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April 8, 2022December 13, 2023

NERC: GridEx Lessons Already In Use

Last year’s GridEx VI security exercise provided some much-needed practice for the security challenges facing the electric grid today, officials from the U.S. government said in a media briefing on Thursday.

Speakers at the briefing, held to mark the release of NERC’s after-action report on the exercise, said that several elements of the exercise have since been seen in practice during Russia’s invasion of Ukraine, including the use of social media to spread misinformation about the developing situation to cause civil unrest. Brandon Wales, executive director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), said the experience of GridEx VI has already prompted action at the federal level to address this potential threat.

Brandon Wales, CISA | NERC

“We’ve begun … working across various sectors and with relevant technology and social media companies about being prepared to respond to these blended attacks, where they’re using social media [and] disinformation to make the impacts of cyberattacks potentially worse,” Wales said. “That is something that I think in the future will likely be in the playbook of multiple adversaries if they are looking to really stress our systems.”

Puesh Kumar, director of the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER), said that the use of exercise scenarios requiring collaboration across industries, as well as between the public and private sectors, helped lay the groundwork for coordinating the response to the developing situation.

“We have lowered the bar for sharing information in terms of what we are seeing, not only out in Russia and Ukraine, but even here,” Kumar said. “You heard the president [say] about two or three weeks ago [that] we are seeing cyber activity targeted at critical infrastructure in the United States. … There are over 3,000 electric utilities across the United States. All it takes one or two utilities seeing activity, and we quickly cascade it to the others out there.”

Attendance Down from Last Time

NERC conducted the sixth iteration of GridEx across three days last November. As in previous years, the exercise was developed, managed and delivered by the Electricity Information Sharing and Analysis Center (E-ISAC). (See GridEx VI Incorporates Recent Cyber Lessons.)

GridEx VI was performed in two stages: First came the distributed play, held Nov. 16-17. In this part of the exercise, participants — more than 3,000 people across 293 organizations in the electric industry, government and other stakeholders — worked a core exercise scenario developed by E-ISAC, which also provided a virtual environment for the exercise to play out. Each organization administered the scenario itself, resulting in a “unique exercise experience” for every participant.

The second component was the executive tabletop, hosted by E-ISAC Nov. 18 for almost 200 participants from 88 organizations, including investor- and publicly owned utilities, cooperatives, independent system operators, and U.S. and Canadian government entities, as well as the natural gas and telecommunications industries. The tabletop was held online for the first time due to the COVID-19 pandemic, allowing participation by a larger and more diverse group of entities while inadvertently mirroring the way a crisis would likely play out.

Unlike the tabletop, participation in the distributed play was down significantly from the 526 organizations represented in GridEx V. Last year’s 293 organizations represent the lowest official participation in the biennial exercise since 2013’s GridEx II. (See NERC: COVID-19 is Chance to Test GridEx Lessons.) The 3,000 individuals participating were likewise fewer than half of GridEx V’s approximately 7,000.

NERC’s report attributed the decline, in part, to the participation challenges posed by the pandemic and also to changes in how participants were counted. Unlike in previous years, participants in GridEx VI were only required to register with E-ISAC to use the exercise tools or access planning materials. NERC said in light of these shifts, “future participation numbers are likely to be more comparable to those recorded for GridEx VI.”

Cyberattacks Get Personal

The scenario of GridEx VI threw myriad challenges at participants. The distributed play simulated a major cyber and physical attack against the North American power grid as customized for each organization, while the tabletop presented a similar scenario centering on the U.S. and Canadian West Coast and included attacks against the natural gas and telecommunications industries.

Timeline of the two-day distributed play component of GridEx VI | NERC

Incidents in the two-day distributed exercise were grouped into four periods, representing the morning and afternoon of each day. The first day saw control system and transmission substation faults accompanied by physical attacks on pipelines and liquid natural gas production facilities that constrained generation capacity.

Manny Cancel, E-ISAC | NERC

On the second day the adversary “directly targeted critical employees” with threats against them and their families, while social media users threatened more attacks on transmission and distribution facilities. Manny Cancel, senior vice president at NERC and CEO of E-ISAC, confirmed that the personal targeting of key personnel was derived from real events and the known capacities of potential adversaries.

“We all know that our adversaries are very sophisticated, and one of the techniques they use is to go after some of the folks in our agencies. Whether it’s through phishing campaigns or other ways to harvest credentials or data, they look for the weak link and try to take advantage of it,” Cancel said.

“Distributed planning especially is informed by the work of the people that are … on the ground. Over 700 planners … have helped us build the scenario, and they leverage the experiences they’ve been through.”

Communications Issues Highlighted

One of the most urgent recommendations from the report was that the electric and telecommunications industries strengthen their coordination in light of the “well-understood” interdependencies between both sectors. In this year’s tabletop scenario, a widespread outage in landlines and mobile phones “essentially [halted] the grid restoration process,” highlighting the need for “technical alternatives that have rudimentary functionality and high reliability.”

In Thursday’s briefing, Wales emphasized that “the report is not implying that there are no backups” for these communication systems, mentioning satellite phones and radio as methods for utilities to stay connected to their field personnel. Instead, he said, the thrust of this recommendation is to allow entities greater “certainty” about their ability to respond in an emergency.

“What’s coming out of this is a little bit deeper kind of understanding — what are the minimum requirements needed at any given location for power to be restored effectively?” Wales said. “What are the various tools that can be brought to bear? … I think that’s going to be some of the work that we do over the next two years, before the next GridEx.”

April 7, 2022December 13, 2023

FERC Approves $132K Penalty Against APS

FERC approved a slate of settlements between regional entities and utilities for violations of NERC reliability standards last week, including an agreement between WECC and Arizona Public Service (APS) carrying a penalty of $132,000 (NP22-16). Additional settlements between WECC and the Western Area Power Administration’s Rocky Mountain Region and between SERC Reliability and the Tennessee Valley Authority had no monetary penalties.

NERC submitted the settlement with TVA to the commission in a Notice of Penalty on Feb. 28. The APS and WAPA settlements were part of a spreadsheet NOP submitted the same day, along with an NOP detailing a settlement between SERC and Broad River Energy. (See related story, SERC Alleges Years of Noncompliance by Broad River in $435K Settlement.)

FERC indicated in a filing March 30 that it would not review any of the settlements, leaving the penalties intact. The commission also said it would not review two other NOPs involving violations of NERC’s Critical Infrastructure Protection standards, while reserving judgement until April 29 on a third CIP-related settlement (NP22-12, et al.). Details on the three CIP settlements were not made public, in keeping with NERC and FERC’s policy on such violations. (See FERC, NERC to End CIP Violation Disclosures.)

Breakdown Blocks Assessment for APS

WECC’s settlement with APS stems from a violation of TOP-001-4 (Transmission operations), which was in effect from July 1, 2018 to March 31, 2021. APS submitted a self-report of the infringement on July 29, 2019.

Requirement R13 of the standard, in place at the time, required that transmission operators “ensure that a real-time assessment [RTA] is performed at least once every 30 minutes.” APS found that on April 17, 2019, its energy management system (EMS) had lost visibility to some of the data being shared between APS, its reliability coordinator and neighboring entities because of “configuration issues and uncoordinated troubleshooting efforts” in a pair of recently replaced firewalls at APS’ primary control center (PCC).

As a result, the utility’s real-time contingency analysis tool — essential to performing the RTA — was unable to function and the RTA could not be done. The conditions continued until staff restored connectivity to the new firewalls, at which point the EMS regained visibility and the RTA resumed, three hours and 26 minutes after the interruption began.

During the breakdown, APS informed its neighboring entities of the issues and confirmed the loss of the relevant data with the RC. Staff in the PCC monitored the system via reports from field personnel and worked with adjacent balancing authorities to manually manage BA responsibilities.

WECC assessed the violation as a moderate risk because the lack of data from the firewalls meant APS could not perform BA functions, while the inability to perform an RTA meant that bulk power system functionality could have been lost in an emergency. However, the regional entity also noted that the utility was proactive in notifying its neighbors of the problem, and that staff continued managing BA responsibilities as best they could.

APS’ mitigating actions include implementing a formal asset change management process to verify that all newly installed devices are functioning normally, and conducting updated training for all personnel that support the EMS application. WECC considered these steps, as well as APS’ internal compliance program, as mitigating factors in determining the penalty.

WAPA Operator Missed Late-night Warning

The settlement between WECC and WAPA originated with a phase-to-ground fault on a 115-kV transmission line on June 3, 2020, at 2:02 a.m. Because of the fault, a breaker on the line tripped and could not reclose automatically; an alarm was generated through the supervisory control and data acquisition (SCADA) system, but the night shift system operator was “distracted [and] did not recognize the visual and audible alarms for over two hours.”

WECC said this failure to act amounted to a violation of TOP-001-4 requirement R1, mandating that transmission operators “act to maintain the reliability of [their] transmission operator area.”

The operator finally tried to close the breaker via SCADA at 4:17 a.m., though unsuccessfully; after maintenance went to investigate the problem, they found a broken jumper about 3 miles from the terminal where the breaker tripped. During this process a shift change occurred and the night operator left without completing an interruption report and transmission log entry. WAPA did not notify its RC and the affected transmission operator (TOP) of the event until nearly 8 a.m., and the unit was restored to service at 3:30 p.m.

By neglecting to inform the RC and transmission operator in a timely manner, the night shift operator violated requirement R8 of TOP-001-4, WECC said. This requirement specifies that RCs and TOPs be informed of “operations that … could result in an emergency.” In addition, the failure to file a 30-minute forced outage notification with the RC infringed on IRO-017-1 (Outage coordination), which requires TOPs and BAs to “perform the functions specified in [their RC’s] outage coordination process.”

WECC did not assess a monetary penalty for WAPA’s violation, citing a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal government entities. The RE did note WAPA’s mitigating actions, including updating internal procedures for restoring 115-kV lines and emergency line restoration, event reporting plan and system operator shift change, along with ensuring operators review the new procedures.

Misratings at TVA Facilities

Because TVA is also a federal government entity, SERC’s settlement with it did not result in any monetary sanctions.

The agreement between the RE and the utility involved violations of FAC-008-3 (Facility ratings) discovered through a spot check by SERC in 2017, in which the RE discovered nine instances of incorrect facility ratings, about 16% of the facilities examined. As a result of the spot check, TVA had to derate the affected facilities by as much as 49%.

SERC attributed the misratings to a number of factors; prominently, the RE found that TVA had misinterpreted requirement R3 of the standard to allow historical facility ratings or design ratings to be used to establish initial facility ratings until the ratings for the actual equipment could be determined. Not only was this assumption incorrect because the standard requires the use of actual ratings, but TVA’s facility ratings methodology lacked a time frame for the unverified data to be replaced; as a result, the use of incorrect ratings could continue “months or years after installation.”

The RE noted that a compliance audit in 2019 found no facilities with incorrect ratings, indicating “improved performance during [the intervening] time.”

While SERC was unable to assess a monetary penalty, it did impose sanctions in the form of a requirement that the RE will perform annual spot checks at TVA facilities beginning this year. The agreement did not specify how long these inspections will continue. TVA also agreed to conduct walkdowns of all transmission substations and switching stations over the next five years.

April 7, 2022January 31, 2024

CAISO Reports High Energy Prices in Q4

High natural gas costs drove wholesale electricity prices sharply higher in CAISO and its Western Energy Imbalance Market (WEIM), the ISO said in its fourth-quarter 2021 Report on Market Issues and Performance, released this week.

Day-ahead electricity prices in CAISO rose by about 50% compared with the same quarter in 2020, reflecting a similar rise in natural gas prices at key trading hubs, according to the Q4 report. Gas prices increased by more than $2/MMBtu at the Henry Hub in Louisiana, SoCal Citygate near Los Angeles, PG&E Citygate near Sacramento, NW Sumas in Washington State and El Paso Permian in Texas, it said.

PG&E Citygate saw a 65% price jump and SoCal Citygate experienced a 57% increase over the same quarter one year earlier, it said.

The price spike led to higher marginal energy prices across CAISO and the WEIM, which covers much of the Western Interconnection. Prices averaged $62/MWh in the day-ahead market, $59/MWh in the 15-minute market and $53/MWh in the real-time market.

“Electricity prices in western states typically follow natural gas price trends because gas-fired units are often the marginal source of generation in the [CAISO] balancing area and other regional markets,” the report said.

Natural gas prices drove up energy costs. | CAISO

In the WEIM, energy prices in California were 18% higher than in the rest of the interstate trading market.

“Prices tend to be higher in California than the rest of the system due to both transfer constraint congestion and greenhouse gas compliance costs for energy that is delivered to California,” CAISO said.

Congestion on three lines — the Los Banos-Quinto 230-kV line in Central California, the Miguel 500/230-kV transformer nomogram and the Imperial Valley-El Centro 230-kV nomogram, both in Southern California — affected CAISO prices the most, it said.

On major interties, “the frequency and import congestion rent on Palo Verde [feeding power from Arizona to Southern California] remained notably high relative to the same quarter in 2020,” but congestion decreased on the Pacific AC and DC interties linking the Pacific Northwest to California and the Southwest.

Prices in the WEIM’s Northwest region — which includes PacifiCorp West, Puget Sound Energy, Portland General Electric, Seattle City Light and Powerex — trended lower than in other balancing areas “due to limited transfer capability out of this region during peak system load hours,” the report said.

CAISO was a net importer during most hours except the middle of the day when California’s ample supply of inexpensive solar power makes it a net exporter.

“Compared to the fourth quarter of 2020, imports into the California ISO from Arizona Public Service and Salt River Project were partially replaced by imports from Los Angeles Department of Water and Power,” the ISO said.

CAISO’s addition of a net-load uncertainty requirement to the WEIM’s bid-range capacity test in June 2021 caused the most resource sufficiency failures in Q4 2021, but CAISO removed the controversial requirement from the test in February.

While gas prices were rising, renewable production increased by about 600MW, or 9% compared to Q4 2020, CAISO said. Hydroelectric, wind and solar generation increased 12%, but geothermal and biogas-biomass generation were down 4%, it said.

The prolonged Western drought eased from October to December, helping to increase hydropower slightly from last year’s fourth-quarter low point, but California then saw its driest January to March on record.

April 7, 2022June 14, 2023

NY Offshore Wind Transmission Project Draws No Residential Comment

The first-ever offshore wind transmission project in New York will bring 816 MW from Empire Wind 1 right under Brooklyn streets — and has drawn no comment from local residents (21-T-0366).

Siting major new energy infrastructure in New York City is notoriously difficult and expensive. Equinor (NYSE:EQNR), which is managing the project on behalf of itself and partner BP, will likely pay half a billion dollars or more to lay 17.4 miles of twin submarine cables in state jurisdictional waters. But it is facing no opposition to its plans to bring the 230-kV lines ashore at the South Brooklyn Marine Terminal.

Only developer representatives, labor and industry interests, and academics spoke at a public hearing hosted by the New York Public Service Commission on Tuesday.

According to Mariah Dignan — regional director on Long Island for Climate Jobs New York, a statewide labor coalition representing 2.6 million workers — the project and its related onshore work will undoubtedly serve the public interest and is necessary to meet the state’s climate action goals, especially the 9,000-MW target for offshore wind energy by 2035. Dignan made her remarks Tuesday.

“In addition, the project and related onshore work and construction must be done with good union, family-sustaining jobs,” Dignan said. “We look forward to working with the applicant to make this clean energy economy a reality through a just transition for not only our workforce but also our communities.”

The 50/50 joint venture of Equinor and BP (NYSE:BP) also includes Empire Wind 2 and Beacon Wind 1. The three projects will collectively provide 3.3 GW of electricity, Harrison Feuer, director of public affairs in the state for Equinor Renewables U.S., said in a presentation at the hearing before it opened to public comment.

Empire Wind Tx Proposal (Empire Wind) Content.jpg

The EW1 onshore export cables between the cable landfall and the onshore substation will consist of a three-core 230-kV HVAC bundle and are not expected to differ from the submarine export cables. | Empire Wind

The operations and maintenance base for all three projects will be situated in an industrial park adjoining the South Brooklyn terminal. “We do extensive environmental and social impact evaluations to minimize the effects on wildlife and local communities, and that happened long before we get started,” Feuer said.

The developers expect state permitting to conclude between the end of 2023 and beginning of 2024, when construction will then commence, said Joshua Verleun, Equinor manager for the permitting process in New York.

After landfall at South Brooklyn, the 230-kV export cables will be connected to an onshore substation to up the voltage to 345 kV for interconnection to the grid.

“When the cables make landfall, they will be pulled directly through the bulkhead to terminate into the onshore substation,” Verleun said. “From the onshore substation there is a short interconnection cable that runs along New York City streets and connects into the existing Con Edison Gowanus substation.”

The approval of the project’s transmission lines will be a critical milestone in its development, said Fred Zalcman, director of the New York Offshore Wind Alliance, a coalition of OSW developers, including Equinor, national environmental organizations, labor and academia.

“This project presents many good benefits to the electric grid of downstate New York, and one of the key benefits I see is its proximity to the New York City load center,” said Thomas Barracca, director of the Office of Economic Development at Stony Brook University, which runs a workforce development program for the OSW industry in New York. “In terms of environmental impact, the project has been very well conceived and thought out, and has obviously been vetted with a lot of stakeholders in the environmental community.”

The developers engaged with local fisheries, whose feedback helped inform decisions on how the project is made, and also worked closely with the U.S. Bureau of Ocean Energy Management and Department of Defense to mitigate any potential interference of coastal defense and radar, Feuer said.

“We are delighted that the cable connection would be going to Brooklyn,” said Adrienne Esposito, executive director of Citizens Campaign for the Environment, a statewide group with 140,000 members. “We all know that the greatest load of fossil fuel use is … in New York City and also on Long Island, and that’s why it’s so imperative that wind farms get connected to both of those areas.”

April 7, 2022October 25, 2023

NY Greenlights $345M, 280-MW Excelsior Solar Farm

New York officials on Wednesday approved a NextEra Energy Resources subsidiary to build and operate a 280-MW solar farm with 20 MW of battery storage capacity on a few thousand acres of farmland between Rochester and Niagara Falls (19-F-0299).

The state Board on Electric Generation Siting and the Environment authorized a certificate of environmental compatibility and public need for the estimated $345 million Excelsior Energy Center project in the Town of Byron in Genesee County. The facility will be the largest solar farm ever built in New York, with solar panels covering 1,716 acres on a project tract of about 3,443 acres and is expected to begin commercial operation in late 2022.

Administrative Law Judge Gregg Sayre detailed the reasoning of the Department of Public Service staff recommendation to the siting board, saying the contested issues fell into three areas: the use of agricultural land, particularly prime farmland; the impact of the project on the character of the community as a result of its size and visual impact; and the alleged noncompliance of the project with the Town of Byron and Genesee County comprehensive plans.

Contested Issues

The state Department of Agriculture and Markets objected to 30% of the project being located on prime farmland and claimed that a solar energy project constitutes a permanent conversion of farmland to non-agricultural uses.

The Siting Board rejected the argument about permanent conversion of farmland in the Hecate Energy Albany case in January of 2021 when it concluded that a commercial solar facility does not result in a permanent loss of farmland where certificate conditions require the land to be fully restored as closely as possible to its prior condition upon decommissioning (17-F-0617).

Judge Gregg Sayre, NYDPS | NYDPS

“In this case there is some permanent loss of farmland due to access roads and other similar construction, but it amounts to only about 31 acres, which is less than 1% of the project’s area,” Sayre said. “Although the department is certainly correct that agricultural production will be reduced in the footprint of the project for approximately 30 years, the reason behind that loss is that the property owners in question have voluntarily entered into lease agreements with the applicant.”

A local group, Byron Association Against Solar (BAAS), filed at least 20 documents regarding safety concerns, issues concerning soil and air contamination, concerns about the danger of battery fires, and the layout of the project, roads, boundaries and set-backs.

BAAS offered two studies to support its position that the project will have a massive negative impact on farming in the town of Byron, but one of the reports was based on what Sayre said is a “completely erroneous” number of affected acres. The report, he said, is deficient in using one year of crop pricing in its analysis of impacts rather than a longer average given the price fluctuation that occurred over the course of several years in the town’s top 10 crops.

The second study produced by BAAS claims that the project would cause a redistribution of farms and lands and an increase in farming costs, but it fails to support its conclusions that the project would increase the cost of farming in the area, Sayre said.

BAAS also put in the testimony from Eric Zuber, owner of a large dairy farm adjoining the project area, who stated that he would lose the use of farmland on which he spreads excess manure.

Secondly, the order concluded that claims that the project will destroy the rural community were “overstated” and that visual impacts have been avoided or minimized to the maximum extent practicable.

Laws and Plans

The third issue in dispute was based on the testimony of a local resident speaking for himself, not for the town or the county, that the project is inconsistent with the town and county comprehensive plans.

Tammy Mitchell, NYDPS | NYDPS

“The resident is absolutely correct in stating that the protection of agricultural lands is listed as a goal in both of those plans, but … the town comprehensive plan also explicitly supports the development of clean energy resources, so there is necessarily, as with most land-use issues, some balancing required of competing goals,” Sayre said.

Last year, the town adopted a solar law, finding that the law is consistent with its comprehensive plan, and the county planning board implicitly found that the law was consistent with both the town and county comprehensive plans when it approved the town law, Sayre said.

“I believe that the proposed draft order granting a certificate of environmental compatibility and public need for the Excelsior solar generating facility is well balanced and avoids or mitigates impacts to the extent practicable,” said Tammy Mitchell, director of the DPS Office of Electric, Gas and Water, serving as alternate chair of the board in place of Public Service Commission Chair Rory Christian.

The other alternates for the permanent members of the Siting Board were Louis Alexander, representing the commissioner of the Department of Environmental Conservation; Dr. Elizabeth Lewis-Michl, representing the commissioner of the Department of Health; Vincent Ravaschiere, representing the commissioner of the Department of Economic Development; and John Williams, representing the chair of the New York State Energy Research and Development Authority.

The Siting Board for the Excelsior case also included one ad hoc member, Norman Pawlak, dissenting.

April 7, 2022November 9, 2023

California Seeks to Blaze Trail for Long-duration Storage

California Gov. Gavin Newsom is looking to earmark $380 million for long-duration energy storage (LDES) incentives in his proposed 2022/23 state budget. For California energy officials, the state’s grid operator and LDES developers, that money can’t arrive soon enough.

California defines “long-duration” as any storage resource able to discharge energy to the grid for at least eight hours at full output, but the state also has a “stretch goal” of 20 to 100 hours. While otherwise technology-neutral, Newsom’s incentive program would seek to boost the commercial prospects of alternatives to lithium-ion batteries and pumped hydro. Priority would be given to technologies on the verge of commercialization or positioned for widespread deployment within the next five to 10 years.

Speaking Tuesday at an interagency workshop exploring ways to advance the adoption of non-lithium-ion LDES, California Energy Commission Chair David Hochschild acknowledged that the $380 million in funding “still has a little ways to go” before passing the legislature.

“But part of the reason for coming together today was feeling an incredible sense of urgency about getting this right, particularly on program design,” Hochschild said.

Two issues are driving that urgency, according to speakers at the workshop.

The first is that California’s grid, increasingly reliant on variable renewable generation, will soon push its reliability limits by relying on four-hour batteries as a substitute for gas-fired peaking resources.

The second factor is more global in nature, with competition for worldwide lithium supplies heating up as more consumers purchase electric vehicles and government policies across the world encourage the electrification of most forms of transportation and heavy-duty equipment.

‘Incredibly Versatile’

Two years ago, CAISO had about 200 MW of battery storage on its grid. Today it manages 3,100 MW, most of which is lithium-ion. By summer, that number is expected to reach 4,000 MW.

During Tuesday’s workshop, Hochschild praised the state’s ability to integrate that kind growth in such a short time.

“We’re not finished, of course; there’s a lot more to go; but just to actually have that installed and dispatchable is incredible,” he said.

“Not only is California leading the way in terms of [storage] technologies that are on the grid, and what we’re operating today, we’re also leading the way in terms of the tools that we have to actually manage and operate these resources,” said Gabe Murtaugh, storage sector manager at CAISO.

California’s battery storage resources, predominantly four-hour in duration, are “incredibly versatile,” helping CAISO manage peak loads and “operational uncertainty” on the grid, Murtaugh said. The ISO has committed much time to developing market models that manage the state of charge of those resources, he said, ensuring they’re available when needed most, such as on the hottest summer days.

But the continued emergence of storage requires a dynamic approach to managing the resources, Murtaugh said. The California Public Utilities Commission’s 2032 integrated resources plan calls for 15 GW of storage by 2032, with 30 to 50 GW looking further out, according to Jonah Steinbuck, deputy director of the CEC’s Energy Research and Development Divsion.

“Just because we have a model that works today, and we’re sharing that model with other ISOs and RTOs across the country, doesn’t mean our work on storage is done by any means,” Murtaugh said. “We know that there’s other different kinds — different flavors — of technology: long-duration technology; other short-duration batteries as well. And as we’ve mentioned before, the ISO is technology-agnostic, so we really need to design our models to be able to accommodate all kinds of technologies potentially.”

The growing prevalence of variable generation in California will alter the shape of CAISO’s “duck curve,” the iconic graph that depicts the deep trough in the ISO’s “net load” during the middle of the day (formerly the period of peak demand) as solar resources reach full output, followed by the steep rise in net load heading into evening as those same resources taper and cease production.

Longer-term peak load forecasts from the CEC indicate the middle of the duck curve will become even deeper and wider as California brings on more solar resources, while net loads in the late afternoon and evening will become even steeper with increased electrification of the state’s economy.

The key for the ISO is to shift the solar oversupply in the trough period to the high needs during the ramp. Using the CEC’s forecasts, CAISO predicts that, by 2024, four-hour batteries discharging at full capacity will be insufficient to provide the energy flows necessary to meet demand across a longer and steeper evening peak. Long-duration storage will be needed to cover that gap and avoid continued reliance on peaking plants.

“Obviously, you can take a four-hour battery and operate it at something less than its full output for a longer period of time, but you’re probably losing some efficiency there,” Murtaugh said.

More challenges loom beyond 2024, as the state pursues its policy of achieving a zero-emissions grid by 2045, requiring use of even longer-duration storage of up to 100 hours, Murtaugh said. That’s because CAISO expects the grid will shift from a summer- to winter-peaking system.

“The hardest times will be during multiday periods when we have low wind and low solar availability, which is more prevalent in the winter than it is in the summer,” he said. “And in those kinds of situations, when we’re very heavily reliant on renewables to produce the energy that’s going to be consumed in the state, then you need storage or some other solution to generate new energy in order to keep the lights on across those periods.”

Other factors will compound the need to adopt long-duration storage by the middle of this decade, according to James McGarry, a senior analyst in integrated resource planning at the CPUC.

Among them is the expected retirement in 2024 of 1.3 GW of gas-fired capacity 40 years or older and the closure of 3.7 GW of thermal plants relying on once-through cooling, followed by the 2025 retirement of the 2.3-GW Diablo Canyon nuclear plant.

“And throughout this time period, West-wide heat and drought conditions paired with neighboring states increasing their own clean energy commitments are leading us to expect tighter availability of imports during peak demand periods,” McGarry said.

“As we look across different use cases and applications, long-duration storage has a major role to play in the ISO’s local capacity requirements,” said Jin Noh, policy director for the California Energy Storage Association. “Studies are already showing a significant need to look at long-duration storage if we really want to replace local gas generation.”

Noh said long-duration storage could provide more of the “diverse capabilities” the ISO is seeking to manage a system increasingly dominated by inverter-based resources, including offering inertia support and helping to “better optimize and utilize the other resources on the grid.”

‘Dirt Cheap’

According to Noh, long-duration storage technologies already benefit from “pretty significant” private investment. But Gov. Newsom’s proposed incentives would “serve as that tipping point for technologies that are really on the verge of commercialization” while easing the “first-mover burden” on those organizations adopting the new technologies.

CEC Vice Chair Siva Gunda pointed out that part of that burden includes testing — then rapidly scaling — the new technologies. Lithium-ion batteries benefited from about 10 years of deployment and providing operational data before attracting broad private investment, he said.

To help alleviate the proof-of-concept burden for LDES, the U.S. Department of Energy has proposed the Rapid Operational Validation Initiative, designed to accelerate testing and have resources ready for commercialization by 2030, ahead of the Biden administration’s 2035 target for a clean U.S. electricity system, said Eric Hsieh, DOE’s director of grid systems and components.

“We’re looking to use these demonstrations to collect data from them [and] combine them with accelerated testing procedures in the lab with domain knowledge and [artificial intelligence/machine learning] algorithms, with the intent of being able to provide investment-grade performance projections with just one year of data,” Hsieh said.

And another key development adds to the time pressure to deploy LDES, according to Larry Zulch, CEO of Invinity Energy Systems, a flow battery developer.

“I talk to a lot of metals companies, people who are in the trade, and they keep telling me, ‘You have no idea what kind of lithium shortage is coming along because of the [transportation sector] requirements,’” Zulch said.

Zulch said the applications that will rely on energy-rich lithium-ion batteries, which include EVs, airplanes and construction equipment, “far exceed the increased production capabilities” of lithium and nickel mines.

Invinity’s flow batteries rely on vanadium, which Zulch said is more abundant than copper and found throughout the world, preventing it from becoming a “conflict” mineral.

Other LDES company representatives speaking during a workshop panel also touted the relative abundance of the critical minerals used in their systems. Mateo Jaramillo, CEO of Form Energy, said his company’s iron-air design relies on the most heavily mined mineral on Earth, present on every continent. Henrik Stiesdal, founder of Stiesdal A/S, said the storage medium in his company’s thermal energy system is crushed basalt, which he called “dirt cheap.”

Unsurprisingly, company executives were unified in their belief that the moment has already arrived for LDES.

“I think the [LDES] batteries that all of the panelists, along with myself, are able to produce and provide are addressing a specific market need that’s already there,” said Balki Iyer, chief commercial officer of Eos Energy.

“What we see here is the fact that we actually have a longer-duration need from the market [that’s] driving the shift, moving away from lithium to non-lithium, longer-duration batteries,” he said.

April 7, 2022June 14, 2023

TVA Board Nominees Back Renewable Power, Affordability

Nominees to the Tennessee Valley Authority’s Board of Directors stressed affordable rates and a more robust renewable portfolio for the federal utility during their confirmation hearing Tuesday.

Beth Geer, Robert Klein and L. Michelle Moore appeared before the U.S. Senate Committee on Environment and Public Works about a year after they were nominated to the TVA’s board by President Joe Biden. Also sitting before the committee was Ben Wagner, a longtime employee in TVA’s office of the inspector general who has been nominated to serve as the federal utility’s next inspector general.

Committee Chair Sen. Edward Markey (D-Mass.) opened the hearing by saying TVA could do more to provide innovation, low-cost power, environmental stewardship, and reduce its 10 million customers’ energy burdens.

Markey said TVA could substantially expand its generation portfolio’s 3% share of wind and solar, both at the utility scale and the distribution level. He called the 3% share a “very sad number.”

“It’s almost as though it’s still the 1930s and there hasn’t been any real progress in terms of the implementation of real change,” Markey said. “Unfortunately, the TVA has pushed, for several decades, more fossil fuel energy at the expense of potentially cheaper renewable sources, which pollutes our communities and exacerbates energy burdens for TVA customers, who already pay some of the highest electricity bills in the nation as a percentage of household income.”

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TVA nominees (from left) Beth Geer, Robert Klein, L. Michelle Moore and Ben Wagner | U.S. Senate Committee on Environment and Public Works

Markey said the trio of nominees are well-positioned to prudently influence the utility’s energy planning for years to come and provide customers with “reliable, clean and affordable” energy.”

However, ranking member Sen. Jim Inhofe (R-Okla.) said “calls to eliminate fossil fuels from the power sector are foolish and would be devastating for the American people by increasing already sky-high utility bills and creating greater unreliability for the electric grid.”

He said the nominees must recognize the ongoing need to maintain fossil fuels as part of TVA’s power supply.

“The TVA must not be weaponized to pursue a radical, Green New Deal-inspired agenda that forgoes reliability and affordability and fossil fuels for its power supply in the name of climate alarmism,” Inhofe said.

He also criticized the slate of nominees for not including anyone from Kentucky or Mississippi.

The TVA Act prescribes that seven of the board’s nine members be residents of the TVA service area and that their residences be geographically diverse across the footprint. The current board contains members hailing from Georgia and Tennessee; the nominees also come from those two states.

TVA’s current board is at quorum with five of nine seats filled. However, two directors’ terms expire in May. The utility’s bylaws allow board members to stay on through the end of the year to maintain quorum if replacements have not been confirmed in time.

The current board includes Chair William Kilbride, whose term expires in 2023; A.D. Frazier and Jeff Smith, whose terms expire this year; and Beth Harwell and Brian Noland, whose terms expire in 2024. If the nominees are confirmed, the board will have three women instead of one, but no one of color.

“The financial success of renewable energy is something I observe daily in my current work, and it’s why the sustainability revolution may now be the most significant investing and business opportunity in the world,” Geer said in her testimony. “Sustainability does not just make sense for our environment; it makes good sense for economic progress.”

Geer, a Tennessee resident, is chief of staff to former Vice President Al Gore and serves on Nashville’s Sustainability Advisory Committee.

“Let me say that while I have worked in the political realm at many points in my career, I firmly believe that doing what is best for all the people of the Tennessee Valley is what matters, and that is, at the end of the day, a non-partisan issue,” she said.

Geer said she shared Markey’s concerns with TVA’s relatively small deployment of wind and solar.

Ernst Objects to 2015 Tweet

Sen. Joni Ernst (R-Iowa) said she will oppose Geer’s nomination over a 2015 Twitter comment she made in response to a Fox News tweet featuring an image of Ernst and a quote from her State of the Union response. Geer responded “hideous” to the tweet, which asked, “What did you think of Sen. Joni Ernst’s GOP response to the State of the Union address?”

Ernst asked Geer to explain herself, saying, “You believe one reason you should be confirmed to serve in the TVA, the Tennessee Valley, is because of your ability to quote, ‘build relationships and work together,’ end quote. Is that correct?”

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TVA board nominee Beth Geer | U.S. Senate Committee on Environment and Public Works

“Well, I apologize if I offended you, and I appreciate you bringing it to my attention,” Geer said. “And I do, in fact, believe that civility is key, and I’m sorry that I did not demonstrate that, in your opinion, with that tweet.”

Klein, a former lineman at the Electric Power Board of Chattanooga and member of the International Brotherhood of Electrical Workers, said TVA’s status as a government-owned public utility poises it “to be a leader in technology and innovation for the nation, allowing the United States and the Southeast, in particular, to contribute to our collective goals of decarbonization.”

Klein said if confirmed, he would support carbon reductions and “look for projects that could potentially lead the way in further reductions.” He said he was particularly interested in TVA’s exploration of a small modular nuclear reactor near Oak Ridge, Tenn.

Klein also said he was committed to exploring new renewable energy additions to TVA’s fleet.

Moore, a former sustainability staffer in the Obama White House and CEO of solar nonprofit Groundswell, said “energy and environmental quality go hand in hand in hand with fiscal responsibility” and pointed to her work in helping build a market for green buildings that use less energy and water.

She recalled a childhood in which her grandparents would rack up “backbreaking” $300-$400 energy bills because they were forced to turn on their furnace periodically during Georgia winters to keep their inefficient house’s pipes from freezing.

Ranking member Sen. Shelley Capito (R-W. Va.) grilled Moore on a 2018 tweet on her now-private, personal twitter account where she wrote, “Oil is like opioids, it keeps you sick and poor.” Capito asked how Moore would square her opinions with TVA’s 40% fossil fuel energy portfolio.

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TVA board nominee L. Michelle Moore | U.S. Senate Committee on Environment and Public Works

Moore said while she was grateful for fossil fuels powering the Industrial Revolution and helping to lift families out of poverty, it’s time to move forward with clean energy and new technologies. She said she envisioned battery storage having a bigger role in TVA’s portfolio and said she will make sure that as TVA’s decarbonization plays out, communities with fossil plants will be supported.

Late last year, the five-member board voted to give TVA CEO Jeff Lyash more discretion over utility decisions, including replacing output from the Cumberland and Kingston coal plants in Tennessee. TVA is currently exploring building pipelines and two new natural gas plants at the sites, a move the Sierra Club opposes.

TVA’s emissions goals and renewable generation plans are currently the focus of an inquiry by the U.S. House of Representatives’ Committee on Energy and Commerce. The committee is questioning whether the utility is doing enough to keep rates affordable and invest in renewables and energy efficiency. (See TVA Defends Rates, CO2 Reduction Plans in House Inquiry.)

Before the inquiry, several nonprofit groups said TVA needed a stronger decarbonization plan than its current 2050 goal.

Wagner is a 31-year veteran of TVA’s inspector general’s office, where he served as an investigator and auditor until his retirement in 2017. Before that, he worked in TVA’s nuclear power segment.

Wagner committed to performing program reevaluations of TVA’s audits and investigations to determine possible process improvements.

All nominees agreed to Markey’s ask to pay close attention to TVA’s coal ash dumps. Markey also asked that nominees pledge to place emphasis on energy efficiency measures.

The committee will vote on the nominations in the weeks ahead. A full Senate vote will follow.

The hearing comes as TVA risks losing the largest of its 153 power company customers, Memphis Light, Gas and Water (MLGW), over affordability concerns and low renewable energy investment. MLGW and a third-party contractor hired to oversee a request for proposals are currently evaluating 27 bids for alternative electricity supply, including one from MISO.

The city utility has previously said it will release a short list of finalists and invite the companies to prepare presentations this summer. After that, MLGW plans to request final offers and potentially award a contract in December.

April 7, 2022

Forum: Collaboration Key in Minimizing Enviro Impact of NJ Offshore Tx

The key to minimizing the environmental impact of running transmission lines from New Jersey’s offshore wind projects to the onshore grid will be collaboration and coordination between developers to tie several projects to the same cable ashore, speakers told a state Board of Public Utilities (BPU) hearing Monday.

The suggestion emerged at the third of four hearings into the proposals submitted under FERC Order 1000’s State Agreement Approach (SAA), a solicitation process conducted by New Jersey with PJM in which 13 developers have offered 80 suggestions on how to upgrade the grid to handle the future wind-generated power.

The hearing focused on environmental and permitting issues that are expected to surface in the development of an enhanced transmission system, including the sensitive issue of how to secure public support for the projects and curb opposition. In New Jersey, some elements in the tourism and fishing sectors — and local residents near to where cables from the offshore wind turbines would come ashore — all oppose the projects.

Jeff Nield, an environmental consultant, told the hearing that a system that tied several projects to a single corridor of HVDC cables would be preferable to several projects each running their own line ashore and creating “multiple cable landfall locations.” Tying several projects to cables following the same route, and using a common substation location, would minimize the “overall environmental footprint,” reducing the sea floor disturbance and disruption of neighborhoods when the cable comes on land, he said.

Nield represents developer Mid-Atlantic Offshore Development (MAOD), which submitted three proposed cable routes. It is a joint venture between EDF Renewables North America and Shell New Energies US, who also partnered to submit the proposal for Atlantic Shores, one of New Jersey’s approved offshore wind projects.

A single-cable corridor, Nield said, would benefit from using HVDC technology, which is able to “transmit more electricity from offshore wind projects through fewer circuits occupying less area offshore and on land.” And a “coordinated transmission solution can also decrease the potential conflicts with other resource users,” he added, citing the example of the impact on shipping.

“This equates to fewer potential conflicts with shipping because cables are routed in one well sited corridor, and it minimizes the areas that conflicts can occur with commercial and recreational fishing,” he said.

That reduction in disruption also could make for a smoother passage for the transmission project through the environmental process, said Michael Sole, vice president of environmental services at NextEra Energy, which submitted several proposals for routes.

“The key thing is fewer environmental impacts means lower permitting risks,” said Sole, who displayed a presentation slide that showed a project with a single trunk line linking four wind areas and a project with several cables coming from the wind areas and only joining together in a single collector station closer to the shore.

The single-trunk line “minimizes the footprint and impact of cable routes coming in onshore as compared to an alternative solution where if every wind developer had to bring a landing into the shore,” he said. “So, the question of a coordinated transmission approach is: Can it be done efficiently with an offshore wind development? And the short answer is: absolutely.”

Fishermen Doubts

The forum followed two earlier hearings that focused on the proposals submitted and the BPU’s evaluation process, and how they would be integrated into the existing grid. The BPU expects to decide on the proposals in October.

New Jersey, with a mandate from Gov. Phil Murphy that it reach 100% clean energy by 2050, see its growing offshore wind sector as a key element in the effort and has set a goal of 7.5 GW from the sector. The state has so far approved three offshore wind projects — the 1,100-MW Ocean Wind and 1,148-MW Ocean Wind II, and the 1,510-MW Atlantic Shores — in two solicitations, with three more solicitations expected to be awarded by 2027 and in operation by 2033.

The first three projects included plans to bring the energy ashore. But the BPU, through the SAA process, is looking for a more efficient way to do that for future projects.

In presenting the problem to potential developers, the board sketched out three general proposals for the transmission elements that could be addressed, including the upgrades needed. The proposals also included an “offshore transmission backbone” that would run parallel to the coast and provide a connecting strip to receive the energy from the wind farms and pass it on to cables headed for the shore. (See Fierce Competition in Plans to Upgrade NJ Grid.)

The potential disruption of marine life and in the coastal communities through which any cable would pass through is among the most sensitive faced by the offshore wind projects. Ocean Wind is facing vigorous opposition in the tourist town of Ocean City in South Jersey, through which the cable would pass as it goes to a now closed coal-fired power plant in neighboring Upper Township. (See Ørsted NJ Wind Project Faces Local Opposition.)

Commercial fishermen, who are among the most vigorous opponents of the wind projects, fear that the projects will damage habitats, perhaps scaring fish away from long-time fishing areas, and that it will be dangerous to fish around the turbines. Fishing representatives say the combination of the weight of the fishing nets and the impact of the waves, wind and tides passing through rows of turbines can make it difficult and dangerous to maneuver a fishing vessel. (See Fishing Industry Concerned About NY Bight OSW Plan.)

Scot Mackey, a lobbyist for Garden State Seafood Association, a 1,200-member industry group that represents fishers of scallop, clam and other fish, commended the BPU and state Department of Environmental Protection (DEP) for “trying to play catch up with this issue.” But he added that the impact of the cable and transmission infrastructure should have been addressed before.

“We are greatly concerned about the impact of transmission,” he told the hearing. “We support minimizing the number of cables in the greatest possible way to minimize the impact on commercial fishing, most of which is done via bottom [and] midwater trawl pulling large structures through this environment.

“We are greatly concerned with the size, scope and cumulative effects of such huge projects in such a short period of time being proposed off our coast, in prime fishing grounds,” he said.

Zachary Klein, a policy attorney for Clean Ocean Action, also questioned the pace at which the offshore development is unfolding.

“Given the seriousness of the risks at play, it seems more responsible to start with a pilot-scale offshore wind development in the mid-Atlantic to minimize the impacts of bringing energy onshore while we figure out how to do so most responsibly, in greater volume,” he said.

“I just urge that the approach to minimizing these impacts not be looked at so rigidly,” he added. “And that if necessary or appropriate, we take a step back, and consider that maybe reducing or not jumping to rapid industrial development might help ensure that this interconnection with the grid can be done in the most responsible way possible.”

April 7, 2022December 13, 2023

FERC Accepts PJM CTOA Revisions

FERC on Tuesday accepted revisions to PJM’s Consolidated Transmission Owners Agreement (CTOA) changing the voting rules in the Transmission Owners Agreement-Administrative Committee (TOA-AC) and giving more voting power to larger transmission owners in the RTO (ER22-358).

PJM TOs in November filed the proposed revisions to the CTOA. The changes

called for the removal of an individual vote majority requirement “where an extreme supermajority of ownership supports an action;”
permitted voting action to occur “where a quorum of an extreme supermajority ownership is present;”
provided “comparable changes to the conduct of simple majority votes,” and;
limited the open meeting requirement to matters subject to a two-thirds voting rule under the existing CTOA language.

The commission said the revisions received “broad support” among transmission owners in a vote taken in October at the TOA-AC. The revisions become effective retroactively to Jan. 10.

“We find that the proposed CTOA revisions are just and reasonable as they are limited modifications to the CTOA that allow PJM Transmission Owners to resolve concerns potentially affecting their ability to achieve the needed vote to propose tariff changes to the Commission, and to effectively and efficiently conduct the business of the TOA-AC and execute their responsibilities as transmission owning members of PJM pursuant to the CTOA,” FERC said in its order.

Issues

The TOs said the CTOA currently features a voting structure based on a combination of two separate votes needed to act on an issue: an individual vote based on the votes of individual, unaffiliated PJM transmission owners; and a weighted vote based on the net asset value of each PJM transmission owner’s transmission facilities. According to the rules of the CTOA, no individual TO can have a weighted vote of more than 24.9% of the sum of the weighted votes.

Voting under current CTOA rules at the TOA-AC is divided into two procedures, including an action where a supermajority, or two-thirds, of the individual and weighted votes is required, or an action where a simple majority of both the individual and weighted votes is required.

The voting items requiring a supermajority include comments on the Regional Transmission Expansion Plan (RTEP) and tariff changes related to the recovery of transmission-related costs, including “joint rates or the PJM transmission rate design.” If a proposed issue such as a tariff change is supported by 95% of the weighted vote, a simple majority of the individual vote is required instead of the two-thirds rule.

The TOs said since the CTOA voting rules were adopted in 2006, there have been “several significant developments” impacting the number of transmission owners in PJM and the type of facilities qualifying a company to become a TO.

“PJM transmission owners assert that the commission’s approval of NERC’s definition of bulk electric system made it possible for small municipal electric systems to be eligible to have their transmission facilities integrated with the PJM region and become PJM transmission owners and thus parties to the CTOA,” FERC said in its order.

The TOs said without changes to the CTOA, the required majority individual vote “could create difficulty” in achieving consensus on tariff changes that “protect the PJM transmission owners’ substantial investment in the PJM transmission system that fairly allocate its costs among their transmission customers.” The TOs also said the CTOA should acknowledge the differing levels of investment among the voting entities, pointing out that more than $67 billion was invested in the PJM transmission system as of the beginning of 2021 with individual TO investments ranging from more than $140,000 to almost $15 billion.

In the proposal, the TOs requested the elimination of the majority individual vote approval “in a situation in which the requirement for a two-thirds vote is not met, but a weighted vote of 95% approves the proposal.” The proposal will leave the 95% weighted vote requirement in the CTOA unchanged.

The TOs also argued that the “proliferation of smaller, non-traditional transmission owners could also frustrate the ability to achieve quorum at TOA-AC meetings and thus the ability of the transmission owners to conduct business.” The proposed CTOA revisions called for a quorum to be present when “either 50% of the PJM transmission owners eligible to vote are in attendance or when PJM transmission owners representing 95% of the weighted vote are in attendance.”

In making its argument regarding voting in ISOs/RTOs, the PJM TOs cited FERC’s decision in 2019 to reject RTO Insider’s bid to force the New England Power Pool to open its meetings to the public and press, saying it lacked authority to act. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)

“The commission found that rules prohibiting press and public access to NEPOOL meetings do not directly affect rates, because they do not affect who may vote on NEPOOL proposals,’” the TOs said in their filing.

Protests

A joint protest was filed in November by AMP Transmission, Old Dominion Electric Cooperative and Silver Run Electric, arguing that the impact of the CTOL changes would “disenfranchise non-traditional transmission owners whenever enough of the large incumbent PJM transmission owners coordinate their votes, as they have done in the past.”

The protesters said the changes would allow a “supermajority” of weighted votes to “override a proposal’s failure to obtain the required share of individual votes” and to “negate” the individual votes of the minority PJM TOs. They also argued that the TOs “fail to identify a single instance” where they were stopped from making a filing under the existing CTOA rules by the non-traditional transmission owners.

“Protesting parties assert that the proposed CTOA changes are unjust and unreasonable because they are premised entirely on speculation that ‘the proliferation of smaller, non-traditional [PJM] transmission owners’ could prevent a filing by larger incumbent PJM transmission owners,” the commission said in its order. “Protesting Parties contend that they have no incentive to block a filing that does not adversely affect their interests and that the existing TOA-AC voting rules already provide sufficient protection to incumbent PJM transmission owners.”

The commission said it disagreed with the argument that the CTOA revisions will disenfranchise the non-traditional PJM transmission owners.

“All PJM transmission owners retain the opportunity to express their views on proposals and to cast a vote,” the commission said in its order. “Furthermore, we find that the proposed revisions rebalance the CTOA voting rules to better align with individual PJM transmission owners’ economic stakes in the transmission system.”

Consenting Commissioners

FERC commissioners Allison Clements and Willie Phillips issued a concurring opinion, saying the revisions were approved by 80% of the individual vote under the current voting rules at the TOA-AC. They said PJM stakeholders also retain the ability to protest Section 205 filings “regardless of size.”

The two commissioners said they had “some concerns” with the voting changes, but they were not great enough to reject the proposal. They specifically pointed to the removal of the individual vote, saying the changes make that vote “irrelevant” when the TOs achieve a 95% or greater weighted vote.

The commissioners said they were also “concerned” that the TOs “failed to adequately respond” to a question in a deficiency letter issued by FERC about whether it was just and reasonable “for a small number of PJM transmission owners with the largest transmission rate base to meet the 95% weighted vote threshold for approving a voting item when a majority of individual PJM transmission owners vote against the item.”

“Instead, the PJM transmission owners dodged the question by revising it,” the commissioners said in the concurrence.

April 6, 2022December 13, 2023

ERO Backs FERC’s Cyber Monitoring Proposal

FERC’s proposal to add internal network security monitoring (INSM) to NERC’s Critical Infrastructure Protection (CIP) reliability standards is an “appropriate approach to address” the growing risk of cyber penetration into secure electronic networks, NERC and the regional entities said last week.

The ERO Enterprise asked to take the lead in the process to implement the commission’s plan (RM22-3).

However, in their comments on FERC’s proposal, NERC and the REs — along with other stakeholders — also warned FERC not to act too quickly on forcing through changes to the CIP standards. One of the commission’s suggestions — to impose INSM on low-impact bulk electric system cyber systems (BCS) — proved especially unpopular, with some respondents urging FERC to drop the idea altogether.

FERC suggested modifying the CIP standards in January, issuing a Notice of Proposed Rulemaking that would add INSM — defined as a set of practices or tools for network visibility including anti-malware, intrusion detection and prevention systems, and firewalls — for high- and medium-impact BCS. (See FERC Proposes New Cybersecurity Standard.) In its order, the commission also called for comments on whether low-impact BCS should be included in the standards effort as well.

The NOPR was prompted by recent cyberattacks in which hackers gained access to the internal networks of target organizations. In particular, commission staff cited the SolarWinds hack of 2020, in which attackers — later identified by the U.S. as officers of Russia’s Foreign Intelligence Service — penetrated the official update channel of SolarWinds’ Orion network management software and distributed malicious code to thousands of public and private sector organizations worldwide.

Staff said the SolarWinds attackers “bypassed all network perimeter-based security controls traditionally used to identify the early phase of an attack” and left the company no way to detect their activities inside the network. They warned that because the CIP standards currently only require a utility to monitor communications from the inside of its electronic security perimeter (ESP) — the electronic border around the internal network to which BCS are connected — to the outside, utilities that do not implement INSM are vulnerable to similar tactics.

Fears About Size, Complexity of Task

In its response, the ERO Enterprise emphasized that it “appreciates the risks identified in the NOPR” and agreed with the idea of incorporating INSM requirements into the CIP standards. Promoting awareness of “components or activities on [utilities’] systems” has been a major focus of the ERO for some time, the comments said, referring to NERC’s previous work with FERC staff on supply chain vendor identification. (See FERC, NERC Offer Cyber Supply Chain Guidance.)

NERC and the REs were not alone in their support, both for the principle that utilities should have insight into their networks and for how the commission hoped to achieve the goal. The ISO/RTO Council (IRC) called INSM “a necessary and valuable security practice,” while the Bonneville Power Administration (BPA) said it “supports the commission in recognizing INSM as an important cybersecurity protection that entities should begin deploying.”

But not all respondents were wholehearted in their approval of the proposal. A group of trade associations, including the Edison Electric Institute, the American Public Power Association, the National Rural Electric Cooperative Association, and the Electric Power Supply Association, said that “INSM holds significant potential” to promote electric reliability, but that the technology faces “significant obstacles” in the near term, mainly that there are currently few subject matter experts “capable of working with the technology,” while the technology itself is also not widely available.

Many commenters were similarly concerned about pushing utilities into investing in technologies or practices that are not yet fully mature. The North American Generator Forum (NAGF) pointed out that “all high and medium BCS are not the same” and said that a network monitoring approach may work on one system but not another. In addition, NAGF warned that encrypted network traffic would be impossible to monitor unless it is all routed through a central location with universal encryption keys. Such a location would inevitably become a “high value target for attackers,” its comment said.

Respondents resisted even more strongly the idea of requiring INSM at low-impact BCS: Idaho Power noted that such systems, “by their very definition,” pose little risk to the BES, and as a result the benefit of implementing network monitoring is likewise small. Similarly, the utility said systems without external routable connectivity (ERC) — whether low- or medium-impact — cannot have INSM installed without also adding ERC. Imposing INSM on these systems may not be worth the cost, particularly since systems without ERC pose far lesser risks for hacking.

This sentiment won many supporters. Even the ERO Enterprise, while supporting “considering” INSM on low-impact systems, said that adding this requirement to the CIP standards would require “extensive revisions” because the standards don’t currently define low-impact BCS. BPA went further, arguing that any mandate for internal network monitoring should apply only to high-impact systems, at least initially, with application to medium-impact systems — only those with ERC, for reasons similar to Idaho Power’s — coming later.

All respondents urged FERC not to move too quickly in forcing INSM on utilities, considering the cutting-edge nature of the technology. NERC and the REs suggested that the commission “defer to NERC regarding the timeline for any standards development” due to the “complex considerations” faced by the ERO and industry stakeholders.

“While the ERO Enterprise intends to act expeditiously to support any directed standards revisions, [it] respectfully requests the Commission not impose deadlines that could hamper thoughtful deliberations on technical considerations, scalability and manageability for responsible entities of all sizes, and whether any further implementation requirements may be necessary,” the ERO said.