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November 19, 2024

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SEEM’s Sellers Pushes Reliability, Continuity to SERC Board

CHARLOTTE, N.C. — A spokesman for the Southeast Energy Exchange Market (SEEM) told SERC Reliability’s Board of Directors Thursday that the market poses no challenges to the regional entity’s work on grid reliability.

“For everybody here in the room, responsibilities are not changing. Everybody still has the same reliability responsibilities,” said Corey Sellers, general manager of transmission policy and services at Southern Company, one of SEEM’s founding utilities. “Because we’re not doing a centralized dispatch, all of those … remain as they do today.”

SEEM is slated to enter operation later this year, after receiving FERC’s de facto approval last October (ER21-1111, et al.). (See SEEM to Move Ahead, Minus FERC Approval.) Currently the market includes 16 participants across 11 Southeastern states and nine balancing authorities, with more than 160 GW of collective capacity.

Many industry stakeholders continue to express skepticism about the ability of the new market to meet its claims of reducing friction in bilateral trading and spurring the integration of renewable energy better than alternatives such as  an RTO or energy imbalance market, debates that Sellers has participated in before. (See GCPA Panelists Go One on One Over SEEM Proposal.) In his presentation Thursday, Sellers focused on the image of SEEM as an enhancement, rather than a disruption, to the current market.

Corey Sellers 2022-06-23 (RTO Insider LLC) FI.jpgCorey Sellers, Southern Company | © RTO Insider LLC

“As we entered into this, we kind of went in with two key principles,” Sellers said. “One, let’s try to keep this simple, and build it upon the bilateral market that we’re already operating in the Southeast. And let’s try to get the most benefit for the least cost.”

Continuity was a constant theme in Sellers’ talk, as he sought to assuage SERC’s potential concerns by assuring attendees that “each balancing authority will continue to operate as it operates today” under SEEM. He portrayed the market as an attempt to smooth the business of electricity trading and allow greater use of the region’s wide array of resources.

“It’s really about scale and diversity … There’s time zone diversity, there’s definitely weather diversity, generation, load, all of those things are very helpful when you think about operating the system,” Sellers said. “That was a key component when we put this together … looking at that diversity, [and] at the diversity of resources, in particular around renewables. We have a lot of solar coming online … all across the Southeast.”

SERC’s board includes several representatives of SEEM utilities, who were asked by independent director Shirley Bloomfield to chime in with their thoughts on why their companies signed on to support the new market. The first to speak was Roger Clark of Associated Electric Cooperative; most of the following speakers said he expressed their views better than they could. Clark said the main attraction was the expansion of trading from hourly increments into 15-minute intervals, allowing more responsive scheduling.

“It was a low-cost project; it’s voluntary. We’re optimistic that something will come out of it, but we don’t have a lot of skin in the game,” Clark said. “As a BA, you lay in [resources] the best you can, but that’s what you’ve got, until you get to your next hour. … If I’ve got excess wind that we can put on and sell, [or] there’s excess solar, it’s that intra-hour variability that we’re hoping to get some efficiency out of.”

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Ex-FERC Commissioners Opine on Transmission, Markets

WASHINGTON — Former FERC Commissioners Norman Bay and Colette Honorable recounted war stories and made predictions about where their successors are headed on market and transmission policy Wednesday at the American Clean Power Association’s Energy Storage Policy Forum.

Bay, who served from 2014 to 2017, including a stint as chair, and Honorable (2015-17) were joined by former FERC staffer Christy Walsh, now senior attorney and director of federal energy markets for the Natural Resources Defense Council’s Sustainable FERC Project.

One recurrent topic was FERC’s April Notice of Proposed Rulemaking on transmission planning and cost allocation (RM21-17) and its June 16 NOPR on improving transmission providers’ interconnection processes (RM22-14).

Pivot on Right of First Refusal

Bay said he was surprised that FERC’s April NOPR proposed reinstating transmission providers’ federal right of first refusal (ROFR) to construct transmission projects — a retreat from Order 1000’s attempt to inject competition.  (See ANALYSIS: FERC Giving up on Transmission Competition?)

Bay, a partner with Willkie Farr & Gallagher, said there are two possible explanations for the shift in the NOPR, which was approved on a 4-1 vote, including the commission’s three Democrats and Republican Commissioner Mark Christie. Republican James Danly dissented.

“One is that, as a policy matter, the commission was concerned that this emphasis on competition was having this perverse policy incentive, where it was incenting transmission owners to basically build local reliability projects, and not to build the more ambitious, and frankly more helpful, regional — or even interregional — lines,” Bay said during the discussion, which was moderated by Jason Burwen, ACP’s vice president of energy storage.

The second possibility, Bay said, is that “there was a commissioner who felt very strongly about taking a step back from the removal of the federal ROFR, and basically insisted on this policy position. And to keep that vote, the decision was made to put into place this policy change.”

The June NOPR, which seeks to reduce delays and increase cost certainty for generation developers, was approved unanimously — a rarity since Danly, who has dissented on most rulemakings, joined the commission.

“Five votes on a NOPR like this is significant,” said Honorable, now a partner with Reed Smith. “[For a] NOPR as important and significant as this one, having every commissioner on board is key to provide certainty, and also to provide the proper foundation for FERC to build on.”

But, she added, unanimous support of the NOPR does not mean the final rule will also receive five votes. “You start all over,” she said.

Comments Needed

Honorable encouraged stakeholders to provide comments in response to the two NOPRs and dockets involving energy storage, noting that commission orders must be based not only on the law but also on “what the record says.”

“Your real-life anecdotal experiences about ways in which energy storage has been leveraged in places where transmission wasn’t as robust, that’s critical,” she said. “So, I would urge you to not sit on the sidelines and wait for someone else to put that in there — that you make sure it’s in the record, so that it can be leveraged by those commissioners that are seeking to build that pathway more robustly for storage as an alternative.”

Walsh said stakeholders should also seek to meet with FERC commissioners and staff before filing their comments. “A lot of times you can have a two-way conversation with commissioners and staff, and they can ask you questions about the point you’re making, and they can help you really see exactly what they need to hear in those comments,” said Walsh, who served as an adviser for former Chair Jon Wellinghoff, deputy general counsel and director of the Division of Policy Development during her nearly 19 years at the commission. “This is a rulemaking so there’s no, ex parte [prohibition]. Nothing that’s said in those meetings can be used without you then writing them down and submitting them in comments.”

Market Design

Burwen asked the panelists to predict what might result from FERC’s April order directing CAISO, ISO-NE, MISO, NYISO, PJM and SPP to report on how their system needs are changing due to shifting resource mixes and how they intend to fulfill them (AD21-10). (See FERC Asks RTOs for Plans on Changing Market Needs.)

Walsh predicted the docket would prompt changes but said it’s unclear whether they will be dictated by FERC or proposed by individual RTOs.

“FERC has done a white paper, four technical conferences, and now this order directing reports,” Walsh said. “That’s a significant amount of FERC staff time and industry time, and they would not be doing that unless they had intention to move forward with something.”

In previous orders directing reports, Walsh said, “sometimes the RTOs do the reports and kind of see their own flaws by doing some self-reflection and start fixing it themselves.”

Walsh said she expects more emphasis on using the energy and ancillary services markets, “so that you are really providing services in the hours that they’re needed, rather than in three years, or in case of New York, six months beforehand [through capacity markets]. … I think that we are coming to a system that is going to shift from hour to hour based on load and the resources, and we just need to be more dynamic.”

Capacity Accreditation

The panel also discussed FERC’s two June 16 NOPRs intended to improve the bulk power system’s protections against severe weather risks. One proposes to direct NERC to modify reliability standard TPL-001-5.1 (transmission system planning performance requirements) to set expectations for long-term planning by utilities (RM22-10). The second directs transmission providers to submit one-time reports describing how they assess and mitigate their vulnerability to extreme weather (RM22-16, AD21-13).  (See FERC Approves Extreme Weather Assessment NOPRs.)

Bay said the issue of capacity accreditation — the subject of RTO-specific effective load-carrying capability (ELCC) rules — will require input from FERC as well as NERC.

“I don’t think NERC can do it all, because the issue here is not only technical, involving engineering, but it’s also economic,” Bay said. “I think there is an opportunity for FERC to step in and basically standardize the rules … but it would be difficult. It would be contentious, [but] it might be in the long run better than letting each RTO kind of figure out its own path forward.”

Honorable said she would welcome standardized rules. “Having stepped down from the 888 tower [FERC headquarters], it’s rough out here when you have to deal with a number of RTOs and ISOs that have different frameworks, different rules, different procedures. It’s cumbersome; it’s clunky.

She said FERC could provide “some structure … at the outset, and then leverage other resources. Maybe there is a role for NERC to play in the very technical evolution of it. But I’m concerned that if FERC rides herd over all of it, it could, it might take longer than it should.”

Walsh suggested FERC could have different rules for single-state ISOs in California and New York. “The states are really driving what resources are going to be on line, so it seems to me that, for example, the ELCC in New York might be different than any ELCC in ISO New England or PJM.”

State-Federal Relations

No discussion of FERC would be complete without discussing the perpetual tension between state and federal policymakers.

Honorable said states could become allies of FERC if the agency addresses inefficiencies in market operations and transmission planning across regional seams.

“That’s a place where we can really gain support from states who are grappling with the reliability impacts and the resilience outcomes as a result of long tenured congestion and the uncoordinated ways in which the seams are operating,” she said. “That’s an area that definitely could use more love and attention.”

Walsh praised FERC for creating the state-federal task force on transmission, and the transmission planning NOPR for creating “a really robust process for states” to have input.

But she said the state commissions need FERC guidance on the minimum set of benefits that the system should be planning for.

“State commissions are overburdened,” she said. “Asking the state commissions to figure out [transmission] benefits that aren’t immediately identifiable easily, it’s going to be hard for them.”

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Michigan PSC OKs CMS Plan to End Coal Use by 2025

LANSING, Mich. — The Michigan Public Service Commission approved CMS Energy’s integrated resource plan Thursday under an agreement that will end the company’s use of coal-fired generation by 2025 and boost development of renewable resources and electric storage.

The commission’s order finalized a settlement announced in April (Case U-21090). (See Consumers to End Coal by 2025 in IRP Deal with Mich. AG.)

Consumer groups and environmentalists praised the order as a historic moment for CMS (NYSE: CMS), which got almost 35% of its power from coal last year.

Environmentalists and community groups also said they would continue to push CMS to stop use of a wood-burning plant and to take more steps toward environmental justice.

The agreement calls for CMS to close three coal units at the J.H. Campbell plant in Ottawa County in 2025.   It also approves CMS’s purchase of the natural gas-fired Covert Generating Station in Van Buren County. The agreement also requires CMS to keep its D. E. Karn Complex, powered by natural gas and fuel oil, running until 2031 instead of its initial 2023 planned closure.

The agreement also expects CMS to add up to 8,000 MW of solar power by 2040 and 75 MW of energy storage by 2027, with 550 MW of storage by 2040.

“The clean energy plan is a sea change that positions our company as a national leader and empowers us to deliver reliable energy while protecting the planet for decades to come,” said Garrick Rochow, CEO of Consumers Energy, CMS’ main subsidiary.

CMS executives also said the agreement would save ratepayers $600 million in energy costs over the 20-year life of the plan.

In approving the plan, the PSC ordered CMS to conduct “added analysis” in its next IRP, including total emissions, the effects of particulate matter on health, an environmental justice tool, low-income energy efficiency participation rates and rooftop solar adoption rates.

Among activists involved in the decision, Nayyirah Shariff of Flint Rising said the decision inspired her group, and that group members would continue efforts to shut down a CMS wood-burning plant and incinerator in Flint.

Derrell Slaughter, the Michigan Clean Energy Advocate for the Natural Resources Defense Council, said the agreement was a “significant step” in Michigan’s fight against climate change.

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NJ Boosts EV Charging Program for Tourist, Multifamily Locations

New Jersey has added $6 million to two incentive programs designed to encourage the development of electric vehicle charging stations at tourist locations and multifamily buildings, as the state prepares to launch the third phase of a program that has to date awarded incentives for the purchase of more than 12,000 EVs.

The New Jersey Board of Public Utilities (BPU) allocated $4.5 million to the tourist program last month. Launched in the fall, the program closed its second round of applications on Wednesday. The project in the first phase awarded more than $1 million in grants for the installation of chargers at 24 tourist sites, resulting in the installation of 61 chargers, including to four state parks and at least eight sites on the Jersey Shore.

The program awards an incentive of up to $2,000 for Level 2 chargers and 50% of the make-ready costs, up to $5,000, and up to 50% of the cost of a DC fast charger and up to $75,000 in make-ready costs. (See NJ Seeks to Lure Tourists with EV Chargers.)

The board also allocated $1.5 million to strengthen the program that awards incentive packages to stimulate the development of chargers at multifamily dwellings. The program, now in its second phase, awarded about $1 million for the purchase of 223 chargers and funded the preparation of sites at 67 multiunit dwellings in 41 municipalities, the BPU said. (See NJ Greenlights Incentives for Multi-dwelling EV Chargers.)

Cathleen Lewis, e-mobility program manager for the BPU, said the increased popularity of EVs and the future need for home chargers is already leading to multiunit dwelling developers planning for charging at their properties.

“What you’re seeing is developers know that this is coming; this is going to be an amenity that people are going to want,” Lewis said. She said there had been a “huge diversity” in applications, stretching from suburbs to overburdened communities and dwellings of different sizes.

The funding shifts come as the BPU also prepares to launch the third phase of its Charge Up New Jersey program, which provides incentives for the purchase of an EV. The agency at the end of last month released a straw proposal for the next phase of incentives, with a cut from $5,000 to $4,000 of the maximum incentive available, and an incentive of $250 for the purchase of a Level 2 smart charger for residential use.

The BPU says the program has so far incentivized the purchase of 12,225 vehicles with another 1,235 pending, for a total cost of $57.7 million. The agency expects the third phase, which will require board approval once the final draft is prepared, to start some time after the beginning of the state’s new fiscal year in July.

The state will also receive $15.5 million in federal funds under the National Electric Vehicle Infrastructure Formula program to buy and install chargers, funding that the Biden administration earlier this month said must be used to create a national network that has minimum reliability standards and charging speed, works for all cars and takes common payment methods. (See Biden Administration to Order EV Charging Standards.)

State plans are due in August. Proposed rules released by the Federal Highway Administration (FHWA) include requirements that EV infrastructure “operate on the same software platforms from one state to another”; that they be installed, operated and maintained with qualified technicians; and that basic information, such as location, connector type, power level, real-time status and real-time price, be available free of charge and easily publicized.

Growth in EVs, Charger Installations

The state’s portfolio of EV incentive and charger programs provide a window into the demand patterns in New Jersey as the state pursues aggressive EV and electric charging goals. The state’s Energy Master Plan calls for the state to deploy 330,000 light-duty EVs on the road by 2025 on the way to reaching 100% clean energy by 2050, and cutting emissions by 80% of 2006 levels by the same date.

The state in January 2020 enacted a law that called for the installation of at least 400 DC fast chargers, which can add about 60 to 80 miles to an EV in 20 minutes of charging, and 1,000 Level 2 chargers, which add 10 to 20 miles per hour of charging time, by Dec. 31, 2025.

The law also called for fast chargers with 150 kW of charging power to be located on travel corridors and spaced less than 25 miles apart. The law said by the same date, 15% of multiunit dwellings much have chargers of some sort and 20% of franchised overnight-lodging establishment must have chargers.

The law also required at least 25% of state-owned emergency light-duty vehicles to be plug-ins by Dec. 31, 2025, and 100% of state-owned nonemergency light-duty vehicles to be plug-ins by 2035.

The state had 64,300 registered plug-ins at the end of last year, compared to about 42,000 a year earlier, about one-fifth of the 2025 target.

The state has more than 300 public charging locations, and about 95% of the state is located within a 25-mile radius of a fast charger, according to the Drive Green website operated by the New Jersey Department of Environmental Protection (DEP). In total, there are about 750 chargers in the state, compared to about 675 a year ago, according to the recent state budget.

Local and state government has been slow to transition, however. The additional funding for the tourism and multiunit programs came from the $7 million set aside for the state’s Clean Fleet program, which was launched in 2019 and designed to encourage local and state government entities to convert their fleets to EVs.

“Due to logistical and budgetary reasons, the Clean Fleet program has not generated sufficient interest to utilize all the existing, remaining funding,” according to the BPU order detailing the shift in funds.

Some communities have nevertheless embraced them, with the help of other programs. The DEP on June 15 said the city of Paterson, in North Jersey, would soon receive a prototype electric ambulance, purchased with $908,686 in state funds that will also pay for two fast-charging stations. The city had earlier announced the purchase of 38 Nissan Leafs purchased with the help of $210,000 in state funds for use by fire, housing and health inspectors and the city’s Department of Public Works.

The ambulances, which are expected to go into service in about a year, will replace diesel vehicles, the DEP said in a release. Replacing ambulances has a strong impact in cutting emissions because they spend a large proportion of their time idling as they wait for a call, the department said.

Middle-income Purchasers

The BPU also believes it has had some success in bringing EVs, which are often seen as the domain of mainly wealthy buyers, to those in more modest income brackets.

The second phase of the Charge Up New Jersey Program provided incentives for the purchase of 3,791 EVs, of which 47% got the maximum incentive, according to figures released by the BPU at a June 13 public meeting on the program straw proposal. The figures showed the impact of the board’s decision to limit the maximum incentive of $5,000 to vehicles costing no more than $45,000, with an incentive of only $2,000 for higher-priced vehicles, to a maximum of $55,000.

The rule change was introduced for the second phase of the program, in June, after Tesla vehicles accounted for 83% of the incentives in the first phase, and 93% of the incentives were for the maximum grant. The BPU introduced the $45,000 vehicle cost cap — which meant that only the cheapest Tesla was eligible for the maximum incentive — in an effort to award the subsidies to “incentive essential” customers: those who would only buy an EV if there was an incentive available.

BPU officials also said that they were trying to incentivize the purchase of EVs among middle-income families, rather than just those with higher incomes.

Data for approved incentives and pending applications from the second phase show the impact of the shift, with Teslas accounting for only 66% of the incentives approved or with applications pending in the second round.

“So, we’ve seen a more diversified field in year 2 than we did in year 1,” said the BPU’s Lewis. “We’ve seen many more of the more affordable vehicles and those under $45,000 receiving incentives.

She noted that the BPU has seen “a significant increase” — to 40% of the total — in applicants who got incentives of $2,000 or less. That allows the BPU to “provide incentives for more vehicles with that same budget,” she said.

The next-placed make of vehicle was Ford, mainly the Mustang Mach-E, which accounted for 7% of awards. Hyundai also accounted for 7%, with awards for Kona Electric, Hyundai Ioniq Electric and Ioniq PHEV vehicles. Chevrolet Bolts accounted for 6%.

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Climate Bonds Initiative Issues Draft Steel Certification Criteria

The Climate Bonds Initiative (CBI) on Thursday asked for public comment on draft requirements for allowing steel-sector bonds to obtain certification under its Climate Bonds Standard.

“We’re really looking to expand our suite of criteria for the standard … and that expansion is effectively trying to move us into a wider array of sectors,” Anna Creed, CBI’s head of standards, said in a launch webinar for the draft steel sector criteria.

CBI’s standard focused originally on eligibility criteria for assets and projects in the energy sector, but Creed said the organization now plans to move “at scale” into heavy industry and harder-to-abate sectors.

“Each sector-specific criteria sets climate change benchmarks for that sector that are used to screen assets and capital projects so that only those that have climate integrity, either through their contribution to climate mitigation, and/or to adaptation and resilience to climate change, will be certified,” CBI explained in its draft document.

Certification of a climate bond or green bond under the standard prior to issuance allows the issuer to claim compliance with criteria for the asset or project related to the bond.

“We have criteria in the latter stages of development also for chemical production and for cement production, plus we’re working on hydrogen at the moment, and then we’re going to move on to oil and gas,” Creed said.

CBI’s draft criteria for steel production proposes one segment to address new facilities and another for facilities that existed prior to 2022, according to Fabiana Contreras, industry transition analyst at CBI.

For bonds related to new, fossil fuel-based facilities to achieve certification, the facilities must capture 70% of emissions for storage or use. And new electric arc-based facilities that use scrap metal for production will need to use at least 70% scrap or 100% hydrogen in iron-ore processing. CBI is working on additional cross-cutting criteria that will apply to hydrogen use to address emissions from electricity used in electrolysis, Contreras said.

Certified bonds related to pre-2022 fossil fuel-based facilities would require the facilities to achieve certain emission reductions by 2030, ranging from 15 to 50%, depending on age and emissions per metric ton of steel. Pre-2022 electric arc-based facilities using scrap metal would need to increase renewable energy use to reduce emissions from electricity.

The goal of the draft criteria is to help meet the Paris Agreement target of holding global warming to below 1.5 degrees Celsius.

“That is extremely ambitious … and for a lot of steel businesses the target and the criteria will appear very challenging,” said Max Åhman, associate professor at Lund University and member of the working group behind the criteria development.

Despite the challenge, Åhman believes that the steel sector is already demonstrating positive momentum in transitioning to clean and sustainable practices, and it could be a “role model” for other hard-to-abate sectors.

“If steel can show the way, there is a possibility even for those other sectors to take action to make it profitable and make it sustainable,” he said.

CBI is accepting comments on the draft criteria until Aug. 22.

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SERC: Ransomware Threats Continuing to Evolve

The threat of ransomware is only increasing amid Russia’s conflict with Ukraine, and electric utilities must be ready for the worst-case scenario, cybersecurity experts said last week at a SERC Reliability-hosted webinar.

In The Scoop: Ransomware, representatives from the law enforcement, electric industry, and cybersecurity communities discussed the changes in the worldwide threat landscape since Russia invaded Ukraine in February. Although fears that a global cyber offensive against Ukraine’s allies have yet to be realized, the U.S. Cybersecurity and Infrastructure Security Agency (CISA) has continued to warn about the capabilities of both Russia and the cybercrime groups with which it is unofficially affiliated. (See CISA Issues Fresh Russia Cyber Warnings.)

Those criminal groups took up a significant amount of attention at the webinar, with participants noting that some prominent threat actors seem to have added political allegiance to their traditional financial motivations.

“We’ve already seen some Russian-speaking ransomware groups voice their support for Russia, with the Conti ransomware gang showing their support within hours of Russia’s invasion into Ukraine,” said Lauren Cirillo, a cyber threat intelligence analyst with the Electricity Information Sharing and Analysis Center (E-ISAC). “Other ransomware and data breach groups such as Karma, Freecivilian, and CoomingProject have declared support for Russia as well.”

Cirillo pointed to last year’s ransomware attack on Colonial Pipeline, which shut down the company’s entire 5,500-mile system carrying almost half the supply of fuel products for the eastern U.S., as an early indication of the kind of disruption that ransomware groups could accomplish. The FBI attributed the attack to a criminal gang based in Eastern Europe called Darkside, which demanded a ransom payment of 75 bitcoin (then about $4.4 million).

“I personally find it fascinating that Colonial Pipeline paid the ransom in its entirety on the day of the ransomware’s deployment in their environment, but it still took five days to fully restart the pipeline,” Cirillo said. “This doesn’t include returning the pipeline supply chain to the state it was in before, which took several additional days to accomplish.”

Media reports following the incident claimed that while DarkSide provided Colonial with a decryption tool in exchange for payment as promised, the tool itself was too slow to be usable and the company had to rely on its backups to restore the affected systems. In testimony to Congress, Colonial’s CEO neither confirmed nor denied these stories. (See Colonial CEO Welcomes Federal Cyber Assistance.)

Despite an uptick in ransomware activity over the last year, Cirillo acknowledged that the E-ISAC has seen no sign of a sustained effort against the electric sector. One reason may be that the majority of actors in this space operate on a ransomware-as-a-service model, in which a core group develops and operates the ransomware while recruiting affiliates to hack into networks and deploy the app.

Cirillo said that for these organizations, “service definitely [appears] to be one of the top priorities,” and developers take pains to guard their reputations. For example, both DarkSide and its apparent successor group BlackMatter have promised to avoid attacking civilian infrastructure such as hospitals, water treatment facilities, and nuclear electric plants. Other groups have made similar pledges, such as donating their profits to charity.

However, this too may be changing, particularly among the ransomware groups that have aligned themselves with Russia’s invasion of Ukraine. Conti in particular became “one of the most heedless and unpredictable” actors in this space last year, with the E-ISAC recording multiple reports of attack attempts against small and medium-sized utilities, along with ransom demands far above those seen from other operators.

Conti appeared to be dealt a major blow earlier this year after a former member allegedly leaked the group’s internal chats online, exposing its tactics and processes. But Cirillo said that while researchers say the main group appears to have shut down operations, it is more likely that the leadership is pursuing a more distributed model by partnering with smaller ransomware groups to share expertise and plan attacks.

“Essentially, the Conti brand is allegedly being decommissioned, but their operations are expected to return,” Cirillo said. “Under this model, the smaller ransomware groups gain countless experienced operators while Conti gains mobility and greater evasion of law enforcement by splitting into smaller cells.”

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BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project

The first draft environmental impact statement (DEIS) released by the U.S. Bureau of Ocean Energy Management (BOEM) for New Jersey’s first offshore wind project, Ørsted’s Ocean Wind 1, found that it would not have a major impact on most of the 19 environmental and related categories scrutinized.

But the 1,408-page report released Friday also found that the construction and installation, operations and maintenance, and eventual decommissioning of the project would certainly have a major impact on marine navigation and vessel traffic.

The report assessed the impact on four levels: negligible, minor, moderate and major. Categories that could experience up to a major impact are the scenic view, fishing sector and marine mammals; they could also experience negligible to minor impacts, the DEIS found.

The project could also have negligible to moderate impact on birds, sea turtles and recreation and tourism, as well as benthic resources, the sediments at the seafloor that provide nutrients for some sea organisms.

The release of the report triggers a 45-day public comment period that begins June 24, with public hearings on July 14, 20 and 26. BOEM will consider those comments in preparation for the final EIS, which could include recommendations or requirements to mitigate the project’s major impacts.

Shawn LaTourette, commissioner for the New Jersey Department of Environmental Protection, called the release of the DEIS “a significant milestone in the evaluation of the first offshore wind project off the coast of New Jersey.”

“Over the coming weeks DEP will thoroughly evaluate and provide comment on the DEIS to ensure the project has taken all steps necessary to avoid potential adverse impacts to New Jersey’s natural, historic and cultural resources,” he said in a release. The DEP said it expects the final EIS to be released in March 2023. Gov. Phil Murphy said the release of the DEIS brings New Jersey “one step closer to bringing its vision for a more sustainable future to fruition.”

Most Impacted

The DEIS said the impacts to marine navigation and traffic would include “changes in navigation routes, delays in ports, degraded communication and radar signals, and increased difficulty of offshore [search and rescue] or surveillance missions within the wind farm area, all of which would increase navigational safety risks.”

But most of the opposition to Ocean Wind 1 has been from local residents concerned about its potential harm to their view of the sea and from the commercial and leisure fishing sector, which fears that the turbines will damage marine life and impair their ability to fish. The tourism sector has said the site of turbines on the horizon will also harm the industry.

The DEIS said the impact of the project on commercial fishing would vary, and that the “majority of vessels would only have to adjust somewhat to account for disruptions due to impacts.” However, the report added, “it is conceivable that some of the small number of fishing operations that derive a large percentage of their total revenue from areas where project facilities would be located would choose to avoid these areas once the facilities become operational.”

“In the event that these specific fishing operations are unable to find suitable alternative fishing locations, they could experience long-term, major disruptions,” the report added.

The draft also said that “the daytime presence of offshore [turbines and substation], as well as their nighttime lighting, would change perception of ocean scenes from natural and undeveloped to a developed wind energy environment.” The project’s facilities “would be an unavoidable presence in views from the coastline, with moderate to major effects on seascape character and landscape character.”

The project would also “result in habitat disturbance (presence of structures and new cable emplacement), underwater and airborne noise, vessel traffic (strikes and noise), and potential discharges/spills and trash.”

Doug O’Malley, director for Environment New Jersey, said his organization’s biggest concern is the impact on marine life.

“The goal of offshore wind is to maximize clean, renewable energy and minimize environmental impacts,” he said. “This is early days. But the DEIS is clearly outlining how the project can maximize clean energy and minimize true environmental impacts.

“Offshore wind will clearly impact marine traffic and fishing, but, you know, we desperately need to clean, renewable energy from offshore wind,” he said.

The 1,100-MW Ocean Wind 1 project, approved by the New Jersey Board of Public Utilities in 2019, was the first of three offshore wind projects approved, totaling about half the state’s target of 7,500 MW by 2035. The other two, the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores, were approved in June 2021. The state expects the first of three more solicitations to begin early in 2023. (See NJ Awards Two Offshore Wind Projects.)

BOEM released the Ocean Wind 1 DEIS as the BPU evaluates an application by the project for an easement in Ocean City, where some transmission lines from the project would come ashore. The BPU will hold a public hearing on the issue Friday. (See Ørsted NJ Wind Project Faces Local Opposition.)

Offshore Wind 1 is projected to include 98 turbines with a maximum height of 906 feet at the top of the rotator blade tip. It is expected to come online in 2024.

Ørsted said the DEIS marks a “critical and exciting permitting milestone” for the project. The company looks forward to “reviewing it in detail as we begin a robust public engagement process over the coming weeks.”

The aim of the DEIS is to “assesses the reasonably foreseeable impacts on physical, biological, socioeconomic and cultural resources that could result” from the project, according to its introduction. The report will inform BOEM’s decision on “whether to approve, approve with modifications or disapprove the project.”

Other federal agencies also will use the report to inform their evaluation of the project, including the National Marine Fisheries Service and the U.S. Army Corps of Engineers.

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California Study Takes Read on Heat Pump Views

Widespread adoption of heat pump water heaters in California has been stymied by a preference for tankless water heaters among homeowners, who may feel that a heat pump appliance is a “step backward,” a new report says.

The California Public Utilities Commission last week announced release of the report, which is a market study of electric heat pump appliances in the state.

“It feels like a step backward when you have a HPWH [heat pump water heater], because you have this giant tank that takes up space and then it’s losing heat,” said a builder who was interviewed as part of the study. “That’s going to be a hard move for consumers.”

In addition to taking up more space than a tankless unit, heat pump water heaters can be noisy and cost more upfront than alternatives. And contractors might not be familiar with HPWHs and prefer “business as usual, which has largely been gas tankless water heaters,” the report said.

The report recommended more homeowner education on the benefits of HPWHs, which include a chance to relieve stress on the grid if the appliance is tied in with a demand response program.

Meeting Climate Goals

The focus on heat pump appliances comes as California moves toward building electrification as one way to meet climate goals.

About 12% of California’s greenhouse gas emissions are direct emissions from residential and commercial buildings. And much of that is from space and water heating, CPUC said.

“Heat pump systems provide hot water, heating and cooling using energy from the electric grid, which is increasingly renewable,” the CPUC said in a release.

The goal of the new study was to provide insights that may guide strategies to accelerate adoption of heat pump appliances. The CPUC worked with consultant Opinion Dynamics on the study.

The study examines five electric heat pump technologies: air source heating and cooling heat pumps, heat pump water heaters, ground source heating and cooling heat pumps, heat pump clothes dryers, and heat pump pool heaters.

The report included analysis of past research on heat pump technologies and interviews with a range of stakeholders. The study looked at construction of market-rate and affordable housing, and single-family and multi-family buildings.

Heat Pump Surge Expected

Most of the construction trade representatives interviewed for the study said they expect heat pump installation in new homes to increase substantially over the next five years. That’s due, in part, to the growing number of cities that have banned natural gas in new construction or adopted reach codes encouraging the use of heat pump appliances. A reach code is a city building code that goes beyond minimum state standards.

The trend may be amplified when California’s 2022 Energy Code takes effect on Jan. 1, 2023. (See Calif. Energy Commission Adopts 2022 Building Code.) The code includes a provision requiring developers to install either an electric heat pump water or space heater in new single-family homes. For new multi-family housing, heat pump space heating will be the new standard.

The current market share for electric heat pumps for water and space heating in new homes in California is less than 6%, according to the California Energy Commission.

Another factor increasing demand for heat pump technology is the growing number of homeowners who don’t have air conditioning but now want it. Heat pumps can provide heating and cooling in a single piece of equipment and are “an attractive value proposition,” the report said.

“It’s hard to explain to them the value of heat pumps unless they really, really want the cooling,” said one single-family home architect who was interviewed during the study.

Opportunity Ahead

The report also notes an opportunity for heat pump space heating. Almost half of California homeowners whose main heating source is a natural gas or electric space heating appliance have units that are more than 14 years old, and therefore may need replacing within the next 10 years.

Study consultants also researched heat pump programs in states that are having some success in promoting the technology, including New York, Vermont, Washington, Oregon, Maine and an unidentified Southwestern state.

Staff with those programs said a key to success was developing a strong contractor network, starting initially with a few high-volume companies.

They also advised running marketing campaigns to explain to consumers the benefits of heat pumps and how to use them for the most savings.

Another recommendation was to offer a range of incentives to contractors, such as technical training, continuing education credits or free heat pump units so they can try out the technology in their own homes.

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Jigar Shah: ‘Oil and Gas Sector Shouldn’t be Vilified’

WASHINGTON — The way Jigar Shah sees it, if the U.S. is to have any chance of decarbonizing the grid, building out transmission or standing up an energy storage supply chain, the clean energy industry has to stop vilifying the oil and gas industry and start answering some hard questions — like whether decarbonizing the grid by 2035 is even possible.

One of the industry’s most provocative thinkers, Shah is now director of the Department of Energy’s Loan Program Office (LPO), where he is making multimillion-dollar decisions about which clean energy startups and projects to invest the government’s dollars. That kind of money means clean energy is no longer the plucky, small disruptor that only has to advocate for itself, Shah said at the American Clean Power Association’s Energy Storage Policy Forum on Wednesday.

In the course of a 30-minute conversation with Jason Burwen, ACP’s vice president for energy storage, Shah set the industry a series of grown-up challenges.

“What responsibility do we have to actually answer … big tough questions, as opposed to saying, ‘I would like to not piss anybody off, so I’m not going to say anything,’ and I’m going to let people think that we can be at 90% renewable energy, and that it’s only an interconnection problem that’s holding us back, which is patently false,” he said.

“How much [do] you allow an uninformed part of your industry to vilify other parts of the industry? The oil and gas sector shouldn’t be vilified,” Shah said. “They actually have a lot of really valuable talents. We don’t know how to run refineries. If these people lose their jobs, and we can’t get them back, we’re screwed. All of us are screwed because you’re not all running electric vehicles yet for your installation crews.

“So, we all need to figure out how to coexist together as we make this transition occur, and that means a deep understanding of how all of these things interplay with each other,” he said.

“Where does LNG fit in the entire [energy] mix? What is the position of this audience? Do we want people to increase coal consumption by 25% over the next two years?” he said. “Because that’s what’s going to happen unless we figure out a way to give Asia the energy that they need to grow.”

20-year Payback

Shah was equally blunt about the industry’s failure to deal with core issues of transmission, equity and the manufacturing supply chain.

“The only thing harder to build than nuclear in this country is transmission, and so come on, we’re not going to [build] three to five times transmission in this country,” he said. “Who in this room actually thinks that’s going to happen by 2035? The lines that we’re building right now, we started 12 years ago.

“So, unless you know which lines you started 12 years ago that are going to solve the problem by 2035, what do you think is going to happen?”

Another example: “We are disrupting 300 communities across the country with coal plants that are getting retired. You’re telling me that all those communities want solar plus storage to go into that interconnection? No, they don’t, because they’re not getting jobs from solar plus storage, and that coal plant actually pays $2 million a year in property taxes. Which one of you is paying $2 million in property taxes? So, we need to figure that out.”

The LPO recently made a conditional commitment of a $107 million loan to Syrah Vidalia, a graphite manufacturer in Louisiana, to expand its plant to provide graphite for enough lithium-ion batteries to power 2.5 million EVs by 2040.

But Shah sees bigger challenges ahead for clean energy supply chains because “our country has not actually done this level of planning and forethought and what we would call industrial policy. That’s where industrial policy is defined by getting an outcome that’s slightly different than where the market would otherwise set,” he said. “We’ve always just said, ‘We want to get the lowest possible price, and if that’s importing it from other countries and not doing anything here, that will do.

“We haven’t manufactured stuff here in 40 years, and so a lot of the supply chain isn’t here — the training colleges, all that stuff that we need, it’s still atrophying. And so, we need to actually go the other way and strengthen it, and all of that gets tied into the Loan Program because we’re taking a 20-year [payback] on those loans, so they’re not going to pay back unless the ecosystem is supportive of that company for 20 years.”

VPPs and Net Metering

Pointing to growing penetrations of solar and wind on the grid, Shah pushed the energy storage industry to think beyond lithium-ion batteries.

“When you think about what storage really looks like in our country, it is all the natural gas that we store every single day in huge salt caverns across the country, and we store it all year for like, bursts of time, right? And so that’s what hydrogen storage is; that’s what pumped hydro is,” he said.

“And so, the question really becomes, as we move to this modern grid, can we also get away from real time: matching that electricity [supply and demand] in a way that is just stressful for everybody?”

Shah also had some insights on the impact of transport and building electrification and the need for virtual power plants (VPPs).

“When you think about utility-scale battery storage, which is where most people are thinking about things these days, we’re going to have to have 800 GWh of automotive battery manufacturing in this country by 2030 to meet the president’s goal” of 50% of all new cars sold being electric.

“There’s no way to integrate those vehicles into the grid without a VPP. You cannot let anyone just charge whatever they want, however, they want, as often as they want without some management of the distribution rate,” he said.

In addition, VPPs might offer a possible solution for state-level battles over net metering reform,” Shah said.

Instead of incremental reform — currently being debated in California — he said, “Why don’t we just immediately let in VPPs and say, ‘If you want to do solar on your roof, you’re only going to get paid 5 cents/kWh, and then you’ll get paid another 7 cents/kWh for the integration within the grid out of VPP. So, you get paid the full 12 cents that you wanted before, but you get paid only if you become a grid resource.’”

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Low PJM Capacity Prices No Bargain, Coal & Gas Generators Say

Groups representing gas- and coal-fired generators said Wednesday that the sharp price drop in PJM’s 2023/24 capacity auction is a continuation of trends that threaten the RTO’s long-term reliability.

PJM reported Tuesday that its capacity bill for the year will be $2.2 billion, down from about $4 billion for the 2022/23 delivery year. It was the second year in a row that capacity prices have fallen, with Rest of RTO clearing at $34.13/MW-day, the third-lowest in the history of the Base Residual Auction. PJM said the results were likely depressed by the effective elimination of the minimum offer price rule (MOPR), a tougher cap on generator prices and robust forward energy prices. (See related story, PJM Capacity Prices Crater.)

“While the auction’s low capacity clearing price represents a savings for customers in the short term, these results portend real concerns over adequate compensation for resources needed to support reliability in all conditions and looking forward,” the Electric Power Supply Association said in a statement. “What appears to be developing is a trend where the addition of new supply resources is far outpaced by the retirement of resources that can deliver reliable power in the PJM BRA. Oversimplifying the results of the auction by cheering the lower price for capacity fails to recognize that there is a cost to ensuring the delivery of reliable power, and the most cost-effective way to deliver it is through well functioning markets, not from picking winners and losers among the resources that participate.”

EPSA said PJM’s market rules are undermining capacity price signals, calling on the RTO to “avoid rule changes intended to accommodate specific preferred resources or technologies.”

“The desire by some to defer to the policy choices of 13 states and D.C. to dictate the regional resource mix may seem sound but, in reality, threatens the reliability framework to which consumers of all types have become accustomed and expect as a part of their daily lives,” EPSA said.

The PJM Power Providers (P3) Group, which represents more than a dozen merchant generators in the RTO, was similarly critical.

“The auction-clearing prices are among the lowest they’ve ever been, so the compensation that generators will receive to commit to serving PJM’s region next year is greatly reduced,” P3 President Glen Thomas said in a statement. “However, the requirements they will commit to are more rigorous than ever. Increased obligations for decreased compensation is an incentive to leave the market rather than retain existing resources or attract new ones that will help maintain reliability going forward.”

EPSA and P3 members hold large portfolios of natural gas-fired generation.

Nuclear in the Money

Nuclear plants were big winners in the auction, clearing 5,315 MW more than last year. Solar resources increased 25% to 1,868 MW, while wind resources dropped by 434 MW. Natural gas resources cleared an additional 1,685 MW, while cleared capacity of steam units (primarily coal) dropped by 7,186 MW to 27,682 MW, reflecting a decrease of 7,813 MW offered into the auction because of plant retirements.

Coal trade group America’s Power said the auction will likely cause more coal retirements.

“PJM’s coal fleet was already expected to decline by half (more than 24,000 MW of announced coal retirements by 2030) even before the auction,” CEO Michelle Bloodworth said in a statement. “In addition, EPA regulations are expected to cause even more coal retirements, especially during the 2026-2028 time frame.”

Bloodworth reiterated the group’s request that PJM study how its reliability would be affected if half or more of its coal fleet retires by 2030, saying more coal retirements could also cost ratepayers when gas prices spike.

“We continue to urge PJM and other grid operators to value the reliability, resilience and affordability attributes of coal,” Bloodworth said. “Doing so would help put coal on a more level playing field with other resources that are receiving federal and state subsidies.”

Impacts Debated

At a press conference announcing the results Tuesday, PJM Senior Vice President of Market Services Stu Bresler noted several rule and timing changes that may have impacted the results, including the effective elimination of the MOPR, the use of a lower unit-specific market seller offer cap (MSOC) to counter market power and a historical, rather than a forward-looking, energy and ancillary services revenue offset. Bresler cautioned that because the RTO had not done any modeling, “we don’t know the magnitude of any [price] impacts.”

The less restrictive MOPR was applied to only seven resources totaling 76 MW that had failed to file for exemptions in time, Bresler said.

“Revisions demanded by FERC have virtually eliminated the MOPR, and it now fails in its purpose to prohibit subsidized resources from both suppressing the clearing price for resources who do not enjoy the benefit of a subsidy and preventing those otherwise economic resources from clearing,” P3 said.

The group said the elimination of the default MSOCs “promoted by proponents as necessary to protect against the potential to inappropriately influence prices, instead … forced suppliers to use unit-specific calculations of anticipated revenues from the energy and ancillary services markets to determine their necessary capacity market revenues while also prohibiting those calculations from accounting for the costs and risks of accepting a capacity obligation to operate when so directed by PJM.”

Jeff Dennis, managing director and general counsel of Advanced Energy Economy (AEE), offered a different take.

“There will be unfounded speculation that removal of the expanded MOPR caused the low prices; but past auctions run without an expanded MOPR produced even lower prices,” he tweeted. “PJM has been oversupplied for years; oversupplied markets produce low prices.”

He also expressed dismay at the increase in natural gas clearing the market, saying gas capacity is overvalued because of PJM’s use of an “outdated methodology” compared with the effective load-carrying capability (ELCC) used to value renewables.

P3, however, contended that the capacity capability provided by wind and solar is “overstated” even with ELCC.

“PJM’s proposed solution to rectify this issue is under dispute because it assumes utilization of extra room on the transmission system that should be available to all system users,” P3 said.

Constellation and Vistra Report on Auction Results

All of Constellation Energy’s (NASDAQ GS:CEG) nuclear-, natural gas- and oil-fired generation in PJM (18,775 MW) cleared in the auction, the company said in a filing with the U.S. Securities and Exchange Commission.

That included all 16,175 MW of its nuclear capacity, up from 9,900 MW last year, when the Byron, Dresden and Quad Cities plants in Illinois were left out of the money.

Exelon (NASDAQ:EXC) spun Constellation — including its generation and competitive energy operations — off as a standalone company in February to focus on its regulated utilities.

Vistra (NYSE:VST) reported it cleared 6,868 MW at a weighted average clearing price of $37.20/MW-day, a total of $94 million.

It said it also expects incremental revenue of $70 million to $75 million from existing retail and other third-party bilateral sales above the auction clearing price, for total estimated revenues of $164 million to $169 million.

Public Service Enterprise Group (NYSE:PEG), owner of the Salem and Hope Creek nuclear plants in New Jersey, and Energy Harbor, which operates nuclear plants formerly owned by FirstEnergy Solutions, did not respond to requests for comment. Talen Energy declined to comment on whether its Susquehanna nuclear plant cleared.