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November 16, 2024

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E-ISAC Warns of Escalating Russian Cyber Threats

Staff at the Electricity Information Sharing and Analysis Center (E-ISAC) warned this week that Russia’s electronic warfare teams are becoming more aggressive, both in their attacks against Ukraine and in their willingness to punish the country’s perceived allies worldwide.

“They will use a number of tools in their toolkit, including dis- and misinformation, as well as cyber and physical attacks against critical infrastructure, including the grid in North America,” Matthew Duncan, director of intelligence at the E-ISAC, said during Thursday’s regular Talk with Texas RE webinar. “We know this because they have done it before, whether it was in Ukraine in 2015 and 2016, or this week.”

By “this week,” Duncan was referring to the revelation on Wednesday of a new breed of malware with the ability to gain full access to a wide range of industrial control system (ICS) and supervisory control and data acquisition (SCADA) devices. The threat was first publicized by cybersecurity firm Dragos, which called the new malware “Pipedream” and its developer “Chernovite”; the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency confirmed the discovery separately in a joint statement with the FBI and National Security Agency.

Pipedream makes use of “custom-made tools for targeting ICS/SCADA devices,” CISA said in its advisory; in particular, the malware targets programmable logic controllers (PLC) from Schneider Electric and Omron Automation, along with Open Platform Communications Unified Architecture (OPC UA) servers. PLCs are computer systems that constantly monitor the state of input devices and control the state of output devices, while OPC UA is an open-source standard for data exchange between sensors and cloud applications.

The malware is deployed once attackers have established a foothold in an operational technology (OT) network. Attackers can use the bug to look up details on the target device, upload malicious configurations and code, backup or restore its contents, and modify its parameters. They can also “move laterally within an IT [information technology] or OT network and disrupt critical devices or functions.”

Dragos believes Pipedream has not yet been deployed in the wild, calling it “a rare case of accessing and analyzing malicious capabilities … before their deployment and … a unique opportunity to prepare in advance.” The same cannot be said of another threat exposed this week by Ukraine’s Computer Emergency Response Team (CERT), an apparent sequel to the Industroyer malware used by Russian attackers to devastating effect against Ukraine’s energy sector in 2016.

In the first Industroyer attack, hackers managed to knock about 20% of Kyiv’s power grid offline for about an hour; the U.S. Department of Justice later brought criminal charges against six Russian military intelligence officers believed to be involved in the attack. (See Six Russians Charged for Ukraine Cyberattacks.) Unlike the earlier incident, this week’s hack — dubbed “Industroyer2” — was apparently foiled before any outages were caused. However, Duncan warned that the incident shows the seriousness of the ongoing threat.

“Analysts reported clear similarities between the components of [the first] Industroyer and the sequel that was announced this week, and they have high confidence that the new malware was created by the same authors: this Sandworm team [from] the Russian military intelligence,” Duncan said. “But the exact capabilities of this new grid-focused malware specimen remain far from clear, and I suspect we will see more information coming out about this in the coming days.”

Against the rising threat level, Duncan praised the U.S. government for ramping up its efforts to disrupt operations against domestic targets; in particular, he pointed to the FBI’s announcement last week that it had shut down a Russian government-operated botnet — a group of thousands of devices with malware that allows hackers to use them for coordinated cyberattacks — before it did any harm. He urged private sector organizations to work with each other and with the government to ensure that threats are spotted quickly.

“It’s good to see that the government is being proactive and engaging the adversary on this, and that’s why it’s really important to share information with government partners [and] with the E-ISAC to make sure we’re [connecting] those dots,” Duncan said.

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Ariz. Regulators Reject Expansion of SRP Gas Plant

Arizona regulators have rejected Salt River Project’s proposed expansion of the Coolidge Generating Station, a gas-fired power plant in Pinal County, citing concerns about the impacts on the nearby Randolph community.

The Arizona Corporation Commission voted 4-1 on Tuesday to deny a Certificate of Environmental Compatibility for the project.

The expansion would have added 16 gas turbines to the Coolidge plant with a combined capacity of 820 MW. The generating station’s current capacity is 575 MW from 12 single-cycle turbine units, according to SRP’s website.

SRP said the project is needed to meet growing energy demand as more residents, manufacturers and industrial users move to the area. The utility is forecasting growth in peak demand of about 16% by 2025, or roughly 1,200 MW.

In addition, the expansion would provide reliability to support the addition of renewable energy, SRP said.

Commissioner Sandra Kennedy agreed that additional capacity is needed but said it doesn’t have to come from “a polluting fossil-gas facility.”

“An investment of $1 billion … on fossil-fuel infrastructure in 2022, when that money could instead be used to accelerate clean energy technology, is a tragic displacement of funds,” Kennedy said.

Incomplete Info Alleged

Commission Chair Lea Márquez Peterson said SRP didn’t provide complete information on the project.

SRP did not issue an all-source request for proposals for the expansion, saying it had previous RFPs that provided enough data, according to an order approved by the commission. But data from the past RFPs allegedly were not submitted as part of the record in the application.

A required power flow and stability study also wasn’t provided to the commission, according to the order.

And even though SRP contracted with E3 to see how much solar plus storage would be needed to provide the same reliability as the natural gas expansion, the utility didn’t provide the complete study to the commission’s Line Siting Committee or to the SRP board before a vote to move ahead with the project, the order stated.

Commissioner Justin Olson was the lone “no” vote on denying the expansion. He said natural gas is a key component in the expansion of renewable energy because it provides reliability at times when renewable energy is not available.

“If we are going to eliminate any natural gas energy generation, or any expansion of it, we are not going to have the ability to meet the energy demands of Arizona residents,” Olson said. “We’ve seen this happen in California.”

SRP didn’t respond to a request for comment on Thursday. But following Tuesday’s vote, SRP said on its website that it would “continue to evaluate what generation and market options to pursue in the near term to address the resource challenge this decision creates for serving our customers with reliable, affordable, sustainable energy.”

Historic Community

Construction of the Coolidge Generating Station was completed in 2011. SRP bought the plant in 2019.

The power plant is near the community of Randolph in unincorporated Pinal County.

Commissioner Anna Tovar noted the historic significance of Randolph, which she described as a Black community founded in the 1920s by people who came from Arkansas and Oklahoma to pick cotton. Because they weren’t allowed to buy property in nearby Coolidge, they settled in Randolph instead.

“I do not believe it is wise to put further pressure on this community to relocate,” Tovar said. “The history is important, and we shouldn’t lose that.”

And even though SRP had made progress in mitigating impacts of the proposed project, Tovar said it wasn’t enough.

“The increase in emissions, when combined with the pre-existing environmental and air quality issues, will result in an unacceptable total environment for the Randolph community,” she said.

Reaction from environmental groups to the commission’s vote was positive.

Adam Stafford with Western Resource Advocates called the decision “a win for climate action and environmental justice in Arizona.”

“It’s time for SRP to find clean alternatives and revisit its sustainability goals to adopt mass-based emissions reduction targets in line with what scientists say is needed to avoid the worst effects of climate change,” said Stafford, who is WRA’s managing senior staff attorney in Arizona.

Ellen Zuckerman with the Southwest Energy Efficiency Project also applauded the decision.

“At a time when far too many Arizonans are making painful economic decisions and falling behind on their bills, we simply cannot rubber-stamp $1 billion for improperly rushed and poorly vetted projects.” Zuckerman said in a statement.

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BPA Foresees No Capacity Deficits in Binding WRAP

The Bonneville Power Administration should have enough generation to avoid capacity deficits if it decides to join the “binding” phase of the Western Resource Adequacy Program (WRAP), the federal power marketing agency said Wednesday.

Participation in the WRAP will also have little impact on BPA’s marketing of surplus power, Steve Bellcoff, a BPA public utilities specialist, told customers during a public meeting Wednesday.

Surplus sales are a key source of BPA’s revenue, helping to defray overall system costs and reduce prices for the agency’s “preference” customer base of publicly owned utilities.

BPA has already committed to participating in the initial “nonbinding” phase of the Western Power Pool’s WRAP, scheduled to roll out in the third quarter of this year. In that phase, participants will be asked to offer “forward showings” of resource adequacy and availability seven months in advance of the summer and winter capacity periods but will not be penalized for failing to meet their requirements. (See NWPP RA Program Taking Shape for Q3 Launch.)

The agency has yet to issue a decision on whether to join the binding WRAP, which will impose penalties on participants that fail to close capacity deficits ahead of operating days.

“It’s in the coming months that we’ll start to get to a point where we’re looking at the contemplation of a decision to join for Bonneville,” Russ Mantifel, BPA Director of Market Initiatives, said during Wednesday’s meeting.

During the meeting, Bellcoff described some key — albeit surmountable — challenges to how BPA can ensure that it has enough capacity to meet its WRAP obligations. The difficulties arise, in part, from conflicts between WRAP processes and how the agency manages a hydroelectric system subject to the vagaries of weather.

Bellcoff explained that BPA begins its forecasting from the resources side, examining historical stream flows, applying current constraints and operations, then modeling the expected energy available from its hydro resources to determine how much load can be served.

On the other hand, the WRAP forward showing capacity requirement starts with the P50 (50% or higher probability) load forecast, and then adds a planning reserve margin (PRM) to that forecast.

“So everything that is done [for the WRAP] is on the opposite side of what we do today,” Bellcoff said.

Misaligned Timelines

Further complicating matters is the misalignment between WRAP timelines and BPA planning and forecasting horizons. The WRAP requires participants to submit forward showings by March 31 for the following winter season. Bellcoff noted that BPA doesn’t begin its hydro modeling for the following winter until June, months after that submittal.

“Prior to our first modeling for the next water year, we don’t have any idea what our water looks like in March or the following winter,” Bellcoff said.

Similarly, the forward showings for the WRAP’s summer season are due the previous Oct. 31, the start of the water year in the Pacific Northwest.

“The water forecast in October can be drastically different than what we would see in the spring, and those are important things because, in October, we’re still pretty conservative [in projecting] for the following summer,” Bellcoff said.

“There’s just way too many variables in our water year planning to establish at the forward showing seven months in advance of the seasons that we have vital knowledge on what our hydro looks like,” he said.

The conflicting timelines mean that BPA must rely on estimates from its long-term planning process to calculate expected capacity figures for the forward showings. Despite that complication, BPA’s own scenario planning suggests the agency has enough resources at its disposal to avoid capacity deficits along any of the WRAP’s operational timelines.

Bellcoff said the projected PRM requirements for the WRAP, based on data produced for the nonbinding phase, are 16% for winter and 12% for summer. For BPA that translates into PRMs of 1,102 MW and 768 MW, respectively.

“That’s what gets added to the load,” he said. “Those numbers are well within that wide-variety range that we look at today and plan for on the resource side, so they’re all within the uncertainty we plan for today.”

Bellcoff said that BPA also does not expect the WRAP to affect how its power operations department and trading floor work together to develop marketing strategies to deal with energy and capacity surpluses and shortages.  And because BPA does not foresee capacity deficits, it does not expect WRAP to affect its marketing of surplus power to benefit preference customers.

A slide presented at Wednesday’s meeting summed up BPA’s perspective on the issue: “The capacity obligation associated with PRM is within today’s range of resource and load variability. In advance of any specific condition, it is not known when, or if, the forward showing capacity requirement would become additive to BPA’s trading floor’s existing risk tolerance.”

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MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest

[EDITOR’S NOTE: This story was updated on Friday, April 15, 2022, to include comments made by MISO officials and stakeholders during a teleconference that day.]

MISO’s 10th annual Planning Resource Auction (PRA) saw all its Midwestern zones clearing at the nearly $240/MW-day cost of new entry (CONE), signaling the prospect of temporary outages and a dire need for additional generation.

Zones 1 to 7 — which include the Dakotas, Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana and Wisconsin — all cleared at $236.66/MW-day in the 2022/23 capacity auction, MISO announced Thursday. Zones 8 to 10 — Arkansas, Louisiana, Mississippi and Texas — did not feel the pinch and cleared at $2.88/MW-day.

MISO said that even with nearly 97 GW worth of offers, 1.3 GW of resource contributions external to MISO and 1.9 GW worth of imports from MISO South, MISO Midwest remained a little more than 1.2 GW short of its 101.2-GW planning reserve margin requirement.

The RTO said 8 GW in its North and Central regions were exposed to the CONE clearing price. MISO’s load-serving entities that don’t have enough contracted capacity to cover their load obligations use the PRA. During a teleconference with stakeholders on the results Friday, MISO Director of Resource Adequacy Coordination Zakaria Joundi said that only 8% of load participated in the auction this year. Participation in the PRA is voluntary.

Ahead of the 2022/23 planning year, MISO anticipated a 121-GW coincident systemwide peak, with 157 GW in total installed capacity and just short of 128 GW in total unforced capacity.

The grid operator attributed some of the shortfall to post-COVID load increases.

It also said that even though it has about 4 GW more worth of installed capacity footprint-wide than it did in 2018, it has about 8 GW less in accredited capacity, reflecting an uptick in intermittent generation and retiring thermal generation. Unless members build more capacity that can reliably generate, MISO said, “shortfalls such as those highlighted in this year’s auction will continue.”

Joundi said that although MISO is maintaining “decent amount of installed capacity,” accredited capacity “keeps going down.”

He said as generation retirements and suspensions were being replaced with lower-accredited renewable resources, MISO demand levels rebounded as the nation emerged from the worst of the pandemic.

“We couldn’t find enough capacity in the North-Central region,” Joundi said.

MISO’s South-to-Midwest transfer limit bound in the auction, limiting imports that could pass to the north, Joundi said. The South finished the auction with about 2 GW of surplus.

“This is an outcome we’ve been worried about for a decade,” MISO Independent Market Monitor David Patton said. He said the capacity auction’s vertical demand curve — which values reliability requirements over economics — doesn’t produce efficient enough economic signals and has caused generation that should be otherwise economic to retire. The Monitor has been a vocal proponent of a sloped demand curve for years.

“We obviously have been sounding the alarm for some time,” Michelle Bloodworth, CEO of coal trade organization America’s Power, said of thermal retirements. She said she foresees a worsening retirement crisis over the next decade.

In a press release, the RTO said it “remains committed to continue its work with members and state regulators to maintain grid reliability.”

“We have anticipated challenges due to the changing energy landscape and have communicated our concerns. … We have prepared for and projected resource fleet transformation, but these results underscore that more attention is required to offset the rate of acceleration,” MISO CEO John Bear said. “These results do not undermine our ability to meet the immediate needs of the system, but they do highlight the need for more capacity flexibility to reliably generate and manage uncertainty during this transition.”

MISO said zones 1 to 7 will head into the June 1 start of the planning year with a chance of temporary load shedding. Joundi told stakeholders to prepare for more frequent emergency procedures throughout the planning year. He also said MISO is evaluating the resource forecasting information it receives from members.

“The reality for the zones that do not have sufficient generation to cover their load plus their required reserves is that they will have increased risk of temporary, controlled outages to maintain system reliability,” MISO President and COO Clair Moeller said. “From a consumer perspective, those zones may also face higher costs to procure power when it is scarce.”

Patton has reviewed and certified the auction results.

Coalition of Midwest Power Producers representative Travis Stewart said the results were a bit of a head-scratcher, as the Midwest appeared to have sufficient capacity based on unforced capacity values heading into the auction. He said it seemed that more market participants are holding back supply up to MISO’s 50-MW withholding threshold, but Patton said he didn’t discover any withholding that would run afoul of MISO’s rule.

The price separation between MISO Midwest and South in previous auctions became even more pronounced this year. In the 2021/22 auction, zones 8 to 10 cleared at an all-time low of 1 cent/MW-day, while zones 1 to 7 cleared at $5/MW-day. (See MISO Capacity Auction Values South Capacity at a Penny.)

This is the second time CONE has made an appearance in the PRA. Zone 7, which covers MISO’s territory in Michigan, was MISO’s first local resource zone to clear at the then $257.53/MW-day CONE, in the 2020/21 auction.

The Organization of MISO States and MISO’s joint annual resource adequacy survey in 2020 warned of possible capacity shortfalls in the Midwest by 2022. However, by 2021, the survey had moved the risk into 2023. (See OMS-MISO Survey Sees Uncertain Supply Future and 2021 OMS-MISO Resource Adequacy Survey Shows Less Cause for Concern.)

“We didn’t necessarily expect this outcome to happen this year,” Joundi said. He reminded stakeholders that the OMS-MISO survey is a snapshot in time, and circumstances have changed since the last one. “Slight surpluses did erode.”

MISO said this year’s auction results show a need for market redefinition and more efforts to make resources more available. It could also be one of MISO’s last single annual capacity auctions. The grid operator has filed for FERC permission to conduct four seasonal auctions beginning in 2024. It has also asked to implement a minimum capacity requirement, in which LSEs must demonstrate that they’ve secured half of their load obligations prior to the auction. Last month, FERC issued MISO a deficiency notice for outstanding questions of the design. (See Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid.)

At a Feb. 28 executive update with stakeholders, MISO General Counsel Andre Porter said the RTO’s seasonal auction and long-range transmission planning are meant to ensure it has adequate reserves amid changing resource portfolios and increasingly unstable weather.

“Even while we wait, volatility and uncertainty continue,” Porter said of FERC’s decision time on the seasonal auction. He said MISO is encouraging states to scrutinize their resource adequacy plans to make sure they’re appropriate for a changing landscape.

But Patton said that the long-range transmission plan will only help auction results if a project increases the transfer capability between Midwest and South. MISO doesn’t plan on addressing the constraint in the long-range transmission effort anytime soon.

Patton said the RTO should consider asking for greater flow capacity between the South and Midwest when it next refreshes the transmission use agreement it has with SPP and other parties. “That is something we should think about as that agreement gets renegotiated.”

Some stakeholders called for an operational analysis of adding transmission capability between the regions.

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MISO Focuses Stakeholders on $10B LRTP Projects

MISO convened a special meeting of its Planning Advisory Committee Wednesday to underscore the urgency for $10 billion in long-range transmission projects in its Midwestern region.

Jarred Miland, the RTO’s senior manager of transmission planning coordination, stressed the grid operator’s pressure to build transmission as members’ generation portfolios transition to cleaner resources.

“The resource portfolio has been changing rapidly over the past 10 years and reliability will become increasingly difficult as renewable energy increases across the footprint,” Miland told stakeholders.

He said the long-range transmission portfolio (LRTP) seeks to “provide an orderly and timely transmission expansion effort that supports key goals,” including keeping system performance reliable in greater supply volatility and accessing lower-cost and cleaner energy.

MISO’s first set of long-range projects could be the largest portfolio of regional projects ever proposed in the U.S. The grid operator has projected that the $10.4 billion package will yield anywhere from $23 billion to $52 billion in financial benefits over the projects’ 20- to 40-year lifespans, resulting in a 2.6:1 overall benefit-to-cost ratio. (See MISO Updates Stakeholders on $10B Long-range Tx Package.)

The LRTP is broken down into six groupings of 18 line segments. Staff assumes all projects will be built by 2030.

First cycle of long-range transmission plan (MISO) Content.jpgProjects under the first cycle of MISO’s long-range transmission plan | MISO

 

Miland said “work is still ongoing” to determine whether some segments will be open to competitive bidding. MISO plans to post a draft list of the portfolio’s competitive facilities by June 1.

Staff calculated the portfolio’s benefits by quantifying transmission’s ability to solve reliability issues, reduce congestion and fuel costs, avoid new generation and other transmission investments, trim reserve margins, avert loss-of-load events and meet utility and state decarbonization goals.

MISO adviser Joe Reddoch said the RTO played it conservatively when approximating the projects’ benefits and did not overstate savings. He said although the level of benefits will differ between Midwestern transmission pricing zones, they all stand to receive benefits.  

While WEC Energy Group’s Chris Plante worried aloud that the LRTP’s benefits were too optimistic, Sustainable FERC Project attorney Lauren Azar said the identified list of benefits was probably “too narrow.”

Clean Grid Alliance said the projects can enable the additional 52.7 GW of renewable power projected in the most conservative of the  three planning scenarios. That would power about 12 million homes and support 213,000 jobs, the group said.

Stakeholders asked whether MISO has accounted for the spiking costs of building materials and labor.

Aubrey Johnson, vice president of system planning, said staff will update cost estimates over the next month, but that he doesn’t expect the figures to change much. He said MISO was cautious from the start when estimating project costs and said he only expects “fine-tuning around the margins.”

The Planning Advisory Committee will vote on whether to recommend the portfolio to the Board of Directors during a May 27 meeting. The board will vote on the portfolio on July 25.

Determining LRTP’s Effect on the Interconnection Queue

MISO is determining how long-range projects will interact with its generator interconnection queue.

During a Monday Interconnection Process Working Group, MISO’s Jesse Phillips said staff is planning to monitor when new generation projects making their way through the queue are affected by a long-range transmission project.

Phillips said if a project is found to resolve a constraint found in network upgrade studies and is approved by the board within a year of an interconnection customer striking a generator interconnection agreement, the customer will not be financially responsible for transmission upgrades. He said the generation project will then be contingent upon the transmission project instead of a network upgrade.

Generation projects that entered the queue as early as 2017 could be affected by the new considerations, Phillips said

Stakeholders expressed doubts that the long-range projects will be built in time to support new generation projects advancing through the queue. Several pointed out that the transmission projects don’t have specific in-service dates yet.

Some also asked whether MISO would consider reinstating projects to the queue that were previously priced out by high network upgrades. Before staff embarked on their long-range planning, some stakeholders criticized the RTO for placing the system expansion’s financial burden on generation developers.

Phillips said staff is in the early stages of analyzing how they should treat projects affected by the LRTP. He said MISO is accepting written opinions through April 29 on how to integrate long-range projects into interconnection studies.

The discussion came as generation projects are experiencing multiple delays in the interconnection queue’s definitive planning phase. MISO is also trying to get a feel for how many developers are lining up to enter the queue this year. Staff are asking developers for a heads up on whether they plan on submit projects by the Sept. 15 deadline.

MISO said the submittals will be used for resource forecasting and won’t supplant the need for a queue application. It also said the information developers share will be non-binding and confidential.

In March, the queue contained 848 projects totaling 133 GW of installed capacity. Solar projects accounted for 62% of the capacity, with wind, storage and hybrid formats each responsible for 11%.

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177-MW Morris Ridge Project Builds Buzz for Solar Beekeeping

A study of EDF Renewables’ 177-MW Morris Ridge project in Western New York is gaining attention for its innovative take on designing utility-scale solar with a purposeful plan for beekeeping and honey production.

The emerging agrivoltaic practice of solar beekeeping seeks to find synergies in land use in agricultural areas, according to Mary Kate MacKenzie, business manager for Sweet Grass Meats in Naples, N.Y., and co-author of the report “Co-locating Solar and Agriculture at the Morris Ridge Solar Energy Center.”

“We’re going to be seeing a lot of change in some of our agricultural landscapes as solar expands in the coming years, so solar beekeeping is an opportunity for the same piece of land to support solar energy production as well as an agricultural enterprise,” she said during a large-scale agrivoltaics webinar hosted by United Solar Energy Supporters on Tuesday.

EDF won a contract from the New York State Energy Research and Development Authority to build the Morris Ridge solar facility on 1,000 acres of leased land previously farmed for crops, such as corn and soybeans. The developer plans to incorporate agrivoltaic practices into the project, which is slated for commissioning next year.

To support that plan, the town of Mount Morris commissioned the Morris Ridge study to understand the opportunities for sheep grazing and beekeeping on the property. The study was selected for a poster presentation at the AgriVoltaics2022 Conference in Italy in June.

“It feels pretty nice that we went from first time on the drawing board to being a poster child, you could say, for sheep and bees,” said Town Supervisor David DiSalvo. “I’m hoping we have a couple of herds and a lot of beehives to be one of the leading producers of honey in New York.”

Bee-friendly Takeaways

Honey production is an $11 million/year industry in New York, and the value of honeybee commercial pollination services can reach up to $400 million/year, according to MacKenzie.

Utility-scale solar developers interested in attracting beekeepers to their facilities can take a few key points from the Morris Ridge study, she said.

The top consideration for developers is to understand the factors that will support a strong operating profit margin for the grouping of bee colonies known as an apiary.

“Beekeepers really need a minimum honey yield for an apiary to be economically viable,” MacKenzie said. “If you, as a developer, want to recruit a beekeeper to your site, you need to convince them that the honey yield will be there.”

Predicting honey yield requires an intimate knowledge of the solar facility’s landscape composition.

Vegetation in the landscape affects honeybee productivity, including how much pollen they collect and how healthy they are, MacKenzie said. The facility needs to provide the right plants for pollen collection and not expose bees to dangerous insecticides used for crop management within their foraging range.

While the study found that the Morris Ridge site does not currently have the ideal landscape composition for a profitable apiary, EDF plans to make changes that MacKenzie said will help.

“The intent of the developer is to establish permanent pasture on the site under and around the solar panels, as well as some pollinator-friendly plantings in the buffer zones across the site,” she said.

Developers will also need to understand that their approach to the business of beekeeping will be different than how it’s traditionally done.

“Beekeepers are rural folks who take great pride in having longstanding relationships with landowners, but they’re often just handshake agreements,” MacKenzie said. The study, she added, recommends that solar developers create a mutually beneficial relationship with beekeepers through written agreements.

A survey of local beekeepers used in the study found that most respondents had positive attitudes toward solar beekeeping. One respondent, however, did not believe the landscape would have the criteria he looks for in an apiary site.

“The key here is understanding what beekeepers look for and ensuring that you can provide that and communicate that as you’re trying to recruit someone to work with you,” MacKenzie said.

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PG&E Settles Kincade, Dixie Fires with Prosecutors

Critics on Tuesday denounced Pacific Gas and Electric’s $55 million settlement with prosecutors over two massively destructive fires, comparing it unfavorably to the $51 million compensation package that PG&E CEO Patti Poppe received in 2021 and the utility’s sharply rising electric rates for residential customers.

While “Poppe was raking in the money” last year, the company’s equipment started the second largest wildfire in state history, the nearly 1-million-acre Dixie Fire, which PG&E said could cost it $1.15 billion, “much of it from homes and entire communities burned to the ground,” the Environmental Working Group, a Washington D.C.-based nonprofit, said in a statement.

PG&E’s rates have risen 19% for average residential customers since Jan. 1, and the utility has asked the California Public Utilities Commission for 23% in cumulative rate hikes over the next four years. (See PG&E Rate Request Prompts Protests.)

“PG&E’s customers may not know how high their monthly gas and electric bills may go this year, how they’ll pay them, or exactly how much of California the company will burn to the ground in 2022,” Environmental Working Group President Ken Cook, a California resident, said in the statement. “But when they learn that the head of PG&E earned $51 million last year, they will know this: PG&E is out of touch and out of control.”

Dixie-Fire-Closes-Historic-District-(US-Forest-Service-Lassen-National-Forest)-Alt-FI.jpeg

The Dixie Fire bore down on the historic town of Greeneville, which was later destroyed. | U.S. Forest Service/Lassen National Forest

On Monday, PG&E (NYSE:PCG) and the Sonoma County District Attorney issued separate statements saying they had agreed to settle their dispute over the October 2019 Kincade Fire, which burned down large swaths of Sonoma County wine country and hundreds of homes and commercial structures. A broken jumper cable on a PG&E transmission tower sparked the blaze, the California Department of Forestry and Fire Protection (Cal Fire) determined.

The $20 million settlement with Sonoma County dismisses the numerous criminal charges that prosecutors had filed against PG&E and requires it to submit to an independent monitor and to create 80 new wildfire safety jobs in Sonoma County, District Attorney Jill Ravitch said in a statement defending the agreement.

“Although criminal charges are dismissed, the level of punishment and oversight provided by this judgment is greater than could be achieved against a corporation in criminal court,” Ravitch said. “For the next five years, PG&E’s operations in Sonoma County will be closely scrutinized. Furthermore, the costs of this oversight, as well as other payments under this judgment, will not be passed on to ratepayers.”

Trust but Verify?

In a separate settlement Monday, PG&E said it had signed a $35 million stipulated judgement with the district attorneys of Plumas, Lassen, Tehama, Shasta and Butte Counties to resolve “any potential criminal prosecution” of the utility in connection with last year’s Dixie Fire, which burned through all five counties over three months.

That settlement also subjects PG&E to an independent safety monitor for five years and requires the utility to hire 80 new fire safety workers across the five counties.

None of the total $55 million in settlement proceeds will be recoverable from ratepayers, PG&E said in an April 8 report to the U.S. Securities and Exchange Commission.

The CPUC fined PG&E $125 million for the Dixie Fire in December. (See CPUC Assesses PG&E $125M for Kincade Fire.)

In its 2022 proxy statement submitted April 7 to the SEC, PG&E said Poppe’s total 2021 compensation of $51.2 million last year included her base pay of $1.35 million, a $6.6 million bonus and more than $41 million in stock, based partly on meeting operational performance and safety metrics.

“We are committed to doing our part, and we look forward to a long partnership with these communities [damaged by wildfires] to make it right and make it safe,” Poppe said in Monday’s news release.  “We respect the leadership of the local DAs, welcome the new level of transparency and accountability afforded by these agreements, and look forward to working together for the benefit of the communities we collectively serve.”

Plumas County District Attorney David Hollister said in PG&E’s statement that the utility’s “new leadership team has demonstrated they are committed to change and will continue to work towards earning our trust. I appreciate this commitment and, to paraphrase the 40th President of the United States [Ronald Reagan], look forward to verifying these efforts as provided by today’s agreement.”

Others were not as enthused, including some who lost family members, homes and businesses in the catastrophic fires that PG&E equipment caused in 2015 and in each of the past five years. The fires included the November 2018 Camp Fire, which killed 84 people and leveled the town of Paradise.

PG&E pleaded guilty to 84 counts of involuntary manslaughter and one count of arson in that case while it was serving five years of federal probation stemming from the 2010 San Bruno gas pipeline disaster.

During its probation, PG&E started at least 31 wildfires, killed 113 people, destroyed nearly 24,000 structures and burned approximately 1.5 million acres, federal Judge William Alsup, of the U.S. District Court for Northern California, wrote in his final comments before reluctantly releasing PG&E from court supervision in January. (See PG&E Ends Probation as a ‘Menace to California,’ Judge Says.)

Survivors lamented the dropping of criminal charges and the settlement amounts, which they said were too low to deter PG&E from starting future fires.

In a statement by Reclaim Our Power Utility Justice Campaign, a coalition of 75 groups “fighting to hold PG&E accountable,” Mary Kay Benson, a survivor of the 2015 Butte Fire, asked what that would take.

“How many more burned-down towns, more lives upended, more burned lungs do we need to see until we get justice?” Benson said. “For the millionaire executives at murderous PG&E, the money in this settlement is a rounding error and is an appalling way to mistreat the families, farmworkers, forests and lives damaged by this monstrous company.”

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FERC Dismisses Gas Policy Update Rehearing Requests

FERC on Tuesday dismissed 14 requests for rehearing of its revised policy statement on natural gas infrastructure and its interim policy on accounting for greenhouse gas emissions, citing that it had reverted the policies to drafts after the requests had been filed (PL18-1-002, PL21-3-002).

“The draft policy statements do not constitute any final commission determination,” FERC said. “Because commission action is not final and because the rehearing parties are not aggrieved by a statement of policy, rehearing does not lie and dismissal is appropriate.”

The decision was unanimous among the five commissioners, but Commissioner James Danly issued a concurring statement noting that making the policy statements drafts does nothing to alleviate the uncertainty expressed by the petitioners, nor does it address any of his concerns about their legality.

Though Danly agreed that the requests were null now that the statements were drafts, “the ‘fog of indecision’ still lingers over the development of natural gas infrastructure,” he wrote. “What will happen [when the commission issues final proposals] is anyone’s guess. I fear that the philosophy animating the issuance of the policy statements in the first place will ultimately result in similar issuances in the future.”

Both Danly and fellow Republican Commissioner Mark Christie were strongly critical of the two updates, issued in February at FERC’s monthly open meeting as final policies that would begin to apply immediately, including to projects already filed with the commission. FERC walked them back a month later at its next meeting, with the majority citing feedback it had received that they were confusing. (See FERC Backtracks on Gas Policy Updates.)

The rehearing requests were filed by several gas pipeline groups and trade associations, as well as several states including Texas and Louisiana. Among their complaints was the retroactive application of the policies, but FERC said that when it issues its final statements, they would not apply to pending projects.

FERC noted in its order that it would include the petitioners’ requests as comments in the dockets, for which it is collecting public input by April 25. While Danly said he was gladdened by this, he expressed skepticism that the majority would address the petitioners’ concerns.

“And I have a good basis for that concern,” he wrote. “The interim GHG policy statement sidestepped many of the exact same arguments parties have made on rehearing, including the argument that the commission cannot do indirectly what it is prohibited from doing directly and that courts have found that Congress has vested the U.S. Environmental Protection Agency, not FERC, with the authority to regulate GHG emissions. Perhaps if the commission had thoughtfully (or even cursorily) considered these arguments in the first instance, it would not be in the position that it is now.”

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NJ Seeks Efficiency, Savings in OSW Transmission Process

The cost to New Jersey ratepayers of building transmission infrastructure tying the state’s offshore wind projects to the grid could be cut, and the risk of cost overruns diminished, under some of the 80 proposed projects submitted to the state Board of Public Utilities (BPU), stakeholders at a hearing into the issue argued Tuesday.

Such a strategy, if approved by the BPU, would provide a transmission system for about half of the 7.5 GW of offshore wind planned by the state, said developers and stakeholders during the three-and-a-half hour hearing on the BPU’s planning process with PJM under FERC’s State Agreement Approach (SAA). That would be a stark departure from the plans in place for the development of transmission infrastructure for the first half of the planned offshore wind capacity.

Each of the three offshore wind projects awarded by the BPU so far — Ocean Wind 1, Ocean Wind 2 and Atlantic Shores, which collectively would generate 3.758 GW of power — will design and develop their own transmission infrastructure. But the SAA process would allow one or more developers focused solely on transmission issues to design the infrastructure to connect projects awarded in the future to the grid.

Having a single project serve several projects could reap efficiencies of scale, create a more reliable system and reduce the cost to ratepayers through competitive bidding coupled with cost caps to prevent the amount paid by ratepayers from escalating beyond the contracted amount, developers said.

Becky Walding, executive director of development for NextEra Energy Transmission MidAtlantic (NYSE:NEE), said the company had calculated that the process could save “customers billions of dollars” if it results in transmission infrastructure serving several wind farms, rather than each providing their own cable system.

“There is the possibility for substantial cost savings,” added Theodore Paradise, executive vice president of transmission strategy for Anbaric Development Partners. “If you’re avoiding more cables, more trenching, more shore landings, more upgrades [and] more substation expansions because you’re making the most out of the breaker positions that you have in a substation, those are the sorts of things that can really save some money.”

But Larry Gasteiger, executive director of trade association WIRES, urged the BPU to proceed with caution. Cost caps can be weakened by “exclusions” that allow items to be charged outside the cap, and focusing on a project’s cost can sometimes be detrimental to ratepayers, he said.

“The real question here is: Do you really want the cheapest upfront design for your transmission solutions?” he said. “It raises a number of other related questions such as, what is the risk tolerance for what may be a cheaper, but less proven or unproven design over perhaps something that may wind up being more costly in terms of the design, but uses a more well established or more proven track record as the basis for that design?”

Risk vs. Cost Trade-off

The issue of how best to structure the development of future transmission infrastructure emerged as one of the most contentious topics at the BPU’s fourth and final hearing into the SAA proposals, which focused on “ratepayer protections and cost controls.” Under the SAA process, the BPU, working with PJM, solicited proposals for developing links between the grid and the offshore wind projects.

The last meeting in the series included a presentation by Michelle Manary, acting deputy assistant secretary of the Energy Resilience Division at the U.S. Department of Energy, on federal funding for offshore wind, and a panel discussion afterward that included three transmission project developers; Gasteiger; the director of the New Jersey Division of Rate Counsel; and a representative of PSEG, which owns 25% of one of the state’s offshore wind projects and submitted transmission proposals with Ørsted.

Earlier hearings presented the 80 proposals submitted by 13 developers and focused on permitting and environmental issues and grid integration issues.

The BPU, working with The Brattle Group expects to decide by October whether to adopt any of the proposals. Alternatively, it could reject them all and continue as it has so far. (See Fierce Competition in Plans to Upgrade NJ Grid.) The board has held two offshore wind solicitations and awarded three projects, each of which included the design of a transmission system to bring the power to the grid. Three more solicitations are planned, the first to take place in January 2023. (See NJ Awards Two Offshore Wind Projects.)

Rate Counsel Director Brian O. Lipman said the BPU, in assessing the proposal, needs to focus on key benefits to the state, and not get distracted by broader issues.

“For this proceeding, the real issue is not about addressing the pre-eminent challenge of climate change, but rather how will New Jersey select resources that are economically sustainable and environmentally sustainable; in this case, transmission lines,” he said. “The only issue is whether any of the proposed offshore wind transmission projects meet these goals. And if so, which are the best fit?”

The rate counsel encouraged the state only to support projects that would benefit New Jersey and not “promote regional solutions to OSW development along the Atlantic Seaboard.” New Jersey ratepayers should “not be placed in the position of subsidizing OSW development benefits for other states and regions,” he said. State officials in the past have expressed a more expansive view, saying they want New Jersey to be an offshore wind manufacturing and supply chain hub that can serve other states. (See NJ Plans ‘Flagship’ R&D Innovation Center for Wind.)

Lipman said the BPU should pick projects that fit the state’s needs and not “facilitate overdevelopment” that could “place New Jersey ratepayers in the position of having to bear the risk of future project OSW transmission benefits that never materialize.” He added that the BPU should look for projects that “offer to mitigate or assume some risks,” such as development, financial, market and regulatory risks, and require the developer to take on some of them.

“It is likely that any offer to mitigate these risks will not come free,” he said. “Thus, balancing risks and costs to determine the most advantageous proposal or proposals will involve some tradeoffs.”

Structuring the Deal

The projects would be funded by a tariff authorized by FERC that would amortize the cost of the projects over their life. PJM would then allocate the costs to the utilities serving the state, who would in turn charge the cost as a transmission fee in ratepayer bills.

How that will impact ratepayers is not clear. Lathrop Craig, vice president of development for Public Service Enterprise Group (NYSE:PEG), said the company has yet to calculate the cost of transmission, which will in any case vary depending on which project or projects the BPU chooses. But PSEG calculated that the entire cost of each of the three offshore wind projects approved so far would for the average residential account be “in the low single-digit dollars per month,” so the cost of just transmission would be much less, he said.

Speakers differed, however, on the best way to keep those costs down and curb the risk to ratepayers of rising costs.

Clint Plummer — CEO of Rise Light & Power, a New York-based wind project development company that is a subsidiary of LS Power — argued that giving the developer responsibility for all the offshore transmission infrastructure, as well as developing the project, would secure efficiencies by “putting the developers in control of every piece of the project.” That strategy has worked successfully in the past, he said.

“You give the developers not only the ability to manage their projects to deliver a lower cost to ratepayers, [but] you put more of the risk on the developers” and keep it off the ratepayers, Plummer said. Rise submitted a proposal to provide the onshore interconnection by developing a former fossil fuel plant, the Werner Generating Station in South Amboy, on a bay that fronts the New York Bight. He also argued that “it’s very difficult to optimize a wind farm if you don’t control the means by which you’re delivering your final product to market.”

But other developers argued that a separate competitive selection process to pick the transmission infrastructure would drive down costs.

“The competitive pressure of the State Agreement Approach will create tremendous value for New Jersey ratepayers in terms of cost savings and risk mitigation,” said Lawrence Willick, executive vice president of transmission regulatory for LS Power, which submitted proposals to build both onshore and offshore transmission infrastructure.

The process also will protect ratepayers by including cost caps “to actually contain the cost of transmission” development and prevent them from getting burdened with cost overruns from issues such as unforeseen schedule delays, said Anbaric’s Paradise.

AC vs. DC

A key element of the transmission system’s cost structure, however, comes from the technology used, said developers, who offered differing visions at the forum. The issue centers on whether the project uses high-voltage alternating current (HVAC) or HVDC, which is more efficient for transferring power over long distances because it incurs less power loss.

Rise CEO Plummer said HVDC systems come in “large blocks” of 1,100 to 1,500 MW, and that unless the project is a multiple of those sizes, its use would result in the creation of wasted capacity. HVAC, meanwhile, comes in blocks of 400 MW, which is far more flexible and suitable for most of New Jersey’s offshore wind areas, he said.

“HVDC makes a lot of sense for sites that are really far from shore,” he said. But more than 70% of the offshore wind area still to be leased in New Jersey “can connect to the shore with HVAC technology,” he said. “That has real advantages because HVAC is not only a more proven technology in the offshore environment, but it also is a lot cheaper.”

Willick agreed that the “distances really aren’t that long to justify the higher cost of the DC terminals,” and that HVAC systems have the benefit of lasting longer than HVDC systems, which would likely need to be replace during the project’s life.

“So really, if an AC approach does work, and is feasible, then that’s the best approach,” Willick said. “It integrates with the existing system and avoids the high cost and losses of the DC equipment.”

Paradise argued that HVDC is the best option if the state is planning for large capacity. Such a system would avoid creating “the spaghetti of all of those radial lines” running from each project to the shore and be cost effective, he said.

Anbaric submitted proposals for both transmission corridors and an offshore network. It estimated that New Jersey’s entire planned wind farm capacity of 7,500 MW could be handled by five HVDC cables, whereas it would require 19 HVAC cables, Paradise said.

“If you’re going to go big in terms of significant amounts of megawatts and building out robust transmission systems,” HVDC is preferred, he said. “So, if New Jersey is saying 7,500 [MW] is a down payment, but we want to go to 15,000 [MW], then designing a system is really important.”

NextEra’s Walding said the company designed the projects it planned to submit in two scenarios, AC and DC, and found the latter to be cheaper.

“We actually didn’t even propose the AC because it was significantly more, to the tune of 50% more expensive,” she said. “It ended up with more platforms in the ocean on that design. And, so from a cost perspective, we didn’t feel like it was the right thing.”

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New Draft of Advanced Clean Cars II Would Speed ZEV Sales

The California Air Resources Board has released a new draft of its proposed Advanced Clean Cars II regulation featuring a faster ramp up to 100% zero-emission vehicle (ZEV) sales in 2035 than an earlier draft of the rule.

The new version of the regulation would require 35% of new car sales in the state to be ZEVs in 2026. ZEV sales percentages would increase in each subsequent year, climbing to 43% in 2027 and 51% in 2028, before reaching 100% in 2035 and beyond.

A December 2021 draft of the regulation included a 26% ZEV sales requirement in 2026, followed by 34% in 2027 and 43% in 2028. The previous draft and the new version list the same ZEV sales percentages from 2031 through 2035, starting with 76% in 2031.

CARB released the new draft regulation on Tuesday and scheduled a public hearing on the proposed rules for June 9. Written comments may be submitted from April 15 through May 31, or during the public hearing.

‘Significant Milestone’

The proposed Advanced Clean Cars II regulation is a follow-up to CARB’s current Advanced Clean Cars rule.

The regulation consists of two programs. The ZEV program requires an increasing percentage of light-duty car and truck sales in the state to be zero-emission each year. The second component is the low-emission vehicle program (LEV), which sets standards for tailpipe emissions of greenhouse gases and smog-forming pollutants.

The current Advanced Clean Cars regulation sets a ZEV sales requirement of 22% in 2025. This year, the requirement is 14.5% ZEV sales.

Don Anair with the Union of Concerned Scientists called the new draft regulation a significant milestone for California as it’s the first regulatory proposal to bring the state to 100% ZEV sales by 2035. Anair is the research and deputy director for the Clean Transportation Program at UCS.

UCS had criticized the slower ramp up toward 100% ZEV sales requirement in last year’s proposal, saying that ZEV sales trends and automaker announcements showed that a more stringent regulation was feasible. And a faster ramp-up is needed to combat climate change, the group said.

Anair told NetZero Insider Wednesday that the more stringent ZEV requirements in the new proposal are “a significant improvement.”

In addition, Anair said that assurances in the proposed regulation — including battery labeling and warranty requirements — would bring more confidence to the used ZEV market.

EJ Credits Proposed

The regulation’s proposed environmental justice credits are another positive, Anair said, although he noted the voluntary credits don’t guarantee that more ZEVs will be provided to disadvantaged communities.

The environmental justice credits, which were first proposed last year, offer additional ZEV credits to car manufacturers that provide a new ZEV at a discount to a qualifying community-based clean mobility program. The discount must be 25% or more of the manufacturer’s suggested retail price. The credits would be available for model years 2026 through 2031.

CARB’s new proposal also retains a plan discussed last year to allow the transfer of credits from out-of-state ZEV sales.

If a car manufacturer earns more credits than required in a state that has adopted California’s ZEV program, those excess credits could be transferred to another state to make up a credit shortfall. The transfer would be limited to the number of credits needed to satisfy the deficit, and the transfers would only be allowed for model years 2026 through 2030.