (R-S.C.) — chair of the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security — praised Chair Willie Phillips for moving through the backlog of natural gas infrastructure projects but criticized the landmark transmission rule.

“We are concerned the commission has strayed from its responsibility as an economic regulator to an entity focused on assisting the buildout of so-called ‘green energy’ technologies,” Duncan said. “This is happening despite the continued alarms from [NERC] and … grid operators across the country.” 

Duncan said Republicans are concerned the order’s “skewed ‘categories of factors’ approach to transmission planning” will drive up costs and threaten reliability. He argued that FERC prioritized Democratic-led state renewable energy targets, Biden administration goals and corporate clean power purchases. 

Democrats on the subcommittee supported Order 1920, with Rep. Frank Pallone (D-N.J.), chair of the full committee, saying it builds on the progress of orders 888, 890 and 1000. 

“Failing to plan is planning to fail,” Pallone said. “And the basic principle of Order 1920 is that grid planning is essential to maintaining just and reasonable rates. I agree, and I’ve been encouraged by the reception the rule has received from nearly every corner of the political world except from congressional Republicans. It seems Republicans would prefer that their constituents be slapped with higher power bills because utilities are not required, for example, to plan for the impacts of severe weather on the grid.” 

Phillips said Order 1920 would unlock cheaper sources of power for customers while bolstering grid reliability. 

“Order No. 1920 requires utilities to plan today for the factors that we know will drive tomorrow’s reliability and affordability needs, while requiring that customers pay for new transmission only to the extent that they benefit from that infrastructure,” Phillips said. “Let me say that again: If you don’t benefit, you don’t pay.” 

Commissioner Mark Christie dissented on Order 1920, and he explained his disagreement with the majority on how the order would spread the cost of implementing state policies across multistate RTOs. 

“Order 1000 said that you can cost allocate public policy projects separately from reliability projects; this rule says ‘no, you cannot.’ That is a major, radical change from Order 1000,” Christie said. “So, it didn’t build on Order 1000; it was a radical break from Order 1000.” 

Under the order, public policy and reliability have to be planned for at the same time around a set of required factors, including state renewable targets, with one cost allocation formula based on a set of prescribed benefits for all those projects. Christie said that would spread the costs across all the states in an RTO. 

“The states can even agree on a different formula, and the rule says the transmission provider can just ignore it, so I don’t think that’s fair,” Christie said.  

Order 1920 does require that transmission providers give states a chance to weigh in on cost allocations, Phillips said later in the hearing. But as many rehearing requests pointed out, the transmission providers are not even required to file any proposal coming out of that with the commission. (See FERC Order 1920 Sees Wide-ranging Rehearing Requests.) 

The order was approved in May by Phillips and former Commissioner Allison Clements. The three new commissioners did not get into the debate at the hearing, with Commissioner Lindsay See noting she still is staffing up her office. 

See, who comes to FERC after serving as solicitor general of West Virginia, noted the changing legal landscape facing the commission. 

“In response to the now-smaller margin of error for agency orders after the Supreme Court’s recent decisions cabining agency discretion, I welcome the important check judicial review offers in our separation-of-powers system,” she said, referencing the court’s decision in Loper Bright, which ended Chevron deference. (See Phillips, Christie Debate Loper Bright’s Impact on FERC Order 1920.) 

Chang said her position working for the state of Massachusetts gave her firsthand experience highlighting the importance of having adequate infrastructure, efficient market frameworks and viable approaches to growing the economy while working to cut greenhouse gases. 

“As a commissioner, one of my priorities is ensuring a robust and reliable transmission system, including the use of advanced technologies, to deliver affordable energy to all consumers,” Chang said. “This is paramount to the economic growth of our nation, and this is how the United States will continue to lead the world and compete on the global stage in technological innovation and infrastructure development.” 

Commissioner David Rosner said a key task for the commission is maintaining reliability and affordability in light of the ongoing clean energy transition in terms of both supply and demand. That will require FERC to remain vigilant to the realities of the resources that power the economy. 

“That means continuing to faithfully implement the commission’s longstanding policy of resource and fuel neutrality to allow the next generation of technologies to play their role in the energy system,” Rosner said. “It means continuing to harden the energy system to withstand evolving threats to reliability, including weather, physical and cyber risks.” 

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Pacific NW Hydrogen Hub Launched with 1st Round of Federal Funds

The Pacific Northwest Hydrogen Association (PNWH2) said July 24 that it had secured the first slice of the $1 billion U.S. Department of Energy grant the group won last fall to develop a network of clean hydrogen suppliers and consumers across the region. 

Receipt of the $27.5 million in federal funding marks the official launch of the PNWH2 hydrogen hub, one of seven such hubs across the U.S. being supported by up to $7 billion in funds allocated through the Infrastructure Investment and Jobs Act. (See DOE Designates Seven Regional Hydrogen Hubs.) 

The Northwest hub is the second to launch, coming on the heels of last week’s announcement that California’s Alliance for Renewable Clean Hydrogen Energy Systems hub had secured $30 million in its first round of DOE funding. (See California Reaches Funding Agreement to Launch Hydrogen Hub.) 

Phase 1 funding for PNWH2 will be used to cover “initial planning, permitting and analysis activities to ensure that the overall hub concept is technologically and financially viable,” the group said in a statement. 

The Northwest hub is intended to focus on production of “green” hydrogen, derived from the splitting of water molecules using electricity generated by emissions-free resources. 

“We are excited to embark on Phase 1 and lead the way in building a new clean energy commodity in the U.S. that will benefit generations of families throughout the region,” PNWH2 President Chris Green said. 

The group expects the hub to consist of eight “nodes” across Washington, Oregon and Montana “that will leverage the region’s innovative technology and abundant renewable energy to address the hardest-to-abate end users, such as public transit, agricultural products, medium and heavy-duty transport, and the electric power industry.” 

The hub’s “partners” consist of a range of suppliers, including: Fortescue Future Industries, ALA Renewable Energy, Atlas Agro, Express Ranch Hydrogen and St. Regis Solar for production; Air Liquide for liquefaction and distribution; and Williams Field Service Group for transmission and storage. 

Potential offtakers include Amazon for decarbonizing operations, Portland General Electric and Puget Sound Energy for electricity generation and Northwest Seaport Alliance for deploying hydrogen port trucks and cargo-handling equipment. Two hub partners, MHI Holdings and Lewis County (Wash.) Transit, plan to be both producers and consumers of the fuel. 

Washington State University, with assistance from its Consortium of Hydrogen and Renewably Generated E-Fuels (CHARGE), will manage the “community benefits” plan for the hub in accordance with the Biden administration’s Justice40 initiative, which aims to ensure that 40% of benefits from federal clean energy investments flows to disadvantaged communities. 

“These benefits will include the creation of more than 10,000 quality jobs and the development of STEM-based education programs from K-12 through college to ensure a pipeline of trained and qualified workers to build, then operate and maintain the hub’s hydrogen projects,” PNWH2 said. 

Project management for the hub will be headed by AtkinsRéalis, a Montreal-based global engineering services company. 

“I look forward to seeing how this effort helps us decarbonize transportation and industrial sectors and create good-paying jobs for Washington workers and families for decades to come,” Washington Gov. Jay Inslee said in a statement. “This is exactly what we have been working for here in Washington state over the last 12 years, and the PNWH2 is among the leaders in this effort.” 

“Mitigating climate change requires enormous effort and prioritization of resources. It takes a multistate approach to get things done, like the Pacific Northwest Hydrogen Hub,” Oregon Gov. Tina Kotek said. 

PNWH2 will host a webinar Aug. 21 to share more information about its Phase 1 plans. 

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NRDC: Coal Plants Squeezing Out Cheaper Resources in MISO Market

Coal plants in the Central U.S. are elbowing out lower-cost, cleaner generation and have collected more than $1 billion in uneconomic payments over a three-year span, the Natural Resources Defense Council said in a new report.

NRDC secured Grid Strategies to conduct the report: “The Consumer and Environmental Costs from Uneconomically Dispatching Coal Plants in MISO,” which concluded uneconomic dispatch of coal plants remains a problem in MISO, where coal plants operate even when inexpensive wind and solar generation is available through self-commitment, self-scheduling and unrealistic market bids.

The report found that coal plants collected about $1.1 billion in uneconomic payments from 2021 to 2023 and forced 3.8 million MWh of renewable generation curtailment while emitting 5.2 million short tons of avoidable carbon pollution.

According to the report, coal plants in MISO are operating for extended periods when their marginal costs are run at a loss for extended periods of time while “crowding out cleaner, cheaper resources.”

NRDC said the problem was the starkest in Louisiana and Indiana, which accounted for $341 million and $338 million in economic losses, respectively. The report also called out North Dakota, where coal plants realized $120 million in unjustified payments from 2021 to 2023. Otherwise, the report found that coal generators in MISO states took in anywhere from $2 million to $69 million in uncompetitive payments.

NRDC said the worst offenders included Cleco’s Big Cajun II in Louisiana, Duke’s Gibson Generating Station in Indiana and NIPSCO’s R.M. Schahfer Generating Station in Indiana.

North Dakota was host to the most renewable energy curtailment to accommodate uneconomic coal generation, NRDC said, at 1,516 GWh in curtailments over the three-year period. Two other wind-rich states rounded out the most renewable curtailments: Iowa at 755 GWh and South Dakota at 671 GWh.

“Customers shouldn’t have to pay higher bills to keep dirtier, more expensive coal plants online,” Dana Ammann, policy analyst at the Sustainable FERC Project at NRDC, said in a press release. “Grid operators need to stop this inefficient practice and make these plants compete on a level playing field.”

NRDC said MISO should clamp down on coal operators’ “ability to supply power to the grid more or less at their own discretion — regardless of cost or rules.” The organization said power markets have an obligation to ensure the cheapest resources are run first.

NRDC recommended MISO resolve to decommit uneconomic generators, move to a probabilistic unit commitment system, design voluntary multi-day markets or look-ahead tools and work to ensure the accuracy between generator bids and units’ actual operating parameters. FERC also could “act on the basis that conventional generator self-scheduling and self-commitment result in undue discrimination against renewable resources,” NRDC said.

The organization further said state commissions should stop utilities from recovering uneconomic dispatch in costs and review fuel supply contracts to “ensure they do not perversely incentivize uneconomic dispatch.”

“When uneconomic coal plants displace wind and solar power, it sends a signal to reduce future development of those projects. Coal plant operators shouldn’t get a bailout from customers,” Ammann said.

MISO said it has not reviewed the findings or the report’s methodology.

“MISO works closely with our members, state regulators and our independent market monitor to ensure our markets are efficient,” spokesperson Brandon Morris said in an emailed statement to RTO Insider. 

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GE Vernova Finds Defect in Vineyard Wind Blade

A manufacturing defect has been identified in the high-profile failure of a wind turbine blade off the Massachusetts coast. 

The defect is believed to be isolated, but the other hundred-plus blades made at the same factory will be inspected to be sure, GE Vernova told financial analysts July 24 during a conference call about its second-quarter earnings. 

The company said its wind-power operations continue to operate at a loss, and the Vineyard Wind 1 blade failure on July 13 could expose it to potentially significant claims for monetary damages, but it still expects its wind business to become profitable in 2025. 

Accelerating growth for its gas power business — including orders for 49 gas turbines totaling 9 GW of nameplate capacity in the first half of 2024 — gave GE Vernova a profitable quarter. 

The company expects gas turbine orders to be even higher in the second half of this year. 

Wind Problems

The breakup of iconic conglomerate General Electric concluded at the end of the first quarter of 2024, when its power components spun off as GE Vernova from what is now known as GE Aerospace. 

GE Vernova is heir to 130 years of electrical innovation founded by Thomas Edison in Schenectady, N.Y., and it posts some impressive numbers: Its 7,000 installed gas turbines are the largest fleet worldwide by megawattage, the company boasts, while the 55,000 wind turbines bearing its name exceed 100 GW of nameplate capacity and hold the largest segment of the U.S. market. 

A technician works on a gas turbine system generator under construction at GE Vernova’s plant in Schenectady, N.Y. | GE Vernova

But there have been some quality control problems in the wind business. 

In an October 2022 call, General Electric CEO H. Lawrence Culp Jr. spoke of the warranty costs that had become a drag on the financials of what then was GE Renewable Energy. 

In mid-2024, two AEP subsidiaries — Public Service Co. of Oklahoma and Southwestern Electric Power Co. — sued GE Renewables North America LLC in a New York court. 

They claimed numerous material defects had arisen within two to three years of start of operation of a fleet of 426 turbine sets at three facilities in Oklahoma, knocking a significant number out of service and suggesting expensive repairs ahead for many others. The lawsuit describes a damaged blade being “liberated” from its hub in May 2023. 

The Vineyard Wind blade failure was a much higher-profile affair, given the controversial nature of offshore wind, the number of opponents fighting to keep it from developing as a U.S. clean energy sector and the summertime beach closures that resulted as fragments washed ashore. (See Blade Failure Brings Vineyard Wind 1 to Halt.) 

In its communications about the incident, Vineyard has emphasized that it was a GE Vernova equipment failure. 

GE Vernova CEO Scott Strazik said July 24 that the search continues for the root cause of the Vineyard Wind failure but that a “manufacturing deviation” has been identified in the blade that buckled and disintegrated. No design flaw has been identified, nor any connection to a recent blade failure at the Dogger Bank Wind Farm in England, which was blamed on an installation error. 

The Vineyard Wind blade was fabricated by GE Vernova subsidiary LM Wind Power. Strazik said the quality assurance process should have caught the defect, so it will reinspect the roughly 150 other offshore wind blades that have been manufactured at the same factory in Gaspe, Quebec. 

Construction has been halted on Vineyard as the investigation continues, with about a third of the turbines installed. But Strazik said installation work continues at Dogger. 

Strazik indicated the company is looking to make more money in future offshore wind contracts. 

“Going forward,” he said, “we will remain highly selective on new offshore orders, focused on achieving substantially higher pricing and disciplined commercial terms.” 

The finances of GE Vernova’s wind business were a recurring theme on the call. 

“Right now, wind remains the most challenging segment,” Strazik said.  

And that is not just offshore — onshore wind customers are navigating challenges with permitting delays and higher interest rates. Then there are the defects. 

“We are nearly two years into our onshore wind quality improvement program, and we are making progress, with no new significant issues identified,” he added. 

GE Vernova is trying to accelerate updates to the existing onshore fleet, adding crews in the field and lining up more cranes. A blade inspection robot has been used to enhance the manufacturing process, and the company is optimistic about the future. 

“Longer term, wind should play a critical role in the energy transition,” Strazik said. 

Gas Growth

In the shorter term, GE Vernova is doing a brisk business selling and servicing equipment that could continue to burn natural gas for decades. 

The company announced July 10 it would expand generator production and add more than 150 jobs at its ancestral home, the Schenectady campus that General Electric shrank relentlessly over the course of decades.  

A financial analyst asked if the sharp growth in gas power orders is due to GE capturing a greater percentage of the existing market or the market itself expanding. 

“It’s a combination of U.S. orders and global orders,” Strazik replied. “We’re not in a place today where this is one transaction, one market.” 

Demand for electricity is rising amid the growth of data centers and the push to electrify large segments of the economy. CFO Ken Parks said: “Looking ahead, we see increased demand for gas as a reliable source of baseload generation, which is resulting in incremental growth opportunities for both gas equipment and gas services over the medium to long term.” 

Another analyst asked if GE Vernova could meet the rising demand for gas equipment that utilities are voicing. 

GE Vernova’s facilities have capacity to grow, Strazik said, but there are chokepoints. 

“We do have challenges and need to work across our supply base and supply chain to gain access to more parts — think castings and forgings. That very well may lead to some investments we need to make to support this growth on a go-forward basis.” 

GE Vernova’s smallest business segment by revenue, electrification, reported strong demand and significant revenue growth for the second quarter. 

For the three months ended June 30, GE Vernova reported $1.28 billion in net income on total revenue of $8.2 billion, yielding diluted earnings per share of $4.65. This compares with revenue of $8.1 billion in the same quarter of 2023 and a net loss of $149 million, or $0.55 per share. 

GE Vernova stock closed 4.5% lower July 24. It is part of the S&P 500 index, which was down 2.3% for the day. 

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CISA Executive Director to Step Down

Brandon Wales, the executive director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) who briefly led the organization at the beginning of the Biden administration, will leave the agency by next month, CISA said this week.

CISA Director Jen Easterly confirmed Wales’ departure in a statement posted on the agency’s website July 23. She praised Wales for having “guided CISA through some of the most serious threats facing our nation,” such as the SolarWinds compromise of 2020 and the Colonial Pipeline ransomware attack of 2021. Both incidents occurred while Wales was acting director.

Bridget Bean, who has been assistant director of CISA’s Integrated Operations Division since 2021, will take over as executive director in August, Easterly said. According to her bio, Bean “leads the agency’s efforts around coordinating, collaborating and executing CISA’s operational activities to ensure seamless support and expedited responses to critical needs.” Her previous experience in government includes five years at FEMA and 21 years at the Small Business Administration. She also served as president of consulting firm Via Stella for 11 months before joining CISA.

“With more than three decades of federal government service, Bridget brings extraordinary leadership and experience to the role, which will involve a dedicated focus on operationalizing a fully unified and cohesive team,” Easterly said. “We thank Brandon for all he has done for CISA and the nation and thank Bridget for stepping into this critical role.”

The news of Wales’ departure came a week after CISA announced the formal appointments of acting executive assistant director for cybersecurity Jeff Greene and acting assistant director for stakeholder engagement Trent Frazier to fill their positions permanently. Greene’s role is leading “CISA’s mission to protect and strengthen federal civilian agencies and … critical infrastructure against cyber threats,” while Frazier’s involves “overseeing the agency’s national and international partnerships and stakeholder outreach programs.”

Wales has been with CISA since December 2019, having previously served in DHS as senior counselor for cyber and resilience, director of the Office of Cyber and Infrastructure Analysis, and director of the Homeland Infrastructure Threat and Risk Analysis Center.

Wales stepped up to lead CISA in December 2020 after Chris Krebs, who had led the agency since its founding in 2018, was fired by then-President Donald Trump for asserting — along with other federal security agencies — that the presidential election, which Trump lost, was not the subject of fraud. (See After Contradicting Trump, Krebs Out at CISA.) Trump passed over Krebs’ deputy Matthew Travis, who resigned the same day, to name Wales to head the agency; unlike his superiors, Wales was a career civil servant and could not be removed without cause.

According to Wales’ bio, his nine-month tenure as CISA chief included “completing the stand-up and reorganization of the agency following the … CISA Act of 2018” that formally established CISA as an independent agency. During his time at the top, he also led CISA’s response to the SolarWinds and Colonial Pipeline attacks, the former of which has been attributed to Russia’s Foreign Intelligence Service.

Wales handed the reins over to Easterly, a former Morgan Stanley executive and cyber policy lead for President Joe Biden’s transition team, upon her confirmation by the Senate in July 2021. (See Senate Confirms Easterly as CISA Chief.) Following Easterly’s arrival, Wales reverted to his previous position, where he headed the U.S. federal government’s response to Russia’s invasion of Ukraine in February 2022.

“It has been an honor to serve with Brandon Wales over the past three years,” Easterly said. “With more than 20 years of federal service, including more than 19 at [DHS], he was here before we were CISA and expertly helped shape the agency into what we are today.”

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Report Says New Energy Metrics Needed

A report released last week by NERC and the National Academy of Engineering (NAE) said the industry’s “traditional resource adequacy models … do not adequately account for the essential role that electricity plays in modern society” and recommended multiple ways the ERO can improve its approach to resource adequacy.

“Evolving Planning Criteria for a Sustainable Power Grid” arose from a workshop sponsored by NERC and NAE’s Section 6, the part of the academy covering electric power and energy systems. Workshop participants focused on the criteria for planning resource and transmission adequacy on the grid.

The report also is intended as a complement to the academy’s “Creating a Sustainable Electric Infrastructure While Maintaining the Reliability and Resiliency of the Grid” report, which resulted from an earlier workshop hosted by Section 6 in October 2022.

“There is little doubt that our dependence on electricity as the engine of our economy is increasing at a rapid pace,” NERC Chief Engineer Mark Lauby, co-chair of the workshop, said in a statement. “As the grid transforms, it is imperative that traditional planning criteria evolve to reflect a new reality in which energy adequacy becomes a critical complementary consideration of resource adequacy when addressing overall system reliability.”

According to the new report, participants in the March workshop concluded that traditional resource adequacy models and approaches do not account for “the growing risk, over all hours, arising from increased variability and uncertainty caused by the evolving resource mix and increasing demand levels.” These models are based around a loss-of-load expectation (LOLE) of one day in 10 years, with a focus on satisfying load during peak hour conditions.

However, participants noted this strategy has become less effective in recent years as the contribution of intermittent generation resources like solar and wind has grown. The presence of battery energy storage systems (BESS), which act as load at some times and as generation at others, also complicates the thinking around resource adequacy.

A chart shared in the workshop illustrated the “complex interplay between solar and energy storage,” depicting the load and generation in CAISO for June 25, 2023. It showed solar generation rising from comprising 0 MW of the generation mix in the early morning hours to accounting for 88%, along with wind, at one point in the afternoon. Meanwhile, BESS facilities in the state absorbed the solar and wind generation during the points of highest output, then switched to output in the evening when solar resources dropped off.

The report mentioned initiatives by grid stakeholders to move beyond LOLE, such as the Regional Energy Shortfall Threshold under development by ISO-NE. It also noted that other measurements are used in different parts of the world; for instance, grid operators in several European countries use the loss of load hours (LOLH) metric, and the Australian National Energy Market uses expected unserved energy to measure potential loss.

Rather than endorsing a specific metric, the report recommended NERC adopt a “multi-metric approach supplementing LOLE with EUE and LOLH” to allow more flexibility in forecasting. Other recommendations include “continuing the evolution of the resource adequacy criterion, collecting quality data, building composite plans across the interconnections, tracking demand increases resulting from electrification, improving coordination of transmission with distribution and improving benchmarking metrics to enhance the energy adequacy assessment process.”

The report also suggested NERC change its approach to the annual 10-year Long-Term Reliability Assessment to incorporate advanced energy metrics that can reflect energy frequency, event duration and event magnitude risks. It noted NERC “will need to educate federal, state and local regulators on the need to evolve planning modeling processes due to the changing grid,” and said the ERO should continue to work with industry groups to “move the needle toward a more reliable, resilient and secure” North American grid.

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California Wildfire Fund Could be Model for US, Panelists Say

A California wildfire fund created by state lawmakers in 2019 could serve as a model for a similar nationwide fund, speakers said during a webinar July 22 hosted by Americans for a Clean Energy Grid (ACEG). 

Assembly Bill 1054 of 2019 established the fund, which utilities may tap into to pay claims for damages resulting from a wildfire caused by utility equipment. Money in the fund comes equally from utility ratepayers and shareholders. 

Pacific Gas and Electric, Southern California Edison, San Diego Gas & Electric and Bear Valley Electric are fund participants. The California fund is expected to grow to $21 billion. A bill creating a similar fund in Utah was signed into law this year. 

While such a fund is possible for California, which ranks as the world’s fifth-largest economy, it might not be feasible for other states, said webinar speaker Riaz Mohammed with the Edison Electric Institute. 

“We’re not sure that the financial wherewithal is there for a state-specific fund,” said Mohammed, EEI’s senior director of resiliency and environmental policy. 

Mohammed said the institute is exploring the possibility of a national wildfire fund that would mix elements of California’s AB 1054 and the Price Anderson Act, which established a fund to pay members of the public harmed by a nuclear incident. 

The idea would be to create a federal fund that does not preempt any state wildfire funds, he said. 

Limiting Liability

EEI also is focusing on legislation that would limit utilities’ liability for wildfires. 

Although inverse condemnation is a California law that views damages caused by a utility’s equipment to be a “taking” of private property even when negligence isn’t demonstrated, Mohammed said the concept has spread to other states. 

“What we’re seeing across the country is that there’s really no distinction when it comes to wildfire damages or awards,” he said. “Inverse condemnation is what is being applied even if that’s not the law.” 

Courts also have awarded punitive and pain-and-suffering damages in wildfire cases to people who have not been economically or physically harmed, according to Mohammed. 

The key to a system for limiting liability would be a requirement for utilities to have a wildfire mitigation plan in place, he said. For those that do, one possibility would be sending wildfire claims to federal court, where damages would be limited, and bypassing the state courts. Mohammed said EEI is “kicking around” that idea. 

Safety Certifications

Under California’s AB 1054, a fire safety certification is a central element. Without the certification, utilities still may pay into the fund and access it when needed.  

But when it comes time to reimburse the fund, utilities with a safety certification are presumed to have acted prudently unless regulators determine otherwise, according to Melissa Semcer, principal consultant with Climate, Wildfire and Energy (CWE) Strategies. If they acted prudently, utilities can repay with 50% ratepayer funds and 50% shareholder funds, rather than repaying solely with shareholder funds, Semcer said. 

Safety certification requirements in California include having a wildfire mitigation plan, safety culture assessments and evidence of making progress on previous plans. In addition, executive compensation must be based at least 50% on safety metrics. 

“That is actually a game changer,” said Semcer, who previously was the deputy director of the California Office of Energy Infrastructure Safety. 

Panelist Letha Tawney, a commissioner with the Oregon Public Utility Commission, said a wildfire fund raises societal issues. 

“In an electric bill, you’re asking ratepayers to cover rebuilding from catastrophic wildfires,” she said. “Is that really what ratepayer bills should be doing?” 

“And what does it mean for everyone who was still impacted by a wildfire, and it wasn’t utility caused? Where are they supposed to go?” Tawney added. 

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CenterPoint Under Fire for Beryl Response

Beleaguered Texas utility CenterPoint Energy has come under fire from the state’s political leadership, lawmakers, regulators and residents over its slow restoration efforts following a Category 1 hurricane. 

The heat is only intensifying. 

Gov. Greg Abbott (R) has ordered CenterPoint to file a plan with his office by July 31 that outlines how the utility will improve its preparation and response practices before the next hurricane hits. If CenterPoint fails to comply, he threatened to oppose any future rate increases brought to the Public Utility Commission, whose members he appoints. 

“CenterPoint Energy has lost the faith and trust of Texans. … Texans deserve better from their electrical companies,” Abbott wrote in a letter to company CEO Jason Wells. 

Abbott also directed the PUC to conduct a “rigorous” study to determine the causes of “repeated and ongoing power failures” in the Houston area after severe weather events. A mid-May derecho knocked out power to more than 1 million CenterPoint customers, some for as long as 17 days. 

The governor asked the PUC to determine whether the large customer outages are a result of a physical infrastructure or personnel issue. Abbott said the commission must identify why Hurricane Beryl affected millions of Texans when similar events in the recent past did not and file a report to the state legislature by Dec. 1 (56822). 

“I think it’s clear from the events of the past week that the quality of their infrastructure, their ability to maintain that infrastructure and their communication with their customers has been called into question,” PUC Chair Thomas Gleeson said during a July 14 news conference. 

Lt. Gov. Dan Patrick (R), who said CenterPoint “underestimated” Beryl’s force and direction, created a special committee in the state Senate on hurricane and tropical storm preparedness, recovery and electricity. The committee, charged with reviewing “certain utility companies’” response and establishing why they “appear to have been woefully unprepared for Hurricane Beryl,” will hold its first hearing July 29. 

The state House will join the inquisition two days later when its State Affairs Committee conducts an oversight hearing on recent electric industry legislation. It has added an agenda item assessing “utility preparedness, response and recovery protocols” and reviewing performance during severe weather events. 

When Beryl barreled ashore July 8, it left 2.7 million people without power. (See Hurricane Beryl Leaves 2.7M Customers Without Power.) 

As of July 23, more than 1,600 CenterPoint customers were without service. The utility said it had restored almost 73,000 customers in the previous 24 hours, although not all outages stemmed from Beryl. CenterPoint has not issued a public update since July 17, when it said power to 98% of customers had been restored. 

In an email to RTO Insider, CenterPoint said it has restored power to all customers “who are able to receive power.” It said remaining outages are “predominantly isolated instances” in which severe home damage or damage to customer-owned equipment has made restoration difficult. 

Entergy Texas, which lost power to more than 252,000 customers when Beryl hit July 8, said July 16 that it expected to restore electricity to all its customers who could safely take power. Its outage count was less than 600 on July 23, according to PowerOutage.us. 

It is CenterPoint that has drawn much of the ire from Houston residents. Half of the 22 deaths caused by the storm have been attributed to slow restoration efforts and triple-digit temperatures. 

Houston Mayor John Whitmire (D) has threatened to hold CenterPoint accountable by documenting the trouble it has given City Hall. 

“I’m pretty fired up at them. They made my job tougher by not doing their job,” Whitmire told the Houston Chronicle. 

CenterPoint’s shortcomings will provide plenty of fodder for those investigating the utility.  

It was ridiculed nationally for an outage map that was less reliable than a hamburger chain’s app and it has been criticized for its lack of preparation before the storm. Utility representatives told the PUC during a July 11 open meeting they were surprised by the damage Beryl caused in the heavily wooded areas north and east of Houston. (See Texas Utilities: Beryl’s Damage Unlike that of Cat 1s.) 

CenterPoint has spent more than $800 million in recent years on 15 32-MW generators and five smaller ones. However, the 15 massive generators are not designed to be mobile and were never used during the storm. 

The utility has also come under fire for poor tree trimming and maintenance and its poor communication from the top down. Wells filmed a message to Houstonians from an office setting during which he mentioned he had a generator at home, all while sitting next to a thermostat that read 70 degrees. 

In April, CenterPoint filed a $2.3 billion resiliency plan as a result of 2023 legislation. The Texas Consumer Association has asked that the plan be delayed until the probes into the utility have concluded. CenterPoint has already estimated repairing the derecho’s damage will cost about $475 million. 

Separately, Entergy has filed a rate increase with the PUC to recover $6 billion in infrastructure investments since 2019. 

The heat continues to build. 

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Mass. Legislature Faces Looming Deadline to Pass Permitting Reform

With Massachusetts’ legislative session ending July 31, lawmakers are on the clock to reach an agreement on a major climate bill centered around clean energy permitting and siting reform.

Culminating over a year-and-a-half of work on a wide range of proposed climate legislation, the Senate passed an omnibus bill in late June (S.2838), and the House of Representatives followed with its own legislation on July 17 (H.4884).

The bills contain closely aligned changes to how the state permits clean energy infrastructure but vary significantly beyond the permitting provisions and have elicited mixed responses from clean energy advocates in the state.

Permitting reform has been a major focus of the session. A state commission — featuring the House and Senate co-chairs of the Joint Telecommunications, Utilities and Energy Committee — issued recommendations in April. This was followed by negotiations between the two chairs and the administration of Gov. Maura Healey (D). (See Mass. Commission Issues Recs on Energy Project Siting, Permitting and Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.)

The resulting proposal would streamline and consolidate state and local permitting of clean energy infrastructure. For large projects, the state’s Energy Facilities Siting Board (EFSB) would approve them through consolidated permits that encompass “all municipal, regional and state permits that the large or small clean energy infrastructure facility would otherwise need to obtain individually.”

Municipal permitting would remain under local control but be incorporated into the consolidated EFSB process. For smaller projects, all municipal permits similarly would be consolidated into a single application and approval process.

For large clean energy infrastructure projects — defined as including generation, storage, transmission and distribution infrastructure — the EFSB would be tasked with setting approval timelines that are specific to the infrastructure type, capped at 15 months after an application is deemed complete. Only the final consolidated permit could be appealed to the Massachusetts Supreme Judicial Court.

The approval timelines for small projects would be capped at 12 months. The local permitting decision could be contested with the EFSB, which would have six months to either affirm or overrule the local permitting decision.

The clean energy permitting provisions have received strong support from renewable developers.

“The solar and storage industry is glad to see lawmakers continue to push forward on common-sense reforms to reinforce the commonwealth’s place as a national clean energy leader,” Valessa Souter-Kline, the Solar Energy Industries Association’s Northeast regional director, said in a statement. “The reforms include time limits for permitting decisions, a streamlined appeals process and more predictable interconnection that will provide critical certainty for solar and storage businesses.”

Dan Dolan, president of the New England Power Generators Association, praised the approval time frames and consolidated EFSB process, adding there’s “a meaningful benefit to sending the subjective policy message that there needs to be an ‘all hands on deck’ approach to getting projects sited in the commonwealth.”

The legislation also includes funding that would help community organizations participate in EFSB and Department of Public Utilities proceedings. It would require developers to submit a cumulative impact analysis (CIA) intended “to evaluate and minimize the impacts of large clean energy infrastructure facilities in the context of existing infrastructure and conditions.”

While the CIA requirement has been a key priority of environmental justice advocates in the state, some have expressed concern the language included in the House and Senate bills is inadequate.

John Walkey, of the environmental justice group GreenRoots, said advocates are concerned the CIA definition will fail to include “a holistic consideration of all the factors that go into how environmental burdens are sited and experienced.”

“As we get ready for the conference committee, the CIA definition is still falling short,” Walkey said. “We hope that in the few opportunities that remain, the language will see the small adjustments needed to bring it in line with established practice.”

The changes also include provisions intended to contain costs associated with new electric transmission and distribution infrastructure. Developers would be required to consider advanced transmission technologies to receive approval. (See Panelists Call for a More Holistic Approach to Advanced Transmission Tech in Mass.)

Gas utilities would be required to consider “non-pipeline alternatives, the repair or retirement of pipelines, and other alternatives” to minimize costs when evaluating solutions to system needs.

Significant Differences

There are some significant differences between the two versions of the bill, with the Senate taking a more aggressive approach to phasing out gas infrastructure.

In approving requests for gas service, the Senate bill would direct the DPU to review climate impacts and whether there are other viable alternatives to gas heating. It would authorize gas utilities to submit decommissioning proposals for portions of the gas system and terminate gas service to customers along these segments, as long as customers receive “continuous access to safe, reliable and affordable energy services,” shifting their obligation to provide gas service to residents to an obligation to provide thermal energy services.

The bill also would require annual filings from the gas distribution companies “to ensure each gas company is meeting the appropriate pace to preserve and improve public safety, improve infrastructure reliability, minimize the risk of stranded assets and reduce greenhouse gas emissions.”

“The Senate’s provisions on the gas system are really important,” said Kyle Murray of the Acadia Center, adding they would “give the DPU the tools necessary to pursue an ordered transition off of natural gas.”

Caitlin Peale Sloan of the Conservation Law Foundation said the Senate bill includes “important early steps that we could put in place now” to help decarbonize the gas system while limiting long-term costs to ratepayers.

“Nothing in this space happens quickly — ever — so that’s why it’s important to be taking action now,” Sloan said.

Other components of the Senate bill include a ban on third-party competitive electric suppliers in the state, additional funding for electric vehicle rebates, provisions intended to increase access to EV charging and a requirement for the Massachusetts Bay Transportation Authority to fully electrify commuter rail service in the state by 2030.

In contrast, the House bill largely sidesteps the issue of gas system decommissioning and would not ban the practice of competitive residential electricity supply in the state.

Instead, it focuses on promoting energy storage and would direct electric utilities to pursue competitive solicitations for up to 5,000 MW of energy storage, including 750 MW of long-duration storage (between 10 and 24 hours) and 750 MW of multiday storage (greater than 24 hours).

The bill also includes language to promote advanced metering infrastructure, scale up a network of fast EV charging hubs across the state and create a study into the “feasibility of the electric vehicle-only sales mandate, which becomes effective in 2035.”

Both bills also include provisions that would enable additional procurement of clean energy. The House bill would authorize long-term contracts (up to 30 years) for up to 9,450 GWh of clean energy, while the Senate bill would give the Department of Energy Resources broad discretion to procure clean energy as needed to meet the state’s statutory climate targets.

Despite the differences in the bills, top legislators from the House and Senate have indicated they expect to reach some compromise by the end of the session.

“These are long bills; it will be interesting to see what shakes out,” Sloan said. “It’s still just the tip of the iceberg of what needs to be done on climate.”