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November 14, 2024

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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.”

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Dam It! How the Hydro Industry and Environmental Groups Found Common Ground

It was 2018 and the hydropower industry and environmental and tribal advocates had battled themselves to a political stalemate, recalled Kelly Catlett, hydropower reform program director with the nonprofit American Rivers.

The environmental and tribal groups had enough votes in Congress to kill any bill supported by the industry, which likewise had the votes to kill any bills being advanced by the environmental and tribal groups, Catlett said during a July 18 briefing on how the opposing sides came together to find common ground through an “Uncommon Dialogue.”

“We weren’t getting anything done,” Catlett said. “We didn’t have open lines of communication. We didn’t understand each other’s perspective.”

While frequently discounted as renewable energy, hydropower accounts for close to 30% of carbon-free generation in the U.S., and unlike wind and solar, can provide dispatchable, flexible generation. According to the National Hydropower Association (NHA), hydro makes up just over 6% of U.S. power generation but provides 40% of the nation’s black start capacity.

At the same time, hydro comes with a legacy of concerns about its impacts on the environment and tribal land and fishing rights, on top of the usual permitting challenges, all of which have raised multiple obstacles to maintaining and expanding hydro and hydro pumped storage in the U.S.

Convened by Stanford University’s Woods Institute for the Environment, the Uncommon Dialogue on hydro aimed to change the adversarial dynamics of hydropower development, with a series of meetings where industry and environmental groups, government officials and academics could talk and listen to each other and build trust.

Participants included river advocates American Rivers and American Whitewater, the NHA, Natel Energy, a developer of fish-friendly hydropower turbines, and the U.S. Department of Energy, in an observer role.

“Where we [found] common ground is when we started thinking about it as dams,” said Malcolm Woolf, president and CEO of the NHA, noting that only 3% of the more than 90,000 dams in the United States produce electricity. The other 97% were “built for flood control, for irrigation, for water storage, for navigation, sometimes for recreation.

“By focusing on dams … we’re able to talk and make progress, I hope, both on carbon-free generation and river restoration,” he said.

The result, in 2020, was a joint statement from dialogue participants identifying seven areas for ongoing collaboration, including improving hydropower technologies to increase generation efficiency and output, improving dam safety and river restoration and accelerating licensing and relicensing of dams and pumped storage hydro facilities.

Moving forward on those points of collaboration has become increasingly important as a growing number of U.S. hydroelectric dams are up for relicensing ― a long and expensive process ― and many hydro dam operators consider surrendering their licenses, rather than contend with the cost and uncertainties of relicensing, Woolf said.

Either licensing or relicensing can take seven years or, in some cases, decades, he said. “You don’t know how long it’s going to take. You don’t know what’s going to be required, and so every part of the process creates uncertainty and prevents people from investing in modernizing their existing fleet or building more.”

No new dams or pumped storage hydro have been built in 20 years or more, he said, and according to DOE, between 2010 and 2022, 68 hydro projects totaling 322 MW surrendered their licenses.

Bills Supported but Stalled

Given the current deep divisions in Congress, continuing the work of the Uncommon Dialogue also has become essential on the policy front, Catlett said.

A broad range of industry and environmental groups support a set of bills aimed at maintaining and expanding hydro in the U.S. The bills were introduced in Congress last year, with both Democratic and Republican sponsors.

The Maintaining and Enhancing Hydroelectricity and River Restoration Act (S. 2994/H.R. 6653) seeks to provide existing hydro projects with the same kind of tax credits the Inflation Reduction Act offers to new hydro projects and other renewable or carbon-free power. Under the bill, a 30% tax credit would be available for hydroelectric projects that improve safe passage for fish, dam safety, water quality and public uses of and access to public waterways. The tax credit also would be available for projects that add power generation to an existing nonpower dam.

On the permitting side, separate and slightly different bills also were introduced in the House and Senate.

The Hydropower Clean Energy Future Act (H.R. 4045) officially defines hydro as renewable energy “for purposes of all Federal programs” and allows FERC on a case-by-case basis to exempt small hydro projects of less than 40 MW from some or all licensing requirements.

The bill also would give FERC a two-year cap on licensing for any hydropower or pumped storage projects deploying “next-generation” hydro technologies, for example, run-of-river hydro or technologies that “protect, mitigate, or enhance environmental resources, that [are] not in widespread, utility-scale use in the United States.”

In the Senate, the Community and Hydropower Improvement Act (S. 1521) puts a two-year cap on permitting for the addition of hydropower to existing dams and a three-year limit for licensing of closed-loop or off-stream pumped storage projects. The bill includes provisions that make engagement with tribal governments mandatory for hydro or pumped storage projects located on tribal lands and create a pathway for tribes to submit recommendations to FERC on the protection of fish and wildlife habitats.

While H.R. 4045 has been voted out of committee to the House floor, the other bills have not moved forward since their introduction last year.

Pivotal role

The U.S. Energy Association sponsored the July 18 event, and Woolf, a fervent proselytizer for hydro, came armed with facts and figures about the pivotal role NHA sees hydro playing in the energy transition.

Hydro generation powers 30 million American homes and businesses, while also providing flexible, dispatchable power for grid support services. Hydro pumped storage makes up 96% of the nation’s long-duration energy storage.

“It’s 80 GW of hydropower capacity and another 22 GW of pumped storage; so, it’s over 100 GW of largely dispatchable, flexible, carbon-free generation, and that’s in the United States,” Woolf said. Globally, hydropower produces more energy than all other renewables combined, he said.

Hydropower capacity in the U.S. has expanded slowly in recent years, due primarily to upgrades at existing projects or the addition of power generation to previously nonpower dams, according to the Department of Energy’s 2023 Hydropower Market Report.

From 2010 to 2022, about 2.1 GW of new hydro capacity came online, 75% of which was nonpower dam retrofits. New projects, however promising, move slowly.

At the end of 2022, the U.S. had 117 new hydro facilities in the development pipeline, but only eight were under construction, and 95% of the projects were nonpower dam retrofits, according to DOE. The pumped storage pipeline included 96 projects, only 10 of which have advanced beyond basic feasibility studies. Three had received permits from FERC; none were under construction.

The two Cushman dams in Washington state provide a case study on the challenges of hydropower relicensing, said Mary Pavel, a partner at Sonosky, Chambers, Sachse, Endreson & Perry LLP and a member of the Skokomish Tribe. When the dams originally were permitted back in the 1920s, her tribe’s fishing rights largely were ignored, and tribal access to the Skokomish River and fishery essentially were wiped out, Pavel said.

Sockeye salmon disappeared from the river for decades, which she called “an act of genocide.” Dams like the Cushman are “stealing” energy, Pavel said. “You’re stealing energy that’s necessary for my fishery resource, my wildlife resources or my cultural resources or my aquatic resources. That energy is there for a reason.”

Relicensing the dams took over 30 years and ended with a settlement between the tribe and Tacoma Public Utilities, which included a $50 million project to return salmon to the river, along with the return of tribal lands and cash payments totaling about $35 million, according to local media reports.

Both Catlett and Woolf agreed the era of building large dams is over, in part because the best sites already are developed. But Catlett said intensive community engagement will be critical to ensuring the mistakes of the past are not repeated.

“We need to be designing projects to avoid aquatic ecosystem impacts and impacts to the communities in which they are situated and think a little deeper about these projects and the way they are going to interact with the communities around them,” she said.

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NJ Backs New Gas Plant, Sparks Opposition Anger

In a test of New Jersey’s new environmental justice law, the state Department of Environmental Protection (DEP) has concluded that a controversial proposal to build a gas–fueled generating plant in Newark can move forward, despite the high density of other emissions-generating plants in the area. 

The agency, in a decision released July 18, said the plant’s originators, Passaic Valley Sewerage Commission (PVSC), had agreed to include in its plan measures to curb emissions and use limits that would allow the plant to operate only 288 hours a year for testing and maintenance, unless an emergency forced its use. 

Because the DEP’s decision requires the sewerage commission, if it goes ahead with the plan as expected, to install pollution controls on existing equipment at the facility, the state’s action “will result in a net overall reduction of air pollutant emissions,” said Commissioner Shawn M. LaTourette at a briefing as the DEP released the decision. 

“This is a precedent-setting action,” he said, referring to the way the law was used to cut emissions across the facility.  “We believe that this is the kind of result that our environmental justice law was intended to achieve. It’s one that not only avoids casting more pollution upon an overburdened community, but also improves upon the existing conditions by reducing pollution that our neighbors are already experiencing.” 

Yet the DEP’s action immediately triggered vigorous pushback from environmentalists and local lawmakers, who have been fighting to stop the project for years. 

Food and Water Watch NJ called it an “absolute betrayal to Newark residents” and said the decision “completely undermines” Democratic Gov. Phil Murphy’s “own commitment to protect environmental justice communities and take meaningful climate action.” 

“Toxic air pollution from power plants and congestion have plagued our communities for decades, resulting in higher instances of asthma, cancer, cardiovascular disease and developmental disorders,” said state Sen. Renee C. Burgess (D), in a release put out by six legislators. “Just when we thought there was marked progress in combating the new development of these harmful facilities, DEP fails us.” 

Competing Goals

The debate underscores the difficulties of the state’s efforts to aggressively cut emissions while ensuring the state has access to enough electricity to meet its needs. In this case, the DEP also sought to balance competing public health concerns: those of the local community that would be affected by emissions from the plant and the threat if the lack of electricity during a disaster meant untreated sewage ran into area waterways. 

PVSC, which handles sewage from 48 municipalities and is the sixth-largest waste handling agency in the nation, conceived of the plant after Superstorm Sandy severely flooded the agency’s plant. The emergency shut down the main and backup power sources needed to treat wastewater and triggered the release of 840 million gallons of raw sewage into the nearby Passaic River and Newark Bay. 

In response, PVSC seeks to build an on-site emergency standby power generating facility (SPGF) with three 24-MW natural gas combustion turbine generators (CTGs) that is intended to provide power in case of a similar emergency. 

The commission’s application said the plant would be used only 3.5 hours a day or 1,285 hours a year. The commission predicted it would use the combustion turbine generators (CTGs) 480 hours a year for storm preparation, 300 hours a year for testing and maintenance, and 24 hours a year for “demand response” during peak hours to offset load. The DEP said PVSC had explored using electricity provided by solar, wind and battery systems to provide emergency backup, but found it would not be feasible, due mainly to onsite space limits.  

The DEP’s decision does not grant permission for the plant, but it does specify conditions in the project as it now advances through the DEP’s environmental permitting process. As part of the process, which is expected to take six months, the DEP will compile a draft permit for review by the federal government prior to the state making a final permit decision. 

The DEP reviewed PVSC’s plan under an environmental justice law that took effect in June 2023 triggered largely by concerns that communities — especially with a proportion of low-income residents, and those of color — were not being heard in decisions over environmental issues and were, as a result, heavily burdened by polluting facilities.  

Murphy, in backing the law, called it a “historic step” that made the state “home to the strongest environmental justice law in the nation.” The law requires applicants seeking to build potentially polluting facilities to dig deeper into the density, history and emissions of other facilities into the area and identify stressors on the community from any proposed facility and the impact on residents.  

The PVSC project is the last of three gas-generating plants that until recently were proposed for North Jersey. In October, Competitive Power Ventures (CPV) withdrew its plans for a 630-MW gas-fired generating plant Woodbridge, and in January, NJ Transit dropped plans for a 140-MW emergency resilience gas generator in Kearny. (See New Jersey Abandons Controversial Gas Generation Plant.) 

Special Requirements

The DEP’s 16-page decision allowing the PVSC project to “proceed with its proposed permit modification” says the agency’s environmental justice review “has ensured the imposition of special conditions that result in a net overall reduction of facility-wide emissions of air pollutants under regular operating conditions.” 

“I don’t expect anyone to praise this outcome,” LaTourette said. “That’s not the business we’re in. … But (it’s) rather to achieve a result that best protects public health and the environment.” 

The EJ law enabled the DEP to look “beyond the single source of pollution …. and to look broader at the facility as a whole, to achieve facility-wide reductions in pollution,” LaTourette said. “That additional oversight and authority has resulted in multiple new requirements for PVSC to reduce its existing pollution.” 

The requirements, which must be adhered to in the permitting process, included: 

    • limiting the plant’s use — to 48 hours before a storm, to no more than 10 times a year, to emergency “act of God”-type events, and to once a month for maintenance and testing 
    • air pollution control measures — PVSC must remove several existing gas boilers and install state-of-the-art pollution control equipment on four sludge boilers 
    • solar — the agency must install at least 5 MW of solar panels at the facility by the end of 2026 
    • storage — the agency must install at least 5 MW of battery storage capacity at the facility 
    • alternative fuels — the agency must “initiate the transition” of the burners to natural gas or green hydrogen in the near future. 

Community Impact

Lawmakers who represent districts that would be impacted by plant emissions demanded a reversal of the decision and highlighted the state’s history of putting polluting facilities in the Newark area. The city is already home to four electricity-generating plants, and pollution levels are elevated by truck traffic on several highways, much of it serving the Port of New York and New Jersey, which also is in Newark. 

State Sen. M. Teresa Ruiz (D) called the decision “an indefensible and hypocritical decision that blatantly violates New Jersey’s environmental justice law.” 

“It disregards the well-being of Newark residents who have long borne the brunt of toxic air pollution and negative health outcomes from nearby power plants built in their communities to shield more affluent areas from its harmful effects,” she said. “The administration cannot pat itself on the back for pioneering environmental justice policies and promoting environmental education in schools while continuing to harm the environment and the health of its most vulnerable residents.” 

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EPA Announces $4.3B in Climate Pollution Reduction Grants

Pennsylvania will use its $396.1 million Climate Pollution Reduction Grant (CPRG) on a statewide initiative to cut greenhouse gas emissions from industrial buildings through incentives for energy efficiency and emission-reduction technologies. 

Montana’s plan for its $49.7 million CPRG will focus on improving forest management across the state, expanding urban and community forests, mitigating wildfires and coal seam fires, and reducing pollution from agriculture. 

And in Connecticut, New Haven will get $9.4 million to build a networked geothermal system that will provide clean power and heat to Union Station, the city’s transit hub, with carbon-free electricity also going to a neighboring mixed-income housing development. 

EPA on July 22 announced these and 22 other projects that have been selected to receive more than $4.3 billion in CPRG funds from the Inflation Reduction Act, all aimed at reducing emissions, promoting clean energy and creating jobs. 

Announcing the grant awards at a concrete and asphalt plant in Pittsburgh, EPA Administrator Michael Regan said the federal dollars will “fund investment-ready projects targeting climate pollution from transportation, the electric power sector, commercial and residential buildings, industry, agriculture, natural lands, [and] waste and materials management. … These investments are going to change lives.” 

Combined, the 25 projects could reduce U.S. GHG emissions by 971 MMT by 2050, which, according to EPA, is the equivalent of the emissions from the energy used by 5 million average U.S. homes per year for more than 25 years. 

The IRA funds will “empower local ownership … and local solutions to help solve a global problem,” John Podesta, White House senior adviser on climate innovation and implementation, said during an advance press call July 19. “The climate crisis looks different in every community, from Colorado to Connecticut to Lincoln, Nebraska. More bike lanes and public transit may be the best way for one city to reduce emissions, and making a local steel plant more energy efficient might be the best path for another.” 

Lincoln Mayor Leirion Gaylor Baird agreed. “Local initiatives, when combined with federal funding, can transform ideas into tangible solutions,” she said. 

“Here in Lincoln, the planning phase of this grant program showed us that some of the greatest opportunities for emission reductions lie in enhancing the energy efficiency of homes and commercial buildings. Our analysis indicates that investing in energy efficiency and electrification could reduce Lincoln’s emissions by a whopping 77% from our baseline metrics by the year 2050.” 

The money also will be used for “critical home repairs for low-income members of our community” as part of the city’s efficiency and electrification efforts, she said. 

Lincoln’s programs are just one element of Nebraska’s plans for its $307 million in CPRG funding. The money also will go toward accelerating the adoption of climate-smart and precision agricultural practices and reducing agricultural waste from livestock. 

Precision agriculture uses digital tools and automation to improve farming efficiency and crop yields. 

EPA received nearly 300 applications for the grants, with funding requests totaling $33 billion, Regan said July 19. The 25 awardees were “the cream of the crop,” with projects offering “maximum penetration of greenhouse gas pollution reduction. But also, we wanted to be sure we saw the diversity across various industries, whether it be transportation, building, agriculture [or] the power sector.” 

Community benefits and job creation were additional priorities in evaluating applications, he said. “We have a very stringent program. These recipients also have demonstrated that not only could they identify the pollution reduction targets, but they could put metrics in place to prove it.” 

The CPRG funding contains an additional $300 million for emission-reduction projects submitted by tribes and territories, to be announced this year. 

Asked if the grants announced July 22 could be affected by a change in administration, Regan said all the funds would be “obligated” to the awardees by early fall, once all legal and administrative requirements are met. 

“We know these recipients are ready to receive these dollars and will be off to the races immediately,” he said. 

State Climate Plans

The grant announcements are the second phase of the CPRG program, which began last year, when EPA awarded $250 million in noncompetitive IRA funds to help state, city and tribal governments develop climate plans. Individual grants ranged from $1 million to $3 million. 

Plans were due March 1 for states and cities and April 1 for tribes and territories. 

Forty-five states and dozens of cities and tribes ― covering 96% of the U.S. population ― now have plans in place, according to EPA. While five states ― Florida, Iowa, Kentucky, South Dakota and Wyoming ― did not submit plans, cities in those states did. Rapid City, S.D., and Cheyenne, Wyo., submitted plans, as did Des Moines, Cedar Rapids and Iowa City in Iowa. 

Updated, comprehensive plans will be due around the middle of 2025, according to EPA. 

The second-phase grants are intended to help a small group of states and cities implement those plans and provide models that other states, cities and businesses can replicate. 

Pennsylvania Gov. Josh Shapiro, joining Regan in Pittsburgh, said the state’s $396.1 million CPRG is the second-largest federal grant in its history and will be used for its Reducing Industrial Sector Emissions in Pennsylvania (RISE-PA) program. 

Administered by the state’s Department of Environmental Protection, RISE-PA will issue grants “to manufacturing companies across this commonwealth,” Shapiro said. “These grants can be used for … improving energy efficiency, reducing emissions, implementing carbon capture … and replacing equipment with electric power options,” such as swapping out coal-powered smelters used to make steel for electric smelters. 

“I have always said we have got to reject the false choice between protecting our planet and protecting our jobs,” Shapiro said. “We can and we must do both.” 

Multistate and Regional Projects

Other award winners included several multistate and regional projects. 

Maine, New Hampshire, Connecticut, Massachusetts and Rhode Island are partnering on a New England Heat Pump Accelerator, which snagged $450 million, one of the largest grants announced. In states heavily dependent on winter heating oil, the project aims to install cold-climate air-source heat pumps, heat pump water heaters and ground-source heat pumps in 500,000 single-family and multiunit homes. 

New Jersey, Connecticut, Delaware and Maryland have formed the Clean Corridor Coalition, which will receive $248.9 million to install electric charging stations for medium- and heavy-duty trucks along Interstate 95, a major East Coast freight route. 

Maryland also is part of the Atlantic Conservation Coalition, joining Virginia and the Carolinas for a $421.2 million grant to be used to restore coastal habitats and peatlands, plant trees and improve forest management in Appalachia. 

The state’s slice of the two projects will total about $130 million, according to a press release from Gov. Wes Moore (D). 

“It isn’t enough to ask people to see themselves in the consequences of climate change — they also need to see themselves in the progress of climate action,” Moore said. “By moving in partnership with leaders at the local, state and federal levels, we are creating new green jobs, driving economic growth and building new pathways to prosperity for all, while protecting our planet.” 

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PJM Presents Revised Reserve Requirement Study Values

PJM presented its Planning Committee with revisions to the 2023 Reserve Requirement Study (RRS) to reflect the marginal effective load-carrying capability (ELCC) analysis approach the RTO uses for most resource accreditation.

During the July 16 special meeting, PJM’s Patricio Rocha Garrido said the results of the reanalysis recommend increasing the installed reserve margin (IRM), which sets the targeted capacity level above expected loads, to 18.6%, up from the 17.6% stakeholders endorsed in the original study last year. The forecast pool requirement (FPR), which accounts for generator accreditation, would decrease from 11.65% to 9.37%. (See “Stakeholders Endorse Reserve Requirement Study Values,” PJM PC/TEAC Briefs: Oct. 3, 2023.)

The majority of resource classes saw a relatively minor change between their 2025/26 ELCC ratings and the 2026/27 target year for the 2023 RRS, with most increasing or decreasing within 2%. Gas combustion turbines saw the largest change, increasing 6% due to the number of CTs that have announced their deactivation. The overall impetus for rating changes across resource types was a small shift toward risk being concentrated in the winter.

The new values are being brought to the July 24 Markets and Reliability Committee and Members Committee meetings for a same-day first read and endorsement vote.

The marginal ELCC approach was one of several capacity market redesigns drafted through the Critical Issue Fast Path (CIFP) process last year and approved by FERC in January 2024. (See FERC Approves 1st PJM Proposal out of CIFP.)

The CIFP filing also revised three formulas central to the RRS analysis, including:

    • calculating the IRM by reducing total installed capacity (ICAP) by the capacity benefit of ties (CBOT);
    • determining the FPR by multiplying the IRM by the pool-wide average accredited unforced capacity (UCAP) factor, rather than forced outage rates; and
    • making the average accredited unforced capacity (UCAP) factor the ratio of UCAP to installed capacity (ICAP).

Stakeholders endorsed an earlier round of revisions to the RRS to reflect the impact of those design changes earlier this year. (See “Revised Reserve Requirement Study Values Endorsed,” PJM MRC/MC Briefs: March 20, 2024.)

Garrido said PJM also updated the assumed resource mix to include planned resources that submitted a notice of intent to offer into the 2026/27 Base Residual Auction. Gas generators that submitted dual fuel attestations were sorted into the corresponding ELCC classes, and resources that are scheduled to deactivate prior to the start of the delivery year were removed from the analysis. Generators expected to operate on reliability-must-run (RMR) contracts through the delivery year were included in the resource mix.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said some RMR contracts do not require the generator to respond to PJM capacity deployments and should not be included in the resource mix.

“I think we’re actually overstating the amount of capacity that’s going to be there,” he said, adding it would distort market signals.

Sotkiewicz also questioned the assumption that outside capacity could be available for import during emergencies, saying that PJM has been exporting consistently during “emergency events and high load days.”

Garrido said PJM aims to model the system as it’s expected to exist in the target delivery year and that RMR resources should be included if they’re contracted to remain in operation. He stated any impact on the reliability requirement would be small.

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NERC Submits Final Performance Assessment

NERC has submitted its final performance assessment to FERC, reviewing a turbulent five years in which NERC managed “significant collaboration” among the ERO Enterprise, stakeholder groups and government authorities that “resulted in high and improving grid performance.” 

The performance assessment covers the years 2019 to 2023, a period that saw the outbreak of the COVID-19 pandemic, several major severe weather incidents, the emergence of serious cybersecurity threats to multiple aspects of the electric grid and the ongoing shift from traditional thermal generation to renewable resources.  

In the report, NERC sought to highlight “the continued viability and effectiveness of the ERO model” at using “broad technical expertise across diverse stakeholder groups and [ensuring] the independence and agility required to advance reliability in a changing world.” 

FERC regulations require NERC to file an assessment of its performance every five years as a prerequisite to recertifying it as the ERO, and the commission approved the last assessment in 2020. (See NERC Wins Another 5 Years as ERO.) Three years ago, FERC floated a proposal to shorten this timeline to three years, but the commission withdrew the proceeding this year after NERC and the regional entities warned that a three-year assessment cycle might not allow it to conduct the same level of review that the current schedule allows.  

NERC posted a draft of this report in April, seeking stakeholder comments. (See NERC Makes Case for Recertification in Performance Assessment.) The finished assessment, filed July 19, “reflects feedback from [regional entities], industry stakeholders and commission staff,” NERC said, along with input gathered from stakeholders throughout the assessment period.  

In the final assessment, NERC focused on its accomplishments through four key areas: 

    • Energy: addressing challenges arising from the changing resource mix, providing sufficient energy and essential reliability services, improving system performance during extreme weather and adding transfer capability; 
    • Security: addressing cyber and physical security risks; 
    • Agility: becoming nimbler in risk identification and standards development; and 
    • Sustainability: investing in automation, eliminating single points of failure, and strengthening the ERO Enterprise’s long-term stability and success. 

The organization devoted a significant part of the report to its internal development and efforts to modernize and streamline its committee structure. These include the creation of the Reliability and Security Technical Committee in 2020 through the combination of several existing committees and the Regulatory Oversight Committee in 2023 to give NERC’s Board of Trustees “committee-level oversight of standards development.”  

NERC also discussed its efforts to improve cyber and physical security across the ERO Enterprise. It said that during the assessment period, it “zeroed in on structural cybersecurity challenges” to the grid, including supply chain vulnerabilities and information technology and operational technology system monitoring.  

In addition, the ERO highlighted its work developing the Energy Information Sharing and Analysis Center (E-ISAC), which “continues to play a vital role in securing the [grid] through sharing information on cyber and physical security threats and vulnerabilities with industry members, the vendor community, and government and cross-sector partners.” 

NERC received a single comment from the Edison Electric Institute, which it posted as an appendix to the assessment. EEI suggested that “it would be helpful if the [final] assessment explored the use and value of [self-certification and spot checks as] alternatives to full on-site audit engagements.” In response, the ERO asserted that it “has increased its use of self-certification and spot checks to support compliance monitoring and intends to continue to significantly leverage those methods.” 

NERC said that during the first quarter of this year, only 15% of its compliance monitoring engagements used full on-site audits. Among such engagements, 77% used self-certifications, while 8% used spot checks. NERC pledged to “continue coordinating across the ERO Enterprise to support consistent rationale in tool selection through its risk-based approach to” compliance monitoring and enforcement.