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April 6, 2023

Maryland Lawmakers Vote to Raise Offshore Wind Target

Maryland’s General Assembly on Tuesday overwhelmingly passed a bill that raises the state’s offshore wind target to 8.5 GW by 2031.

Lawmakers in the House of Delegates passed the Promoting Offshore Wind Energy Resources (POWER) Act on a 100-36 vote.

The state Senate passed a version of the bill on March 17 on a 33-12 vote. The two chambers now must review what the other passed to determine whether a conference is needed before sending the legislation to the governor to be signed.

Gov. Wes Moore (D) expressed support for the 8.5 GW target last week at the Business Network for Offshore Wind’s International Partnering Forum in Baltimore (See: US Offshore Wind Industry Set to Take Off).

“Today is a wonderful day for Maryland’s offshore wind industry as well as the workers and communities that power this industry,” Dan Taylor, regional field organizer for the BlueGreen Alliance, said in a statement. “By passing the POWER Act, Maryland has fast tracked their state towards its clean energy goals and tied good union jobs to future construction and manufacturing in local communities. The POWER Act delivers on the dual promise of good-paying, safe jobs and a reduction of the emissions driving climate change.”

In addition to raising the target, the bill would require the Maryland Public Service Commission to ask PJM to set up another State Agreement Approach planning process for offshore wind transmission, which the RTO did for New Jersey. The PSC would have to reach out to other PJM states to evaluate regional transmission cooperation that could help it meet its offshore wind goals, according to the legislature’s analysis of the bill.

The PSC, or PJM, will have to issue one or more competitive solicitations for transmission projects by July 1, 2025. Additional solicitations could be issued after that, if needed.

The bill requires PJM or the state regulator to study specific transmission solutions, including one that uses an open-access collector system to allow for the interconnection of multiple offshore wind projects at a single substation.

Transmission proposals could include upgrading the existing grid, extending the transmission grid both onshore and offshore, interconnecting between offshore substations, adding energy storage, and using high voltage direct current converter technology to support potential weaknesses in the transmission grid.

Proposals will have to maintain electric reliability, help achieve the state’s offshore wind and other environmental goals, demonstrate benefits to consumers and the environment, and foster economic development and job creation in Maryland.

The PSC will have to pick one or more transmission proposals by Dec. 1, 2027, and then work with the developers, PJM, FERC, potentially other states, and other stakeholders to ensure the lines get built.

If the solicitation does not lead to any beneficial or cost-effective proposals, the PSC can end it without picking one and would then have to notify the legislature of its decision by Dec. 1, 2027.

The Department of General Services will have to consult with the PSC in issuing a sealed procurement for contracts of up to 5 million MWh of offshore wind energy and associated renewable energy credits from one or more projects by July 31, 2024. Contracts of at least 20-year terms would be issued by Sept. 1, 2025, barring unforeseen circumstances that delay the procurement.

The bill also includes language for the 2 GW of offshore wind developments that have already cleared earlier procurements, allowing developers to ask the PSC for an exemption to the requirement that they pass along to ratepayers 80% of the value of any state or federal grants, rebates, tax credits, loan guarantees, or other benefits. Developers must prove that the exemption is needed to meet their contractual obligations.

April 6, 2023December 12, 2023

E-ISAC’s Duncan Warns Cyber Threats Growing

The North American electric grid remains under threat from “capable adversaries” around the world, staff from the Electricity Information Sharing and Analysis Center (E-ISAC) told a forum hosted by the Texas Reliability Entity on Thursday.

“I think it’s important to consider that in the season of Easter, Passover and Ramadan that there’ll be a number of guardians of the grid watching over us all, making sure the lights stay on and those holidays can proceed peacefully, because suffice to stay, the threat landscape is quite active,” E-ISAC Director Matthew Duncan said during the Talk with Texas RE webinar.

Duncan’s presentation focused on the rise of malware variants, often connected with state-sponsored hacking groups, that target an organization’s operational technology networks, potentially allowing them to affect the target’s physical infrastructure. While most of the malware strains seen in the past could only interfere with entities’ information technology systems, which don’t typically interface with operations, an attack on electric utilities with OT-targeting malware could pose a grave threat to grid reliability.

Among the latest of these new threats is the Bad VIB(E)s malware, detected and named last year by security firm Mandiant. The company describes it as a “malware ecosystem” primarily targeting virtual machines — that is, when a computer is used to provide the functionality of a different architecture — and the computers that control them, also called hypervisors.

Matthew Duncan, E-ISAC | Texas RE

Duncan warned that Bad VIB(E)s, which Mandiant has attributed “with low confidence … to a China-linked actor,” seems to target hypervisors “that are prevalent in IT and OT environments,” and that detecting it may be more challenging than other attacks.

“This type of malware was designed to avoid detection, to avoid your EDR [endpoint detection and response] solutions,” Duncan said. “So you can see the adversaries are evolving to counter the defenses that we put out there to stop them and detect them.”

The good news, Duncan said, is that Bad VIB(E)s does not seem to have been used in any attacks against the U.S. energy sector based on information gathered by the E-ISAC. In this regard it is like another OT-targeting malware strain identified last year by security firm Dragos and dubbed Pipedream, which appeared designed to attack industrial infrastructure. (See E-ISAC Warns of Escalating Russian Cyber Threats.) Mandiant has attributed Pipedream to Russia-sponsored actors; Dragos, as a matter of policy, does not link malware to specific nations.

Also like Pipedream, Duncan noted, the attacker needs access to the target machine to deploy Bad VIB(E)s. However, he said, this does not mean there is no danger; utilities must ensure their staff are vigilant against any potential infiltration attempts while also preparing backup solutions for those times when something gets through.

“I know we all think about cyber hygiene as a very basic and obvious thing to do, but those phishing drills, having your software and hardware enumerated, is really important because you’re essentially protecting the front and the back door,” Duncan said. “Still, mitigations need to be in place inside the house, as it were, on the off chance that they get through those initial screenings.”

Ransomware also continues to be a concern for utilities, Duncan added. While statistics from the FBI’s 2022 internet crime report showed that the energy sector accounted for relatively few victims of ransomware attacks last year, an incident in which the Royal ransomware affected a utility’s supervisory control and data acquisition (SCADA) network provided clear evidence of the seriousness of the threat.

“I think it is important to make the community aware that the adversaries are no longer coming after OT in the abstract,” Duncan said. “It is really important to get … the east-west mitigations inside company networks and utility networks to keep an eye on what might be traversing, so that we can stop adversaries from gaining access and stopping critical operational processes.”

April 6, 2023March 20, 2024

NW Hydrogen Hub Supporters Celebrate Region’s Application, Potential

OAKDALE, Wash. — Backers of a proposal designed to attract billions in federal funding to create a hydrogen hub in the Pacific Northwest say their application is set to be submitted this week.

They also express confidence that the region has a good shot to win a piece of the $8 billion being made available by the U.S. Department of Energy to develop four to eight hydrogen production and distribution networks across the country.

“We think we’re perfect because we’re a high-tech hub,” Washington Gov. Jay Inslee (D) told NetZero Insider following a series of speeches celebrating the application at the Confederated Tribes of the Chehalis Reservation.

Four state governments, two tribes and several private sector firms, utilities and unions have created a coalition — the public-private Pacific Northwest Hydrogen Association (PNWH2) — to submit that application. Inslee noted that the coalition’s members range from British Petroleum to the Sierra Club. The four states are Washington, Oregon, Idaho and Montana

“It’ll help us launch a clean energy economy that would be a model for the rest of the country,” said Janine Benner, director of the Oregon Department of Energy and vice-chair of the association’s board.

The U.S. Department of Energy is looking at 22 “encouraged applicants” — meaning finalists — who each have a chance of getting a slice of the $8 billion pie.

Like other applicants nationwide, PNWH2 is being closemouthed about the details of its roughly 1,000-page application. The association believes it can meet a DOE target of producing 50 to 100 metric tons of hydrogen per day.

Chris Green, assistant director of the Washington Department of Commerce and PNWH2 board chair, said the secrecy is an effort to keep the Northwest’s application competitive with those from other regions and also because of several nondisclosure agreements signed with hydrogen companies involved.

The association has trimmed an original 140 Northwest-oriented projects to “a few dozen” to shrink the field to the most technologically advanced and financially feasible, Green said.

Green said PNWH2 is not concentrating on hydrogen cars or stations to fuel them. Instead, he said, “We want to concentrate on the industries that are harder to decarbonize,” including manufacturing, shipping and aviation.

On March 1, Los Angeles-based Universal Hydrogen flew a hydrogen-fueled De Havilland Canada Dash 8-300 commuter plane for the first time for 15 minutes at 3,500 feet around an airfield in Central Washington’s Moses Lake. Inslee cited that as a venture that the coalition wants to help develop.

Coal-to-H₂

Participants at the Chehalis Reservation event indicated that another plank in the application is Australia-based Fortescue Future Industries’ intention to build a hydrogen production facility next to the TransAlta coal-fired power plant in Centralia in Lewis County, Washington, the last coal plant in the state, which is scheduled to close in 2025. Fortescue is also a member of the PNWH2.

“We were considered a coal community. We were considered a big polluter. What people don’t realize is that we’re an energy community. Transferring from coal to hydrogen is a natural fix,” said Richard DeBolt, president of the nonprofit Lewis County Economic Development Corp.

Event participants also mentioned Seattle-based First Mode, another PNWH2 member, which is developing a hydrogen fuel cell generator designed to replace diesel engines to power huge vehicles capable of carrying 150 to 290 tons of platinum-laced ore in one trip from an open pit mine to a processing plant in South Africa.

The Cowlitz and Chehalis tribes are also participating in the coalition. So far, the Chehalis tribe is interested in setting up hydrogen fueling stations along Washington Highway 12 north of the reservation in Lewis County, said tribal board Chair Dustin Klatush. The tribe has land that could be used for yet-to-be-determined hydrogen-related projects, he said.

A Cowlitz tribal representative did not elaborate on his tribe’s plans beyond a general interest in developing a hydrogen industry.

The ports of Tacoma and Seattle — also members of the association — are brainstorming development of fuel production facilities, Green said. The Douglas County Public Utility District in Central Washington — another member — is in the final stages of building an electrolyzer complex along the Columbia River to use river water to create hydrogen.

Washington has also signed a memorandum of understanding with South Korea to cooperate on developing hydrogen production and distribution along the North Pacific Rim.

Wednesday’s event gave no clue as to whether the application includes Oregon-based Obsidian Renewables’ plans to build hydrogen production plants at existing industrial parks in Hermiston, Oregon, and Moses Lake. These would supply a proposed pipeline system that would terminate at points in The Dalles, Pendleton and Prineville in Oregon, and in Wenatchee and Spokane in Washington. Another pipeline would extend to Lewiston, Idaho. One connecting pipeline would go through the Tri-Cities, which is the second-most populated area in Eastern Washington behind Spokane.

The association would have to provide matching funds for much of the money it is seeking from DOE.

Most of the Northwest matching funds are supposed to come from the individual companies pursuing hydrogen projects in the application, Green said. The Washington legislature allocated $2 million in potential matching funds in 2022. Another $20 million in potential matching funds are working their way through the legislative session that ends April 23.

At the event, Inslee declared that developing a hydrogen industry will require new engineering, construction, operating and logistical construction jobs. “You can’t have anything more broad-based than a hydrogen hub,” he said.

“This would create tens of thousands of good jobs,” said April Sims, president of the Washington State Labor Council of the AFL-CIO.

April 6, 2023June 14, 2023

NYISO Previews Plan to Expedite Interconnection Queue

NYISO on Monday updated the Transmission Planning Advisory Subcommittee on a phased window approach to its generator interconnection queue to potentially replace the current process.

The construct would enable groups of overlapping projects, which proceed in separate phases in a single queue window, to be evaluated simultaneously throughout the interconnection process; add decision periods and milestone requirements to give developers more flexibility; and replace individual system reliability impact studies.

Since the 2019 passage of New York’s Climate Leadership and Community Protection Act, NYISO has been devising ways to hasten its existing three-part interconnection study process, including narrowing some study scopes, adding more staff and considering tariff revisions. (See NYISO Begins 2023 Class Year with Nearly 100 Projects.)

Thinh Nguyen, senior manager of interconnection projects, told stakeholders that the window approach seeks to reduce study times, increase efficiency without compromising reliability and give developers the ability to “get off the train” by opting out of the process without disrupting other studies.

Although encouraged that NYISO is investigating queue enhancements, stakeholders still sought clarity on many aspects of the approach.

Mark Younger, president of Hudson Energy Economics, asked whether a project would still “have another bite at a future queue window” and rejoin later if it decides to not proceed as part of their assigned queue window.

Potential Queue Window Approach (NYISO) Content.jpg

Visual representation of NYISO’s proposed interconnection queue window approach | NYISO

Nguyen responded it would but added that projects electing to withdraw from their current queue window “actually have no more bite but can jump to the next queue window.”

Doreen Saia, an attorney with Greenberg Traurig, asked how the approach would interface with state agencies, such as the New York State Energy Research and Development Authority (NYSERDA), and their solicitations.

Nguyen said that “it’s probably easy for NYSERDA to look at our new process and create the new rules that will be applicable for any solicitation,” to which Saia responded that she would “definitely encourage that those conversations happen in the relatively near team, because I don’t want [NYISO] to go too far down this path and then have [state agencies] say that it’s just not going to work.”

Stakeholders asked additional questions, such as about how study deposits would be treated if a project withdraws, whether the ISO could elaborate on certain definitions or terms, the role consultants would play and how elements of the current interconnection study process would fit into the new approach.

Nguyen addressed these lines of questioning but reiterated that NYISO was “not going to go too deep … because [stakeholders and the ISO] have not yet agreed to move forward with the new process.”

NYISO will continue soliciting feedback and spend part of the April 14 TPAS meeting addressing any remaining questions or unresolved issues, Nguyen said.

Long Island PPTN Report

NYISO on Monday also released its draft public policy transmission planning report, which included sensitivity results for 16 offshore wind projects that participated in the Long Island public policy transmission needs (PPTN) process. (See “Offshore Wind,” NYISO Stakeholders Propose Three Areas for Public Policy Transmission.)

In the coming months, NYISO will continue to review the results with stakeholders, add further details on additional sensitivities for consideration and include ISO-recommended rankings for all the submitted projects.

Developers are invited to present their projects to NYISO’s Board of Directors on April 17; on June 13 the ISO will conduct an “appeal-like process” for stakeholders to raise concerns and provide other feedback directly to the board.

April 5, 2023June 14, 2023

NACFE: Battery Electric and H2 Fuel Cells to Displace Diesel

The North American Council for Freight Efficiency has concluded that hydrogen will be a factor in long-distance heavy-duty trucking by enabling the industry to reduce carbon emissions in a zero-emissions future envisioned by the Biden administration.

In a new report released Tuesday, a team of NACFE analysts reason that battery electric trucks, as currently designed, are not up to carrying heavy freight loads over long distances. The analysis concludes that both battery and fuel cell electric trucks will be needed, with battery trucks hauling freight locally and regionally, up to about 250 miles.

The report comes just days before the U.S. Department of Energy’s deadline for industries working with local and state governments to file applications for $7 billion in matching funds to develop regional hydrogen hubs decarbonizing heavy industry. DOE envisions beginning with six to 10 regional hydrogen hubs.

NACFE’s authors reason that hydrogen production levels will increase significantly over time with the development of the hydrogen hubs, becoming cost competitive with diesel fuel.

Heavy Truck Transportation Roles (NACFE) Content.jpg

Battery electric, hydrogen fuel cells and sustainable liquid fuels will each have a role in transportation. | NACFE

What the report does not say is whether the long-anticipated heavy-duty hydrogen fuel cell systems will be superior to the just emerging re-engineered diesel engines designed to run on hydrogen.

“Two paths are emerging: fuel cell electric and new hydrogen internal combustion engines,” the study asserts. “Hydrogen is not optimum for all duty cycles. Hydrogen fuel cell tractors are, however, the only viable zero-emission solution currently proposed for one-for-one replacements for diesel in the future of long-haul heavy-duty trucks.”

In previous studies issued over the past five years, NACFE focused mainly on battery electric trucks, including large trucks. And in real over-the-road testing in which a small number of fleets participated, NACFE concluded that electric fleets making deliveries over prescribed routes not exceeding 250 miles could handle the job.

Mike Roeth, NACFE | NACFE

Previous NACFE studies did not include converted and re-engineered diesels because none was commercially available or even discussed publicly. Cummins, a long-time engine builder, has not only been designing an engine to burn hydrogen but has also begun building electrolyzers to produce clean hydrogen. President Biden visited a Cummins plant on Monday to mark that buildout.

Mike Roeth, executive chairman of NACFE, said that while the new study demarcated the distances each technology was capable of handling, the organization has not ruled out the use of hydrogen fuel cell trucks for use in short hauls.

“In rural areas, it might be easier to get a hydrogen truck to a [refueling] site than create electricity,” he said.

Asked whether the report included a cost comparison of the three technologies — battery, fuel cell or re-engineered engines — Roeth said it “is just to early to tell.”

He explained that fuel cell vehicles require additional cooling systems over vehicles with engines because fuel cells produce a lot of waste heat when producing electricity.

“But the battery packs are also a big cost.”

April 5, 2023November 9, 2023

CAISO Retools Transmission Plan for Reliability, Renewables

CAISO published a draft transmission plan Monday that identifies 46 transmission projects needed over the next decade to incorporate more than 40 GW of renewable resources essential for advancing the state’s transition to 100% clean energy and maintaining grid reliability.

“The need for additional generation of electricity over the next 10 years has escalated rapidly in California as it continues transitioning to the carbon-free electrical grid required by the state’s clean-energy policies,” CAISO said in the plan. “This in turn has been driving a dramatically accelerated pace for new transmission development in current and future planning cycles.

“To help ensure we have the transmission in place to achieve this transition reliably and cost-effectively, the ISO’s 2022-2023 Transmission Plan reflects a much more strategic and proactive approach to better synchronize power and transmission planning, interconnection queuing and resource procurement,” the plan says.

The more proactive approach was outlined in a memorandum of understanding that CAISO, the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) signed in December. It provided a “new blueprint for our state” with closer links between the planning processes of each entity, CAISO CEO Elliot Mainzer told the ISO Board of Governors in February. (See CAISO CEO Lauds Transmission Planning Agreement.)

The new transmission plan is the first to be prepared under the MOU.

It is based on the CPUC’s projections that the state needs to add at least 40 GW of new resources by 2032 in a base-case scenario and 70 GW in a “sensitivity” scenario “reflecting the potential for increased electrification occurring in other sectors of the economy, most notably in transportation and the building industry,” the plan says.

“The network upgrades are recommended in this plan to make all of the base amounts available and, in Southern California, to also make most of the sensitivity amounts available as well,” it says.

The CPUC has already indicated it will provide the 70GW scenario as its base case next year, so the “remaining network upgrades needed to achieve the sensitivity amounts will be approved next year” in CAISO’s annual update to its 10-year transmission plan.

Interconnection Zones

In preparing the plan, CAISO analyzed projected resource additions within 14 transmission interconnection zones. The Southern California Edison (SCE) Northern zone, for example, will need 11.6 GW of new resources under the base case scenario and 16.9 GW under the sensitivity portfolio, primarily through a buildout of utility-scale solar and battery storage.

Critical resources identified in the plan include:

17 GW of solar generation in the deserts of Southern California and the Central Valley, and in areas of Nevada and Arizona.
3.5 GW of in-state wind generation.
1 GW of geothermal development in the Imperial Valley of far Southern California and in southern Nevada.
Battery storage projects co-located with renewable generation projects and stand-alone storage near Los Angeles, San Francisco and San Diego.
4.5 GW of in-state transmission upgrades necessary to import out-of-state wind energy from Idaho, Wyoming and New Mexico.
3-5 GW of wind generation off the coast of Central California.

“To achieve these outcomes, the ISO has found the need for a total of 46 transmission projects, the vast majority of which would be built in California. They range in projected costs from $4 million to $2.3 billion, for a total infrastructure investment of an estimated $9.3 billion,” CAISO said.

Major projects include a new 500-kV transmission line from the Arizona border to Imperial County, a new 500 kV transmission line from southern Imperial County to San Diego and the Los Angeles Basin, and upgrades to existing 500-kV and 230-kV lines along the Interstate 10 corridor, which runs from Los Angeles toward Phoenix.

“Together, these upgrades provide access to east Riverside County, Imperial County and Arizona solar generation, Imperial Valley geothermal, and New Mexico wind generation,” the transmission plan says.

Other notable projects include a new 500-kV transmission line from southeastern Nevada to the Los Angeles Basin and “rebuilding of existing southeastern Nevada 230-kV transmission inside the ISO to 500 kV, providing access for Eldorado and Pisgah area solar generation, southeastern Nevada solar and geothermal generation, and Wyoming and Idaho wind generation.”

‘Next Major Installment’

CAISO identified 24 reliability-driven projects, totaling $1.76 billion and 22 policy-driven projects needed to meet the state’s climate goals, totaling $7.53 billion.

In addition, the ISO has been working with out-of-state transmission developers to bring wind from Wyoming via the planned TransWest Express line and from New Mexico via the planned Sunzia line to the CAISO boundary.

Developers for the transmission projects have sold capacity on their lines to “resource developers seeking to access California markets,” the plan says. “That work is ongoing, and the timing of those projects is driven by the developers and their subscribers.”

CAISO said it had also studied the need for transmission for North Coast offshore wind based on the sensitivity portfolio provided by the CPUC.

“As the study was only informational and set the stage for future planning, no projects were recommended for approval in this 2022-2023 plan,” it said. But with “growing volumes” of offshore North Coast wind identified in the CPUC’s 2023/24 planning cycle, the “ISO expects to make a decision on North Coast transmission in next year’s transmission plan.”

In a blog post, Mainzer said the 2022/23 transmission plan “represents the next major installment of infrastructure investment required to meet California’s long-term clean energy goals. In close coordination with regulatory agencies, load-serving entities and other key stakeholders, we endeavored to address the state’s reliability and policy needs in the most cost-effective and efficient way possible.”

CAISO has scheduled a stakeholder meeting April 11 to discuss the draft plan and expects to seek approval from its Board of Governors in May.

April 5, 2023December 26, 2023

Nevada Resolution Seeks to Bring Renewables to Yucca Mountain

A Nevada lawmaker has introduced a resolution urging the federal government to use Yucca Mountain, once proposed as a dumping ground for the nation’s nuclear waste, as a site for renewable energy.

Senate Joint Resolution 4, introduced by state Sen. James Ohrenschall (D), was heard last week by the Senate Natural Resources Committee. The committee took no action.

SJR 4 “urges the federal government to use Yucca Mountain for the development and storage of renewable energy.” If passed, the resolution would be sent to federal officials, including the president, vice president, House speaker and energy secretary.

Not long ago, Yucca Mountain faced a “scary future” as the nation’s disposal site for high-level radioactive waste, Ohrenschall told the committee.

Now, he said, there’s an opportunity for “positive uses,” such as renewable energy or research.

“And if these positive uses happen, then I think it becomes exponentially less likely that the federal government will be able to say, ‘No, we need to take all the nation’s high-level radioactive waste and spent nuclear fuel, transport it across the country and send it here to Yucca Mountain,’ which I think puts not only our constituents in danger, but citizens around the country,” Ohrenschall said.

Renewable energy at Yucca Mountain has been discussed previously, including in a 2011 report from the U.S. Government Accountability Office that looked at alternative uses for the site. The report said a potential challenge to energy-related uses was the lack of nearby transmission.

On Thursday, supporters of SJR 4 noted NV Energy’s plans for Greenlink West, a roughly 350-mile transmission line that will run past Yucca Mountain and the neighboring Amargosa Valley community.

“We are in what they call the sweet spot for Greenlink and all the transmission lines and such,” said Carolyn Allen, chair of the Amargosa Valley Town Board.

Renewable energy development at Yucca Mountain would bring an array of benefits to the town, said Allen, who called SJR 4 “an excellent bill.”

“It can bring research,” she said. “It can bring new people that want to live there and raise families there.”

One person spoke in opposition to the resolution. Dylan Keith, assistant director of government affairs for the Las Vegas Chamber of Commerce, said the chamber supports renewable energy research and development.

But “the chamber has had a long-standing opposition to any development with the Yucca Mountain project,” Keith said.

Committee member Sen. Ira Hansen (R) said the nation’s move toward electrification and the growing demand for electricity raise complex questions. He said one issue is what to do with used solar panels and asked whether Yucca Mountain could be used as a disposal site.

“In the next 20 or 30 years, we’re going to have hundreds of thousands of those,” Hansen said. “What are you going to do with the old panels?”

Yucca Mountain was designated as the sole location for a national nuclear waste dump when Congress amended the Nuclear Waste Policy Act in 1987. Since the 1980s, the U.S. Department of Energy has spent billions of dollars studying Yucca Mountain as a disposal site for nuclear waste. The 230-square-mile site is about 100 miles northwest of Las Vegas.

But faced with strong opposition from the state of Nevada and Native American tribes, Congress stopped funding Yucca Mountain in 2010. In 2021, the Biden administration stated its opposition to using Yucca Mountain as a nuclear waste site. Instead, the administration has shifted its focus to “consent-based siting,” in which nuclear waste is stored in communities that agree to accept it.

In preparing its 2011 report on alternative uses for Yucca Mountain, GAO interviewed experts who had a wide variety of suggestions. Those ranged from a command center for unmanned aircraft, weapons testing, public emergency communications or a secure data storage site.

Energy-related ideas included a commercial energy park, with nuclear, solar and wind power generation. Research was another suggested use, with potential topics including carbon capture or compressed air or pumped hydroelectric energy storage.

April 5, 2023December 12, 2023

NERC’s Robb, Cancel Discuss Evolving Reliability Challenges

NERC CEO Jim Robb felt “sobered by the amount of work in front of us” but confident that the ERO can address the electric grid’s “hyper complex risk environment,” he said in a media call Wednesday to mark the five-year anniversary of his joining the organization.

The rapidly changing grid and its implications for reliability were a major theme of the call, which also featured Manny Cancel, a senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), discussing physical and cybersecurity challenges. Robb said the switch from conventional spinning generation to solar, wind and other inverter-based resources (IBRs) should spur stakeholders to rethink how they provide “essential reliability services.”

“We really need to shift our thinking around reliability away from capacity installed plus reserve margin, which really accounts for random events that occur out on the grid, [and] to recognize that we now have a generation mix that’s increasingly impacted by common conditions,” Robb said. “Wind droughts, solar droughts — these things can affect a large amount of generation, and not in a random way. We really need to get our heads around that dynamic and the uncertainties around fuel as we think through the sector’s ability to serve [the] energy needs of customers.”

Shifting toward intermittent generation also means utilities nationwide have increasingly adopted natural gas as a balancing resource, Robb said, making coordination between the electric and gas industries critical. This is not always easy, he acknowledged, saying that while “the gas industry is amazing at what it does,” it “wasn’t designed to serve highly variable loads like electric power.”

E-ISAC CEO Manny Cancel | NERC

Using gas as a lynchpin for the generation fleet has therefore created strains that both industries need to work on together, with help from policymakers and regulators as well, Robb continued, adding that “it’s as hard to start a new gas pipeline … as it is to build electric transmission.”

“Because of electrification policies, electric transportation and moving space heating toward an electric fuel, we’re going to be growing load, and we’re having enough trouble just keeping up with where we are right now,” Robb said.

NERC has an important role to play in educating the various governmental agencies that oversee the development of the grid and gas system, Robb said; this takes the form of putting “steadfast protection … around NERC’s objectivity and rooting our perspectives in science and technology” as the ERO communicates with regulators.

He said the organization’s 2022 Summer Reliability Assessment, and its warnings about the impact of severe weather and transmission outages, “provoked a very strong and positive response in terms of interagency communication” about the importance of reliability services. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.) He also pointed to a recently announced memorandum of understanding between the Environmental Protection Agency and the Department of Energy as a sign that regulators are taking the challenge seriously. (See DOE, EPA Team Up on Reliability Efforts.)

Cancel also discussed the importance of cross-industry collaboration in the security space, calling the E-ISAC a “conduit to the industry” for government agencies, “not only for information sharing, but also to discuss policy and other issues.” He said the E-ISAC’s level of engagement with policymakers “has never been stronger,” while its relationship with its counterparts in other critical industry sectors has also become tighter since Russia invaded Ukraine last year.

Additionally, Cancel pointed to his organization’s efforts to combat supply chain weaknesses through its vendor affiliate program. The program, launched last year, is intended to give vendors a voice in the debates over supply chain issues and provide their “keen insights” on the risk landscape.

“They are doing things from a product perspective … to protect themselves too. We can certainly learn from them, and they can be a powerful voice, particularly the vendors that are used pervasively across the electricity sector,” Cancel said. “That’s not only going on through the [E-ISAC]; it’s going on through other venues [like] trade associations, [and] the government has [been] having dialogue with the vendor community. … I’m not declaring victory, and underscoring that has to continue, but [it’s] a very important step forward.”

April 5, 2023

Rest Stop Operator Seeks Piece of $166M NJ EV Charger Push

A rest stop operator is negotiating with the New Jersey Turnpike Authority (NJTA) to install electric vehicle chargers along the state’s two main highway arteries under a $166 million program, according to the agency.

The NJTA board on March 28 authorized the continuation of talks with Applegreen NJ Welcome Centers, which operates restaurant facilities at rest stops along the New Jersey Turnpike and the Garden State Parkway, which also is managed by the authority. Applegreen, based in Ireland, sells food and fuel at 121 sites in the U.S. Northeast and South.

Service areas on the two highways currently host 76 chargers — 70 on the turnpike and six on the parkway, NJTA spokesperson Tom Feeney said. Of the turnpike chargers, 64 are operated by Tesla, six by EVgo, which also operates all six on the parkway, he said.

The authority’s announcement comes as the state seeks to increase the number of chargers statewide, believing — like other states — that a key element to jump-starting a broad embrace of EVs is to remove the fear that a vehicle could run out of power with no charging nearby to replenish the battery.

New Jersey has 943 public charging locations, 164 of which offer DC fast chargers and 802 offering Level 2 charging, according to the public EV charging locator run by the New Jersey Department of Environmental Protection. About 95% of the state is within a 25-mile radius of a DC fast charger, according to the site.

About 90,000 EVs are registered in New Jersey, a small fraction of the 6 million light-duty vehicles on the road, but a big jump up from approximately 30,000 EVs in the state at the end of 2019. New Jersey policy calls for 330,000 light-duty plug-in electric vehicles registered in state by 2025, along with 400 fast chargers and more than 1,000 Level 2 chargers by the same date.

Expanding the Charger Network

Feeney said the talks with Applegreen have not yet determined where and how many chargers would be installed if negotiations are finalized. But the deal would “greatly expand the number of EV charging stations at turnpike and parkway service areas,” he said.

Elements of the deal already have been agreed to, according to the authorization approved by the agency. Applegreen “will construct EV charging facilities and construct or secure the construction of related utility infrastructure at authority rest service areas,” the order says. The company also will operate and manage the facilities, the order says.

NJTA would pay $24 million in the deal, but there has been no agreement on “customer pricing structure or revenue sharing,” according to the order.

Pamela Frank, CEO of ChargEVC-NJ, a coalition of industry groups, consumer advocates and environmentalists that promotes EV adoption, welcomed the announcement and especially the authority’s $24-million commitment to the project.

“It’s a very good initiative,” Frank said, adding that she expects the deal to add hundreds of chargers along the two highways. “The good news is you’re going to see [chargers] on the parkway; you’re going to see [them] on the turnpike on all of these stops that are owned and operated” by the contractor, she said.

The biggest benefit, however, could be that the project will bring the power cables from the grid needed for chargers at the rest stop charging site, which is often the biggest cost to the charging station, she said. So even if there are not many plugs at the start, due to the limited demand at present, they can be easily added.

New Jersey ranks 15th among states in the number of publicly available non-Tesla fast chargers, according to an analysis of federal data by ChargEVC-NJ, Frank said, noting that seven East Coast states rank higher. The state has about one public EV plug per 24,000 vehicles of all kinds on the road, about the same as the U.S. as a whole, she said.

Multiple Incentive Programs

The federal government awarded the state $104 million in funds from the National Electric Vehicle Infrastructure (NEVI) program, which requires states to identify alternative fuel corridors (AFCs), major state and interstate highways where EV charging stations would be located every 50 miles. EVs can fully recharge in about an hour using the fast-charger ports now available.

Under the first phase of New Jersey’s NEVI plan, from 2022 to 2024, state officials designated 12 highways as AFCs, among them the turnpike and parkway. The plan calls for the state to use the NEVI funds to install four 150-kW chargers at least every 50 miles at locations less than a mile from the highway exit.

The state also has several of its own funding programs designed to stimulate the installation of chargers. The state Board of Public Utilities (BPU) in June expanded a program that awards incentives for chargers installed at tourist sites, in a bid to attract EV-driving visitors. The program offers up to $2,000 for a Level 2 charger and up to $5,000 for a fast charger, along with subsidies for make ready costs. (See NJ Boosts EV Charging Program for Tourist, Multifamily Locations.)

Another state program awards funds to support the installation of chargers at multi-family dwellings, and a third program, called It Pay$ to Plug In, provides incentives of up to $750 for a Level 1 charging port installed at workplaces, public places and other locations, and $4,000 for a Level 2 charging port.

In October, the BPU approved $16.15 million in funds from the Regional Greenhouse Gas Initiative to create the state’s first program designed to promote the installation of fast chargers for medium- and heavy-duty (MHD) electric vehicles. (See NJ BPU Approves $16M for 1st MHD EV Charger Program.)

April 5, 2023December 10, 2023

PJM Presents Alternative Capacity Auction Schedule

PJM presented a draft proposal to delay the next four Base Residual Auctions (BRAs) to the Members Committee during a special meeting on Tuesday.

The alternative schedule would move the 2025/26 auction, currently scheduled for this June, to June 2024; the following three auctions would be held every sixth months thereafter. Auctions would return to their regular timing of being held three years in advance of the 2029/30 BRA, which would be held in May 2026. (See PJM Board of Managers to Seek Capacity Auction Delays.)

The tightened schedule would also continue the current practice of canceling incremental auctions (IAs) when they take place within 10 months of the BRA or would be within the same year as the corresponding delivery year. The first two IAs for the 2025/26 auction and following year’s would be canceled, leaving only the third IA in place. Two IAs would be held in the 2027/28 and 2028/29 delivery years, before going back to the normal three per year.

PJM’s tariff requires that it consult with the MC and Transmission Owners Agreement-Administrative Committee (TOA-AC) at least seven days prior to making a Federal Power Act Section 205 filing with FERC. The TOA-AC, whose meetings are closed to the public, met on Tuesday after the MC.

Pre-auction activities will continue until PJM has received an order from FERC to ensure that the 2025/26 BRA can still be held in June should the commission reject the filing. Should the commission approve the filing, PJM’s Tim Horger said those activities will be rerun leading up to the auction’s new date.

Horger said the filing is based on the premise that FERC will approve the capacity market overhaul that the Board of Managers plans to approve and have filed by Oct. 1 within 60 days. If the commission were to take longer and reach a decision as late as March, Horger presented a potential alternative that would delay the 2025/26 BRA to October 2024 and delay the following four auctions. The schedule would go back to normal with the 2030/31 auction in May 2027.

The draft filing shown to the MC only seeks the capability to change the timing of auctions through the 2028/29 delivery year, necessitating an additional FERC filing for the alternative Horger presented.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said requiring a filing by Oct. 1 and setting June 2024 in stone for the 2025/26 BRA would limit stakeholders’ ability to extend discussions on capacity market changes through the Critical Issue Fast Path (CIFP) process. He noted that PJM has delayed the release of its report on the December 2022 winter storm to July, which he argued also leaves little time for review and to incorporate findings into proposals. (See PJM Presents More Detail on CIFP Proposal.)

The report will be especially important for state consumer advocates, Poulos said, as they are not market participants and lack the insight into the storm’s impact that those directly affected by it possess. A short timeline for making these decisions could put advocates in the position of voting on proposals to recommend to the board without having all the necessary information, he said.

Poulos also questioned whether there is a plan for how PJM would act if FERC approves the auction delay but ultimately rejects the eventual capacity market proposal.

Horger responded that PJM is aware of that possibility and that the risk will have to be addressed should it manifest.

Vistra’s Erik Heinle asked if PJM will request expedited consideration of the filing to reduce the amount of pre-auction activities that market participants must engage in.

PJM Senior Counsel Chen Lu said the decision to make the filing under Section 205 was intended to reduce the amount of time to receive a determination, but PJM will consider asking for expedition.

Ian Oxenham, legal specialist for the New Jersey Board of Public Utilities, urged PJM to not seek expedited consideration, saying that it could deprive commenters of the time needed to evaluate the filing.

“PJM should be very hesitant to shorten that comment period,” he said.

Coal-to-H2