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September 30, 2024

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NY Moves to Cut Costs for Commercial EV Charging Stations

New York is moving to cut the cost of electricity supplied to commercial charging stations for electric vehicles.

The Public Service Commission on Thursday approved a multiphase package of incentives, tariffs and programs to reduce the impact of demand charges.

As an immediate solution, all investor-owned utilities are directed to implement a 50% rebate against traditional demand charges for public direct current fast charger (DCFC) sites.

Customers qualify if their charging station accounts for at least 50% of their maximum on-site electrical demand.

The order also implements commercial managed charging program with use-case-specific adders in the territories of the two downstate utilities: Consolidated Edison (NYSE:ED) and its subsidiary Orange & Rockland Utilities.

In the upstate territories of Central Hudson Gas & Electric (NYSE:FTS), National Grid (NYSE:NGG), New York State Electric & Gas (NYSE:AGR) and Rochester Gas & Electric, the 50% rebate is extended to all commercial EV charging use cases. The four utilities are also required to file commercial managed charging program proposals within 180 days.

As a near-term solution, the PSC order requires the utilities to file within 180 days a proposal for a phased-in rate solution that will replace the demand charge rebate and use-case-specific adders.

Additionally, the order directs the utilities to implement standby rate exemptions for customers who install energy storage systems to help manage their EV charging load.

The order also imposes semiannual reporting requirements on the utilities and creates a biennial review of the effectives of the cost-relief programs and tariffs contained in the order.

The PSC’s order stems from a 2021 change to state Public Service Law. A September 2022 white paper written by Department of Public Service staff, with comments submitted by the utilities and other stakeholders in response, form the basis for much of the order.

The aim is to reduce the operating cost barrier to rapid expansion of public EV charging infrastructure that would be posed by traditional demand charges.

The PSC order notes the inherently conflicting goals at play: The demand charge is a powerful incentive for customers to manage the load they impose on the electrical grid and also potentially a disincentive to wider public acceptance of EVs. But if the incentive is removed and customers do not manage their demand, utilities will have to pay for expensive infrastructure upgrades to accommodate it, and customer prices will rise as a result.

Also, it is impossible to predict when drivers will pull into a public charging station or how much of a charge their vehicles will need. So, planning or managing load is impossible, as well as antithetical to the very point of having public chargers.

Other utility customers will bear the expense of reduced-cost electricity to public charging stations via a surcharge with a one-year lag.

“Our determination to allocate costs among service classes using the transmission-and-distribution revenues allocator reflects the fact that all customers will benefit from the environmental and societal benefits of the transition to electric vehicles, which this order seeks to accelerate,” the PSC said in its order.

The commission will cancel the existing DCFC Per-Plug Incentive (PPI) program and use its unspent funds for a new program to incentivize EV charging demand management technologies. The order calls PPI an “unpopular … series of foibles” and says that “onerous eligibility requirements” similar to those of the program would undercut the demand charge rebate.

The order refers to the “chicken-and-egg” problems of this stage of EV deployment, in which more people need to buy EVs to fund the buildout of public charging infrastructure, and more public chargers need to be built before New Yorkers have confidence to purchase EVs in larger numbers.

“It is clear that the electric vehicle charging industry faces challenging economics under today’s market conditions, particularly in areas where electric vehicle adoption does not yet generate a sufficient level of sales to offset the utility costs,” PSC Chairman Rory Christian said in a statement. “Electric vehicle deployment will play a key role in meeting the dramatic carbon-reduction goals set forth in the Climate Leadership and Community Protection Act, and our decision today provides the industry with a level of operating cost relief that will accelerate investment.”

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Nuclear Innovation Alliance: DOE Must Reorganize to Promote SMRs

The Nuclear Innovation Alliance (NIA), a D.C.-based nonprofit think tank, is advocating a makeover of the U.S. Department of Energy to expand its research-and-development mission to include assisting developers in commercializing advanced reactors.

On Thursday the group released a 37-page report, “Transforming the U.S. Department of Energy: Paving the Way to Commercialize Advanced Nuclear Energy,” arguing that the future of nuclear energy are small modular reactors (SMRs) but that they will not be rapidly deployed without a federal push.

SMRs are factory-made, installed on-site and designed with fail-safe cooling systems. They are typically 100 to 300 MW, a fraction of the power output of the nation’s existing fleet of aging commercial reactors, most of which generate at least 1,000 MW.

New reactor designs must be approved by the Nuclear Regulatory Commission, which has approved only one so far, by Oregon-based NuScale Power. The company’s modules are rated at 50 MW each in a design configuration that could hold as many as 12, for a total capacity of 600 MW. NuScale has an agreement with Utah Associated Municipal Power Systems to build an SMR later this decade on the grounds of the Idaho National Laboratory.

NIA’s report argues that SMRs can be a vital part of the nation’s efforts to decarbonize U.S. power generation and are small enough and safe enough to be installed at the sites that once were occupied by coal-burning power plants.

In a webinar following the release of the report, Executive Director Judi Greenwald elaborated: “Our hope is that the recommendations in this report will better position DOE as a catalyst with a public-private partnership needed to reach full-scale commercialization.

“This is the moment to have this conversation. Over the past couple of years, especially the Energy Act of 2020, the Infrastructure Investment and Jobs Act [of 2021] and the Inflation Reduction Act [of 2022], Congress has provided substantial new direction and funding. Now it’s time for DOE, Congress and stakeholders to focus on effective implementation of these transformative policies through DOE transformation,” Greenwald said.

The report reasons that DOE “will need to coordinate across many segments of the industry” in order to quickly allow “deployment at an immense scale” and “at least double the domestic nuclear energy capacity that is online today.”

It argues that the department should develop an agency-wide plan and include advanced nuclear energy in its Energy Earthshots Initiative.

“This strategic plan would involve establishing an advanced nuclear energy Earthshot that integrates capabilities across DOE; leveraging recent legislation and DOE’s current and future advisory committees; assessing the viable pathways to solve climate stability and energy security issues; and developing a comprehensive national strategy for exporting advanced nuclear energy technology,” the report explains.

The plan would also require a new role for DOE as a critical partner working with private SMR developers, a significant expansion of the department’s long-time role, especially through its National Laboratories, as a pure research-and-development partner.

Finally, the report advocates that the White House appoint a senior director for civil nuclear energy to assist DOE in its new role, and that Congress increase the department’s funding for its expanded responsibilities.

Kathryn Huff, assistant secretary for DOE’s Office Nuclear Energy, said she appreciated NIA’s input.

“I think the work that you all put into this report is apparent in the nuance of some of the specific examples of what we could be doing to accelerate our transformation in DOE,” she said during the webinar. “And I think it really reflects a lot of understanding of where we are as DOE and where we should be and where we could be.”

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Connecticut Looking for Grid Innovators

Connecticut has officially launched the Innovative Energy Solutions Program, a “regulatory sandbox” aimed at rolling out new ideas for a decarbonized, affordable and equitable electric grid in the state.

The program, established in March of last year by the Public Utilities Regulatory Authority, will give out $25 million in funding each project cycle, with a maximum project award of $5 million.

The idea is in part to “break up the inertia of electric utility service in Connecticut,” PURA Chairman Marissa Gillett said back when the program was announced.

The utilities can take part too, however: They would be expected to put forward “innovative customer programs and/or tariff structures.” PURA gave the examples of an advanced critical peak pricing tariff for commercial customers, and the development of a “bring your own device program” to enhance demand flexibility.

Applicants can send in their ideas for innovating through an online portal, which opened Friday.

Eligible projects don’t have to be based in Connecticut, and the types of pilots the state is looking for cover a broad range: “products, services [and] programs that are ready to be tested and have the potential to provide widespread benefits to the grid and ratepayers.”

Once selected, the applicants will have 12 to 18 months to launch their projects and collect performance data.

PURA is holding an information session Tuesday for potential applicants to learn more about the program.

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Financial Concerns Continue for Major Northeast OSW Projects

Two major offshore wind power developers are warning again of economic problems with projects off the New York and New England coasts.

Ørsted on Thursday notified investors that there would be a cost impairment of 2.5 billion kroner (roughly $365 million U.S.) on the 924-MW Sunrise Wind project in New York, its 50/50 venture with Eversource Energy (NYSE:ES), because of rising interest rates, higher capital costs and inflation.

And Avangrid (NYSE:AGR), which has said repeatedly that its 1,232-MW Commonwealth Wind project will be impossible to finance as negotiated, filed an appeal Thursday with the Massachusetts Department of Public Utilities, seeking once again to exit the power purchase agreements.

Inflation is hitting many areas of the renewable energy industry, particularly the offshore wind sector, which is forming nearly from scratch in the U.S. (See related story, Inflation Throwing a Wrench into Renewable Development.)

During a conference call Friday with Ørsted CEO Mads Nipper, financial analysts drilled in the company’s offshore projects broadly and Sunrise specifically.

Nipper said Ørsted is negotiating contracts for Sunrise in a very expensive environment, particularly for transportation and installation costs. Barring further increases in interest rates, he said, Ørsted does not expect 2023 impairments on other projects in its offshore portfolio, which were negotiated in less expensive environments.

An installation vessel is being built for Sunrise, Nipper added, and while it is a bit behind schedule, it should be ready in time to work next year.

Like Avangrid, Ørsted says it remains committed to its Northeastern offshore wind projects. It previously acquired the first commercial OSW project in the U.S., Block Island Wind in Rhode Island, and is a partner in the construction of the second, South Fork Wind in New York.

On Wednesday, a day before it quantified the financial obstacles facing Sunrise, Ørsted announced it had acquired Public Service Enterprise Group’s (NYSE:PEG) 25% share of Ocean Wind 1, giving it 100% ownership of the 1,100-MW project off the New Jersey coast. Nipper told analysts Friday that PSEG’s exit did not indicate the project was in trouble; rather, it was a strategic move to optimize tax credits.

The company said preliminary unaudited results show 2022 earnings from its worldwide offshore business down 9.5% from 2021, primarily because of delays to three projects and impacts from hedging. But it expects significantly higher offshore earnings in 2023.

Ørsted’s stock price dropped 8.7% in trading Friday.

The Commonwealth project has been unraveling for the last few months, with Avangrid saying it has negative net value as negotiated. The company has said it remains committed to the concept and would like to submit a viable bid on the project in Massachusetts’ next offshore wind solicitation.

The Massachusetts DPU has rejected Avangrid’s requests, first to pause its review of the power purchase agreements with three electric distribution companies, and then to dismiss the PPAs altogether. The companies meanwhile refused to negotiate any changes. (See Mass. DPU Orders Commonwealth Wind Project to Continue.)

In its appeal Thursday, Avangrid said the DPU’s orders are based on errors in law, unsupported by evidence, and arbitrary, capricious and an abuse of discretion.

Developers of another proposed Massachusetts wind farm — Mayflower Wind, phase 1 of which would deliver 405 MW — have cited the same financial pressures as Commonwealth but have not yet attempted to back out.

Mayflower, which previously was granted limited participant status in the Commonwealth proceeding because the two projects are interrelated, requested full participant status Thursday because of Avangrid’s latest motion.

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MISO Plans to Bar Intermittent Resources from Ramp Capability

MISO wants to exclude its intermittent class of resources from providing ramp capability by midyear.

The grid operator said last week that, in practice, dispatchable intermittent resources have not “assisted in ramping needs,” referring to wind generation that’s often trapped behind transmission congestion.

The RTO’s ramp capability product’s current design doesn’t account for a resource’s deliverability, staff said, adding that ensuring a deliverable ramp product will produce better price signals.

Senior Market Engineer Chuck Hansen said during a Market Subcommittee meeting Thursday that MISO wants to file with FERC in February to disqualify intermittent resources from ramp eligibility by June.  

Some stakeholders argued that wind can provide upward ramping and said MISO seems to be treating certain resource types unfairly because of system congestion.

Hansen said the action is prudent in today’s operating environment, but it doesn’t have to be a “forever change.” He said staff can revisit ramp eligibility as the fleet evolves.

In early December, Clean Grid Alliance’s Natalie McIntire pointed out that ramp-capable hybrid resources with storage capability currently are forced to register as dispatchable intermittent resources because MISO doesn’t yet have a hybrid resource market participation model.

MISO also wants to disable its downward ramp capability product by setting the product’s demand curve price to zero. The grid operator overwhelming needs up ramping, not down ramping.

Hansen said devaluing downward ramping is a “way of turning it off without throwing it away.”

“We’re not ready to remove it permanently,” he said. “But this is a way to disconnect the clutch, to use a metaphor.”

Hansen said staff will still track down ramping in its markets but won’t price it. He said from 2018 to 2022, MISO paid $542.80 in real-time payments for the downward product.

“It’s not that it has not been sending useful pricing signals. It’s really that it’s been sending no pricing signals,” Hansen said in December.

A MISO analysis showed that if it priced its downward ramp capability at zero, only 18 of 70,000 five-minute market settlement intervals would have been short on down ramp in the first eight months of 2022.

“We have an abundance of ability to ramp down. It’s physics; it’s always easier to ramp down,” Hansen said. “We don’t want to pay for something that’s inherent to the system.”

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Stakeholders Cry Foul on MISO’s Resource Accreditation Pivot

Less than a year after debuting availability-based accreditation, MISO is proposing to reformulate how it accredits its resources.

Stakeholders aren’t happy.

MISO wants to accredit all resources based on their performance during predefined resource adequacy hours, or tight operation conditions. It will then adjust unit accreditation by a capacity value determined by loss-of-load expectation. The equation’s LOLE piece would replace the grid operator’s use of unforced-capacity values that rely on forced outage rates.

The new design is also intended to replace MISO’s current accreditation method for renewable energy, which uses a unit-level effective load-carrying capability calculation based on a peak hour contribution. It would also have staff fashioning new planning reserve margin requirements based on coincident loss-of-load hours rather than coincident peak load hours.

Jordan Bakke, director of policy studies, told stakeholders during a Resource Adequacy Subcommittee (RASC) meeting Wednesday that MISO’s goal is to create a single, “comprehensive resource adequacy accreditation reform” filing with FERC by next year, though the requested effective date is up for debate.

“We’re not trying to seek immediate implementation,” he said.  

Bakke said the grid operator wants to shift its accreditation philosophy from “peak load-based” to “risk-based” under a sampling of the system’s riskiest hours.

Multiple stakeholders said they had serious concerns with the proposal, arguing that a direct loss-of-load approach should be applied to all resources. They contended a loss-of-load approach will only rely on a limited number of forecasted hours that are too small a sample to use for accreditation.

Invenergy’s Sophia Dossin asked how the approach will help MISO. She said a forced-outage value is broader and based on more reliable historical — rather than forecasted — information.

Bakke said a probabilistic loss-of-load approach is better suited for the tighter operating reality MISO is facing. He said the past is not an indication of the future conditions and resource mix.

Staff said using a direct loss-of-load calculation produces similar accreditation values to unforced capacity calculations.

“My reaction to that is, ‘So what?’ That’s almost a tautology,” resource adequacy consultant Michael Milligan said.

WEC Energy Group’s Chris Plante wondered whether MISO and stakeholders would be better served if they reexamined the tariff’s Schedule 53, which defines the RTO’s seasonal accreditation calculation.

“I think we’ve gone in the opposite direction of what stakeholders have intended,” he said. “I think we need to ask what it is we want out of our resource adequacy construct. Do we want it to tell us when to construct generation or do we want it to tell us the reliability value of the existing fleet? And I think it should be the latter.”

“I think what you’re hearing in this meeting today is there’s not support for this proposal. And yet, you’re moving forward with it anyway,” Clean Grid Alliance’s Natalie McIntire said.

McIntire asked why staff is proposing to change thermal resource accreditation so soon after winning approval of its availability-based method. Were they revisiting accreditation because they “didn’t get it right,” she asked.

“We need more. We need more here from MISO. And I think we need to take a step back and see what’s needed from the stakeholder process … rather than MISO completely driving this train,” McIntire said.

“I share what a lot of other stakeholders are feeling in this process: Are we going to be railroaded?” Southern Renewable Energy Association’s Andy Kowalczyk said.

Staff said they will devote more time to the topic during future RASC meetings.

FERC last year approved MISO’s seasonal capacity accreditation, which assigns accreditation based on a generating unit’s past performance during expected tight conditions. That accreditation only applies to MISO’s thermal generators; MISO has yet to file a separate, availability-based accreditation for its renewable generators. (See FERC OKs MISO Seasonal Auction, Accreditation, MISO Adding Availability-based Renewable Energy Accreditation.)

During a Jan. 17 discussion before the subcommittee, market participants complained about the difficulty of making minor adjustments to planned generator outages without taking hits to their resource accreditation. Representatives from Minnesota Power and WEC Energy Group said they have either started an approved outage early or extended it by a few days, only to entirely lose their outage exemption and negatively impact their accreditation.

Stakeholders said MISO is unfairly decrementing their availability-based accreditation for the outage’s entirety and not for just the few days tacked on. They asked staff to rectify the situation and make it easier to modify existing planned outages in MISO’s nonpublic interface.

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FERC Allows One-time Bypass of MISO IC Queue Fees

FERC last week granted a waiver to several renewable energy projects that allows their developers to circumvent MISO’s fee distribution after one of the projects dropped out of the RTO’s interconnection queue.

The commission said in its Jan. 20 order that it granted the waiver because the project negotiations with MISO resulted in a “mutually agreeable solution” that makes the other projects whole for any increased upgrade costs after EDP Renewables withdrew its Shullsburg Wind Farm (ER23-404).

EDP challenged MISO’s calculation of the monetary harm inflicted on three other wind farms with its withdrawal and termination of its generator interconnection agreement with the RTO and American Transmission Co. (ATC) in 2020.

When a generation project in MISO’s queue withdraws, staff analyzes the financial impact on remaining interconnection requests in the same study cycle by calculating network upgrades costs that are shifted to those projects. The grid operator then uses the milestone payments made during the definitive planning phase or payments made by interconnection customers to reimburse remaining projects for any upgrade costs caused by the withdrawal.

MISO determined that five other projects hoping to interconnect to ATC’s system were financially affected by the withdrawal. Two of those waived their rights because their projects were insignificantly affected.

The Shullsburg facility contested MISO’s calculations and initiated an alternative dispute resolution process in 2021. Shullsburg ultimately reached a confidential agreement between it and the three remaining projects, the companies said.

MISO said it has some reservations about the agreement because the three remaining projects aren’t guaranteed reimbursement unless they “make a certain type of sales to certain customers.” However, the grid operator said it supports the agreement because it allows the distribution of agreed-upon harm payments to the projects.

The RTO also said the agreement allows it to hold in escrow the payments Shullsburg made while in the queue until the three projects become operational.

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Phillips Presides over 1st FERC Meeting as Chair

Acting FERC Chairman Willie Phillips presided over his first open meeting Thursday, announcing a roundtable on environmental justice and his key staffers.

“I have to tell you, never in a million years would I think that somebody like me would lead an agency for the United States government, [coming] from a place like where I am from,” Phillips said.

Phillips is just the fourth African American to serve on the commission, and he often talks about his upbringing in rural Alabama and how it influences his work as a regulator. His priorities remain reliability, transmission, and environmental justice and equity issues, he said.

Phillips plans to move forward with FERC’s work on improving its transmission planning policies that started under his predecessor, Richard Glick, including efforts to improve the interconnection queues, changes to regional planning, cost management and interregional transfer capability.

On environmental justice and equity, Phillips announced a commissioner-led roundtable that will be held March 29 and is meant to further the goals of FERC’s Equity Action Plan issued last year that aims to reduce barriers to meaningful participation by underserved communities.

“This will provide an opportunity for FERC to hear from stakeholders on how the commission can better incorporate environmental justice and equity considerations,” Phillips said. “Growing up in rural Alabama, I know first-hand the effect that government can have on communities. It is important that we consider the voices of historically disadvantaged communities in our decisions.”

Phillips’ staff is led by FERC’s new chief of staff, Ronan Gulstone; Senior Transmission Counsel Karin Herzfeld; and Senior Legal Adviser Stacey Steep, who will focus on energy projects and permitting. All three worked for Phillips when he was a commissioner, with Gulstone coming over from D.C. government and the other two joining his staff from other offices at FERC.

Commissioners James Danly and Mark Christie briefly offered their congratulations to the new chairman in their opening comments. The meeting began on time and lasted only about an hour; Danly noted that he did not file any dissents on any of the orders issued.

Somber Comments from Clements

Speaking to reporters after the meeting, Phillips was optimistic about advancing the commission’s more controversial initiatives begun under Glick.

“Throughout my whole legal career, I have made a point of making a priority of consensus building,” he said. “That is how I cut my teeth working at NERC; it is a consensus-based organization. … You may have noticed that I haven’t any dissents since coming to FERC. … When I believe something is important to me, I work hard to meet my colleagues where they are and get it in the majority. I think that’s possible because I’ve done it, and I have no doubt that we can do it again, together.”

He also balked at a question of whether the commission would wait for a fifth member to continue work on the natural gas pipeline certificate policy proposals issued under Glick.

“As a global matter, we’re not waiting on anything. We’re moving forward. The commission will not sit on our hands.”

Commissioner Allison Clements, however, was more somber about the situation FERC finds itself in now.

“It’s an unfortunate set of circumstances that leave this chair next to me being empty today,” Clements said. “One thing we’ve learned over the last few months is that, because of the important work FERC does and the issues our jurisdiction spans, this agency has moved beyond the time when it got to stay out of the broader political limelight. So, the question for me, then, is how to bring forward, into this new normal, successful approaches to achieve our statutory responsibilities.”

While most orders FERC issues are done unanimously, the reality is that the hard orders that do lead to disputes among the commissioners are often the cutting edge of a changing industry that has be overseen with an “outdated and undermatched” regulatory framework.

Dealing with those thornier issues is still possible, and Clements said FERC should renew its commitment to technology neutrality and use “data-driven decision-making.”

“Only when we are willing to look at good data and credible studies, no matter the author, can we address reliability and cost issues in concrete terms on a forward-looking basis,” Clements said. “Only when we address reliability and cost issues in concrete terms can we decide whether and how much change is needed, and where any needed change may fall on the spectrum from incremental to wholesale reform.”

FERC should also prioritize the “public” in public interest, which means improving public access to it and ensuring transparency.

“It means fairly considering good arguments no matter which stripe the stakeholder who makes them wears,” Clements said. “And it means being open to the idea of making changes requested by stakeholders, small and large, because they make our decisions better.”

Clements did not respond to a request for an interview about her comments.

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FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack

Citing the need for “constant monitoring and vigilance” to protect the bulk power system from cyberthreats, FERC directed NERC on Thursday to require utilities to implement internal network security monitoring (INSM) on certain cyber systems at BPS facilities (RM22-3).

The commission approved the draft final rule at its January open meeting, with all four commissioners voting in favor of the measure. Commissioner Allison Clements said the rule would plug a critical “gap in our current cybersecurity standards” and urged FERC to “be vigilant to keep that [regulatory] ground floor strong enough … to counter the evolving threat.”

Acting Chair Willie Phillips predicted that building consensus around a new standard would “not [be] an easy task” for NERC but said it was a job that must be completed.

“I’ve noted — and I know my colleagues have noted many times — that grid security, and cybersecurity in particular, are among our most important responsibilities regarding the [BPS], so I’m very happy to see that we are moving to finalize this rulemaking today,” Phillips said.

Final Rule Softens NOPR

FERC’s order expanding NERC’s Critical Infrastructure Protection (CIP) standards builds on a Notice of Proposed Rulemaking that the commission issued almost a year ago. (See FERC Proposes New Cybersecurity Standard.) The rule applies to all high-impact bulk electric system cyber systems, regardless of whether they have external routable connectivity (ERC), and to medium-impact BES cyber systems with ERC. “Bulk electric system” refers to those facilities subject to NERC’s reliability standards, a subset of the broader BPS.

FERC gave NERC 15 months to submit new or modified CIP standards requiring INSM in all applicable BES cyber systems. NERC would also need to submit, within 12 months, a report on the feasibility of implementing INSM on low-impact BES cyber systems and medium-impact systems without ERC.

“I’m very pleased that we are directing a firm 15-month deadline for NERC to propose the standards. … It’s hard; the processes take time, but it is imperative that we get this important cybersecurity measure in place as quickly as it is feasible,” Clements said.

The draft rule represents a slight softening of FERC’s original NOPR, which proposed requiring INSM in all high- and medium-impact BES cyber systems regardless of ERC. The commission’s order explained the change as an effort to “strike a proper balance” between commenters such as NERC and the regional entities, which supported the proposal in full, and those that warned about the difficulty and cost of implementing INSM on all cyber systems. (See ERO Backs FERC’s Cyber Monitoring Proposal.)

Order Plugs Cyber Monitoring Gap

Speaking at Thursday’s open meeting, Cesar Tapia of FERC’s Office of Electric Reliability described the proposed standards as a necessary response to events like the SolarWinds hack of 2020, through which thousands of public- and private-sector organizations — including FERC itself — were infected with malicious code. Tapia said the attack “demonstrated how an attacker can bypass all perimeter-based security controls traditionally used to identify malicious activity and compromise” electronic networks believed to be secure.

In response to a question from Phillips, Tapia explained that the classification of BES cyber systems as high-, medium- and low-impact is based on “the functions of the assets housed within each system and the risks they potentially pose to the reliable operation of the” BES. He added that registered entities determine the systems’ impact level themselves.

Asked how the presence of INSM can reduce time needed to discover and respond to a security compromise, Tapia said that attackers who have compromised one device on a network “typically [attempt] to compromise other devices within the network as well,” requiring them to “move from device to device.” Unlike other security controls, INSM can alert security staff to this kind of movement, contributing to a “defense in depth strategy.”

The timelines set by FERC will begin 60 days after the publication of the final rule in the Federal Register.

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Fifth Circuit Demands an Explanation from FERC on Long-Pending Grand Gulf Complaints

The Fifth Circuit Court of Appeals told FERC Wednesday that it must explain why it has yet to rule on disputes between state regulators and Entergy that have been pending for up to six years.

The Louisiana Public Service Commission has filed several FERC complaints against Entergy’s (NYSE:ETR) System Energy Resources, Inc. (SERI), which runs plants jointly owned by the firm’s different utilities, notably the Grand Gulf Nuclear Station in Mississippi.

The PSC, along with retail regulators in Arkansas, Mississippi and New Orleans, have submitted several complaints in recent years challenging SERI’s rates — the oldest dating back to January 2017 (EL17-41) and the newest in 2021 (EL21-56). (See Entergy Regulators Ask FERC to Settle Grand Gulf Dispute.)

“The LPSC argues that consumers are over-paying SERI by about $4 million per month due to the activity alleged in one complaint,” a three-judge panel said. “Another complaint alleges that consumers in Louisiana unjustly paid a further $360 million in costs for Grand Gulf.”

The Louisiana commission went to the court to complain that FERC was taking too long in the proceedings, and its inaction was “causing irreparable injury to consumers.”

While Congress never imposed firm deadlines for FERC to resolve Section 206 complaints under the Federal Power Act, “it certainly anticipated greater alacrity than this,” the court said.

The Regulatory Fairness Act of 1998 holds that FERC is supposed to give Section 206 complaints the same priority as Section 205 filings, which come with firm deadlines. FERC is supposed to explain why it has not ruled on a complaint after 180 days, but it regularly ignores that requirement and did so in the Louisiana PSC’s complaints, the court said.

“Despite the RFA’s guidance, Section 206 proceedings before FERC appear to take much longer, costing consumers hundreds of millions of dollars and pressuring parties to settle,” the court said. “The remaining LPSC complaints have gone four to six years without resolution.”

FERC argued against any requirement to act on the case, saying it would allow it to skip the queue of other items pending before it. But the court said that argument concedes that the federal regulator has other Section 206 proceedings that have been pending even longer, meaning many consumers have been paying unjust rates, without hope for a refund, for more than six years.

FERC must make a filing within 21 days explaining why it has taken so long to deal with the regulators’ complaints.