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December 9, 2022

PacifiCorp to Join EDAM, Final Plan Released

PacifiCorp on Thursday became the first Western utility to commit to joining CAISO’s proposed extended day-ahead market (EDAM) for its real-time Western Energy Imbalance Market, assuming the market design wins approval next year.

“With this important and timely announcement, we are hopeful that many of our other valued partners across the West will join PacifiCorp in positioning the EDAM as the next major step in Western market integration,” CAISO CEO Elliot Mainzer said in a statement.

PacifiCorp helped design the WEIM and joined as its first member in 2014. The market now includes 19 participants and has generated more than $3 billion in economic benefits, including $500 million for PacifiCorp, which has also helped design the EDAM.

“This next step to a day-ahead market is another game-changer to increase the triple benefit to our customers of cost reductions, increased reliability and reduced emissions,” Pacific Power CEO Stefan Bird said in a news release. Pacific Power is the PacifiCorp division that serves customers in Oregon, Washington and a small part of California.

The news of PacifiCorp’s commitment came a day after CAISO issued a final proposal for the EDAM that it plans to present to its Board of Governors and the WEIM Governing Body on Dec. 14. Both governing boards are scheduled to vote on the plan in February. FERC approval would be next.

The final proposal makes changes to the draft final plan published Oct. 31. They include clarifications and enhancements that respond to stakeholder comments.

Transmission commitment has been a thorny topic in the EDAM planning effort, which CAISO fast-tracked starting late last year.

“Availability of transmission to the market is critical for efficient transfers of supply across the EDAM footprint to serve load and maintain grid reliability,” the plan says.

Stakeholders have had questions and concerns about what, exactly, transmission availability and commitment mean in the EDAM design.

“The final proposal clarifies, in response to stakeholder comments, the transmission requirement for resource participation in the market,” it says. “In particular, the final proposal clarifies that a resource must be a designated network resource under the terms of the Open Access Transmission Tariff, have reserved firm point-to-point transmission (of any duration), or have a legacy transmission contract.

“If transmission has not been reserved, the resource would nevertheless be able to participate in the market and the EDAM entity transmission provider would assess a charge for using transmission based on the rate for the lowest duration of firm point to point transmission service established by the OATT.”

The final proposal also introduces two enhancements to proposed transmission availability rules.

It “enables eligibility for historical revenue recovery associated with historical sales of monthly firm and non-firm point, in addition to the already eligible weekly, daily and hourly transmission products.” And it clarifies the “treatment of, and the ability to exercise, transmission rights between an EDAM balancing area and a non-EDAM balancing area to support continued service to load and meeting obligations under existing or emerging programs around the West.”

The Western Power Pool is moving forward on its Western Resource Adequacy Program. Stakeholders have raised question about how that program’s requirements might clash with the EDAM’s rules. PacifiCorp and 10 other utilities said Thursday they intend to join the WRAP.

Resource Sufficiency Tweaked

Another sticking point has been the plan for a resource sufficiency evaluation (RSE) to keep participants from leaning on the EDAM to serve unmet internal load. How resources will be counted and penalties for failing the RSE have worried some stakeholders. (See CAISO Tackles EDAM Design in Stakeholder Meeting.)

The final proposal tries to ensure that demand response, as a resource, is “accurately captured and tracked.” It details how generation-only balancing areas will be treated in the RSE. And it retains the consequences for failing the RSE outlined in prior versions but clarifies the proposed surcharges for failing the test.

The final plan further modifies the EDAM design by allowing participants to elect whether to allow convergence bidding within their balancing area after they join and removes a “mandatory transition to convergence bidding after one year of participation” contained in earlier drafts.

“The ISO will further evaluate and derive a more permanent EDAM convergence bidding policy leading up to the two-year anniversary of EDAM operation,” it says. “The stakeholder process will permit for consideration of EDAM operational experience and EDAM entity readiness in deriving the convergence bidding policy design.”

CAISO has promoted the EDAM this year as an effort to bring greater cooperation to the balkanized Western Interconnection, which has more than three dozen balancing authorities.

SPP has been trying to do the same with its planned Markets+ day-ahead offering, which would eventually subsume participants in its real-time Western Energy Imbalance Service. The WEIS has had limited success competing with CAISO.

SPP, however, also plans to launch a Western edition of its Eastern RTO, called RTO West. Utilities in Rocky Mountain states have indicated interest in joining SPP, which has a reputation for including voices from multiple and varied regions of the South, Midwest and Great Plains states.

Legislative efforts to expand CAISO’s governance to include members from other states have been unsuccessful in the past, but increased competition and studies that have shown up to $2 billion in annual benefits from a Western RTO might help sway lawmakers. A California Assembly resolution passed last year asks CAISO to prepare a report on recent market studies for the Legislature when it reconvenes in early 2023.

December 9, 2022

Va. Air Panel Votes to Exit RGGI

Acting on a promise by Gov. Glenn Youngkin (R), the Virginia Air Pollution Control Board voted Wednesday to withdraw from the Regional Greenhouse Gas Initiative (RGGI), an action likely to result in legal challenges.

The board voted 4-1 to approve a proposed regulation allowing Virginia’s exit from the 11-state cap-and-trade program, which it joined after the General Assembly mandated participation in 2020 (SB 1027). After a review of the proposed regulation by the executive branch, it will be published in the Virginia Register of Regulations with a 60-day public comment period.

In January, Youngkin issued an executive order requiring the Department of Environmental Quality to proceed with the withdrawal. The DEQ is required to consider public comments before writing a final regulatory proposal.

“With the board’s decision to proceed to public comment, we are one step closer to exiting RGGI and bringing relief to ratepayers,” said acting Secretary of Natural and Historic Resources Travis Voyles, who presented the proposal.

Youngkin’s four appointees to the air board supported the repeal. Three members named by former Gov. Ralph Northam (D) balked, with one voting “no” and two abstaining, saying it would require legislative approval to withdraw.

In a report in March, the Youngkin administration called RGGI a “direct carbon tax” on residents and businesses, saying that none of the $300 million the state has received to date is being used to provide rebates to customers. (See Youngkin Report: RGGI a ‘Direct Carbon Tax’ on Va. Ratepayers.)

The air board’s vote was denounced by environmental groups.

“Participation in RGGI is a commonsense policy that reduces air pollution, keeps us on track to meet our climate goals, and provides necessary funding to address the flooding we see today and that we know will get worse in the coming years,” said Victoria Higgins, Virginia director for Chesapeake Climate Action Network. “Because of RGGI’s overwhelming public support, Youngkin failed to repeal this popular policy through the legislature. It is appalling that the governor has now turned to using unelected members of a citizen board to enact his extremist agenda. This transparently undemocratic and illegitimate attempt at repeal reveals the lengths to which Youngkin will go to drag Virginia backwards on climate.”

Nate Benforado, a senior attorney in the Southern Environmental Law Center, also questioned the board’s authority.

“The administration continues to march down this repeal path despite the fact it has no such authority to repeal this regulation,” he said. “The law requires Virginia’s participation in RGGI, and the administration must abide by the General Assembly’s decision. But equally troubling is the fact that the administration appears uninterested in listening to its own residents. The public overwhelmingly opposed this action, but the administration is poised to plow through this irresponsible and unlawful repeal, no matter what people say and no matter the harm to Virginia.”

December 9, 2022March 20, 2024

GridCONNEXT Digs into Grid-Telecom Convergence

WASHINGTON — The convergence of the electric grid and telecommunications system is inevitable, critical and underway, according to Commonwealth Edison (NASDAQ:EXC) CEO Gil Quiniones.

“There are a lot more intelligent devices that are installed on the grid, aside from integrating renewables, wind [and] solar,” Quinones told an audience of grid professionals at the gridCONNEXT conference, sponsored by the GridWise Alliance. “There are a lot of smart switches, voltage-optimization devices and other systems that are on the grid. Plus, our customers are having more intelligent building electrical systems. So how do you orchestrate [that]? That can only happen when there’s convergence between telecom and the power grid.

“We really need a new operating system and a new set of application software,” Quiniones said. “That’s starting to happen now, but we need to enable the technology.”

Convergence was a key theme at the two-day conference, with panels on Monday digging into the current state of the interfacing of grid and telecom, and utility information technology and operational technology systems.

“A smart grid needs smart communications,” said Chris Guttman-McCabe, chief regulatory and communications officer at Anterix (NASDAQ:ATEX), a broadband company focused on the utility sector. “What we’re seeing is an absolute necessity for broadband by utilities” to respond to a range of new challenges, from cyber and physical security, to the aggressive decarbonization and environmental justice goals a growing number of electric utilities are adopting.

Like Quiniones, he sees a core “need to rethink everything within your purview, including your communications platform.”

Systems convergence is part of the digitization of the grid that has accompanied its transformation from a one-directional system — “generation, transmission, distribution to load,” as Quiniones said — to a bidirectional system, in which the customer meter is an increasingly permeable interface.

ComEd has been “layering fiber on top” of its power system, Quiniones said. “We’re going to be able to control the devices that we have in place, and we’re doubling down on that, in combination with a wireless network. It’s probably the right business model for us and utilities going forward.

“It is important because there has to be system awareness and visibility; situational awareness and visibility,” he said. “There needs to be very fast communication and switching. All those devices need to talk to each other in milliseconds.”

“It’s also a way for us to isolate faults. If there are outages, we can quickly isolate them and keep many of our customers up and running,” he said.

Anterix has developed an ecosystem of software and applications developers working to integrate and leverage communications systems on the grid. One of its partners, Schweitzer Engineering Laboratories, has developed a system that can “de-energize a broken line before it hits the ground,” Guttman-McCabe said. “That capability wasn’t usable until it was integrated with high-speed, low-latency, dedicated broadband.”

Communications systems have also been an essential part of ComEd’s Bronzeville microgrid project, a community-level microgrid that can island from ComEd’s distribution system in an emergency and trade or share power with another microgrid at the Illinois Institute of Technology.

Such projects “need very fast sampling and time-synchronized decision-making,” Quiniones said. “When we integrate more renewables, when we have more electric vehicle charging stations, when we have more heat pumps [and] hot water heaters that are all going to have devices embedded in them that can communicate with the grid, you need a very robust communications system.”

A Safe Place to Innovate

Similarly, Justin Driscoll, interim president and CEO of the New York Power Authority, sees IT/OT convergence as integral to hitting New York’s aggressive decarbonization goals, such as cutting the state’s greenhouse gas emissions 85% by 2050.

“The integration of information technology systems and big data analytics are systematically allowing the digital information world to see, understand and influence the physical, operational world,” Driscoll said in his opening remarks at Monday’s second convergence-themed panel. “When implemented properly, IT/OT convergence can merge business processes, insights and controls into a single, uniform environment by allowing different technologies to integrate and interoperate efficiently as a single, cohesive system. …

“NYPA will take full advantage of technology and advanced analytics from the generator to the end user,” he said. “And this journey enables NYPA and its customers to leverage the full potential of an advanced technology environment in every aspect of the utility industry value chain.”

One example is NYPA’s “enterprise-wide Cybersecurity Awareness Program that spans both IT and OT environments to ensure that cybersecurity is baked into the culture of everything we do,” Driscoll said.

Adrienne Lotto, senior vice president for grid security, technical and operations services at the American Public Power Association, said IT/OT convergence has been an “ongoing journey” for the past decade. Drivers include the changing generation portfolio, integration of distributed energy resources and the evolution of utility business models, she said.

“The business is changing, and as a result we need more and more data about our operating efficiency, creating the controls, understanding the data points and then responding in a coordinated response perspective,” Lotto said.

Looking at the challenges ahead, Lotto said, “All of these data points have data that is feeding into the utility, and how are we going to manage all of that? How are we going to standardize all of that? How do we run analytics to solve all that, and how do we understand all that while our [industry] is growing, changing and advancing?”

Coming from the IT side, Russell Boyer, energy field director for Dell Technologies, said the goal going forward is to create standard or common platforms “that can take that data and turn it into insights so that we can accelerate” progress toward industry targets.

The challenges he sees are the different skillsets of workers on both the IT and OT sides, who historically have not worked together on a regular basis and may be resistant to learning new skills and processes.

“You’ve got to figure out how to create a safe place to do innovation,” Boyer said. “So that everybody [is] on board, all the stakeholders get together and start doing some testing so that they can understand what this process is going to deliver so that they can get to the buy-in and get on board and ultimately be a part of that solution and the innovation that needs to occur.”

A Different Digital Divide

The digitization of the grid has also opened up a new digital divide, said GridWise CEO Wayland. “For me, it’s bigger than internet access,” she said. “It’s about access to the grid that allows the customer to interact with the grid and allows the customer to understand their energy use” and even use their own DERs to participate in wholesale markets under FERC Order 2222.

Bridging that divide was one reason GridWise pushed hard to have funding for broadband expansion included in the Infrastructure Investment and Jobs Act. “The idea that communications are central to the grid and should be part of that infrastructure was not well understood” in Congress, she said.

Of the $65 billion for broadband in the bill, $1 billion is dedicated to “middle-mile” infrastructure, which helps to connect small or remote communities to larger broadband networks. Utilities, and in particular electric cooperatives, are eligible to apply for the middle-mile funds.

In Illinois, the passage of the Climate and Equitable Jobs Act last year means ComEd is planning its system by “what’s best for disadvantaged and underserved communities,” Quiniones said.

The utility has been deploying its own fiber networks to help ensure service to remote and underserved communities, and leasing out excess capacity to internet service providers, which can then provide “last-mile” connectivity, he said.

“We’ve actually applied [for] IIJA funding to kind of accelerate our deployment,” Quiniones said. “It’s beyond broadband. We want to make sure that our customers have access to all the other clean energy technologies that are going to be deployed, whether they are DERs or electric vehicle charging stations or just resiliency and reliability.”

Anterix sees broadband as a versatile “Swiss Army knife” for the grid, Guttman-McCabe said. It is “an underpinning for everything that any utility is facing: the need to aggregate and act upon data, the need to be more equitable with [the] distribution of energy opportunities and offerings … the need to bake in cybersecurity instead of bolting it onto your existing, antiquated communications systems,” he said.

“As a utility begins to contemplate digitization of their grid and all the sensors that are there, all of a sudden you can start to recognize cloud-based computing, machine learning and artificial intelligence, virtual augmented reality,” Guttman-McCabe said. “And with that comes an incredible range of opportunities for the utility, for customers, for rapid evolution of distributed energy resources.”

December 9, 2022June 14, 2023

MISO Staff Preview New LRTP Projects with Board

ORLANDO, Fla. — MISO staff on Tuesday gave their board a first look at its concept map of proposed projects under the second phase of its long-range transmission plan (LRTP), saying the new portfolio could cost up to $30 billion.

Stakeholders reacted with disbelief over the portfolio’s possible magnitude when MISO transmission planners unveiled the map last week. (See ‘Conceptual’ Tx Planning Map Troubles MISO Members.)

Aubrey Johnson, vice president of system planning, said the grid operator isn’t “married to” the hypothetical network of 345-kV and 765 kV-lines and an HVDC line across Lake Michigan, but engineers “needed a place to begin work from.”

MISO’s MTEP 22 report cover | MISO

“This is an initial draft,” he said Tuesday during the board’s System Planning Committee meeting. “We view this as a directional starting point.”

Johnson reminded board members that in early 2021, staff warned them that it could require up to $100 billion in new transmission over the next few years for members to achieve their renewable generation additions and carbon-cutting goals. They said the first LRTP, based on the most conservative transmission planning future, could cost up to $30 billion. However, the resulting portfolio cost a little more than $10 billion. (See MISO Board Approves $10B in Long-range Tx Projects.)

“The billion-dollar question, I’m sure, is what it might take. This [portfolio] could be anywhere from $20 to $30 billion to achieve what we think is necessary” under MISO’s moderate second planning future, Johnson said.

Board members worried aloud that the RTO isn’t refreshing its future load assumptions as often as it does with generation predictions.

Alliant Energy’s Mitch Myhre, representing transmission-dependent utilities, said his sector was alarmed by the second LRTP portfolio’s potential scope and cost. He said MISO should consider non-transmission alternatives, synchronous condensers, and other transmission-enhancing technologies under the second LRTP plan.

Southern Renewable Energy Association’s Andy Kowalczyk asked MISO leadership and board members to consider moving up LRTP planning for MISO South. The grid operator is looking at the Midwest region in the first two of four LRTP portfolios.

MISO’s 2022 interconnection queue cycle currently holds 956 generation project submissions totaling 171 GW. More than 96% of those projects are renewable or storage. (See MISO Insists it can Handle Record-setting Interconnection Queue.)

“What sets this year apart is just the record number of requests,” MISO’s Andy Witmeier said.

The project submittals are a 128% increase over 2021’s 77 GW of nameplate capacity submissions. Witmeier said that the Inflation Reduction Act’s approval and MISO’s first LRTP portfolio spurred the increase in generation plans.

MISO has released the first two requests for proposals associated with its first LRTP portfolio: a 345-kV line on the Indiana-Michigan state border and the Denny-to-Fairport 345-kV on the Iowa-Missouri border.

MTEP 22 Winds Down

Board members on Thursday unanimously cleared the way for work to begin on MISO’s $4.3 billion, 382-project 2022 Transmission Expansion Plan (MTEP 22). (See MISO’s $4B MTEP 22 Clears 1st Board Vote Despite Criticisms.)

No members took advantage of a public comment period before the vote on the annual plan.

Since MTEP 03, $32 billion in transmission investment has gone into service; another $23 billion remains under development, including the first LRTP.

With MTEP 22 in the rearview mirror, expedited project submittals under MTEP 23 are already accumulating.

Entergy submitted two expedited review projects for MTEP 23 before MTEP 22 was formally approved. MISO found no harm in Entergy Texas’s work on two 138-kV substations in East Texas to accommodate industrial load growth. The utility will commence with a customer’s new, $28 million substation and $10 million in upgrades to another substation, adding a 12 MW load capability and 25.1 MVAr capacitor bank.

December 9, 2022June 14, 2023

Duke Completes Power Restoration After NC Substation Attack

Duke Energy (NYSE:DUK) has completed restoration efforts for the 45,000 customers in Moore County, N.C., who lost power over the weekend after unknown attackers damaged two substations with rifles, and the utility is now offering up to $25,000 to help catch those responsible, it said in a statement on Thursday.

The state and county have each matched Duke’s offer, according to a statement North Carolina Gov. Roy Cooper released on Wednesday, meaning that up to $75,000 are available for information leading to the culprits’ arrest. Meanwhile, the FBI also issued a release seeking information on the incident.

The restoration went more quickly than expected; on Monday, Duke was still estimating that it would need until Thursday to bring all customers back online. (See Duke: NC Outages from Attacks May Last Until Thursday.) Duke spokesperson Jeff Brooks told RTO Insider in an email that service was restored “to all customers capable of receiving power” by 6 p.m. Wednesday, more than 24 hours earlier than anticipated.

But as Moore County’s government and businesses returned to normal Wednesday night, the threat of violence against the bulk power system remained on investigators’ minds after shots were fired near Duke’s Wateree Hydro Station in Ridgeway, S.C. According to the incident report by the Kershaw County Sheriff’s Office, Duke employees working outside the facility heard shots fired ab 4:30 p.m.; they then saw a car driving away with a man hanging out the window holding a rifle.

Duke Energy substations (FBI) Content.jpg

The Duke Energy substations in Carthage (left) and West End, N.C., that unidentified attackers shot on Dec. 3, leading to the loss of power for around 45,000 customers in Moore County. | FBI

Deputies reported finding shell casings on the road, but in an area where the hydro plant could not be seen. When they went farther down the road in the direction the employees said the car had driven from, the plant was “extremely visible and easily accessible,” but no shell casings were found in this area.

The Sheriff’s Office said that it is conducting a joint investigation with the State Law Enforcement Division and the FBI in light of the Moore County incident. However, Sheriff Lee Boan emphasized that police currently have “no reason to believe this shooting incident has anything to do with an attack on the hydro station.”

Duke said that no injuries or property damage are known to have occurred from the Ridgeway shooting, and no outages were reported either. The utility said it is cooperating “closely” with the FBI on the investigation and “will leave it to investigators to classify or compare the nature of the incident at this time.”

No Culprits Identified in NC Outages

The Moore County outages began around 7 p.m. Saturday night near the town of Carthage and quickly spread through most of the county. Sheriff’s deputies and Duke personnel discovered “extensive damage” to two substations caused by multiple shots from firearms; the FBI on Thursday identified the substations as being located in Carthage and West End, about 10 miles apart; one resident living near the West End substation told local media he heard about 20 shots that night.

As of Thursday law enforcement officials had reported no suspects in the North Carolina attacks. Investigators are reportedly focusing on bullets and casings found near the substations in hopes of identifying the types of rifles used.

Brooks said Duke is aware that the outages have been “challenging [and] unsettling” for the utility’s customers. He emphasized that Duke maintains “multiple layers of physical and electronic security, as well as people and processes that work together to … restore power when disruptions occur.”

“Security is an evolutionary process, and we are always working to improve our strategy and stay ahead of the next threat, whether it be weather, physical or cyber in nature,” Brooks added. “We will take learnings from this incident and apply it to our security strategy going forward. And our ongoing grid improvement strategy focuses heavily on strengthening the grid to make it more resistant to outages, and more resilient through the use of automated restoration processes, self-healing technology and a comprehensive outage response plan, to restore power faster when disruptions occur.”

December 9, 2022

MISO System Operations ‘Uneventful’ During Fall

ORLANDO, Fla. — MISO said its system encountered “moderate fall weather that produced minimal operating challenges” this year, encountering rough patches only when unseasonably warm weather clashed with the generator maintenance season.

“The beauty of this fall is that it was wholly uneventful,” J.T. Smith, the RTO’s executive director of market operations, told the Board of Directors during a Markets Committee meeting Tuesday.

Demand averaged 71 GW during the season, peaking at 107 GW. MISO averaged 72 GW during the fall of 2021 and had a 98-GW peak.

The grid operator has gone more than a year without a maximum generation event. In October, it was forced to issue a capacity advisory and order conservative operations for its South region when maintenance outages dovetailed with a late heat wave. It also issued a capacity advisory and hot weather alert in September for its Central region.

MISO’s generation fleet, much of it aging thermal resources, averaged about 53 GW of daily derates and planned and unplanned during the season. That was in line with last year’s average of 54 GW. The grid operator has a little more than 160 GW in accredited capacity.

MISO set a record for wind output at 24.2 GW in late, blowing past the earlier mark of 23.6 GW recorded in January.

Smith said staff continues to work on its unit commitment process by improving its optimal dispatch calculator. Independent Market Monitor David Patton has said MISO often made resource commitments that appear unnecessary during the year.

The grid operator is anticipating a 102-GW system peak in January under typical winter conditions. That would jump to 109 GW should an arctic blast descend on the footprint. (See MISO: Diminished Emergency Possibilities this Winter.)

A January cold snap may have MISO “leaning on imports or walking into” emergency steps to call up its load-modifying resources, Smith said. He predicted active winter storm patterns in Michigan, Indiana, Ohio and Illinois that could potentially ice over transmission lines and wind turbines.

Smith said staff continues to monitor developments on the nation’s railway system, even after Congress averted a rail strike last week. He said coal production and deliveries remain strained and that an unstable supply chain of chemicals to scrub emissions is also a point of concern.

Director Nancy Lange observed that she wasn’t hearing members’ anxiety or the urgent fuel supply warnings MISO issued ahead of last winter.

“We are seeing less conservation of coal right now, indicating [operators] are more comfortable with their current supplies,” Smith said. “I’m not as concerned as I was last year over procurement.”

Patton agreed that coal conservation is ebbing across the footprint as winter approaches, signaling confidence in fuel supplies.

During a Technology Committee meeting Tuesday, staff reported they encountered a software defect in September that caused a process to fail within its energy management system. They said the defect was caused by too many input constraints, exceeding system capacity, and MISO was forced to transfer critical systems to its backup data center. The vendor managing the software has since come up with a patch to increase the software’s constraint capacity, the RTO said.

December 8, 2022June 14, 2023

FERC-DOE Technical Conference Considers New Standards for Supply Chain Threats

WASHINGTON — Cybersecurity threats in the supply chain have evolved since FERC directed NERC to develop standards covering them in 2016, but there was no consensus on whether the rules need to be updated at a technical conference Wednesday.

FERC and the Department of Energy jointly hosted the event at the commission’s headquarters, just days after a physical attack on two Duke Energy (NYSE:DUK) substations in North Carolina. (See Duke: NC Outages from Attacks May Last Until Thursday.)

Puesh Kumar, director of DOE’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER) | FERC

“As we saw last weekend in North Carolina, this isn’t really necessarily an academic exercise, it’s a real exercise,” FERC Chairman Richard Glick said. “There are people out there, whether they be people here in the United States or people around the world, obviously governments and so on, that are out there trying to do damage to the grid.”

Glick expressed support for new critical infrastructure protection (CIP) standards, saying the supply chain threat has evolved and become more serious over time. FERC approved NERC’s supply chain standard in 2018, with updates in 2021. (See FERC OKs Updated Supply Chain Standards.)

Puesh Kumar, director of DOE’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER), said cyber threats are compounding supply chain challenges “from COVID and where the global economy is right now.”

Counterintelligence officials have seen an increase in the number of attacks coming from the supply chain, said Jeanette McMillian, assistant director for the Supply Chain and Cyber Directorate of the National Counterintelligence and Security Center. Her office, which falls under the Director of National Intelligence, oversees providing outreach to private sector entities that are at risk from foreign intelligence operations.

Jeanette McMillian, National Counterintelligence and Security Center | FERC

The threats can hide in the “noise of the supply chain,” whether it is operating normally like in the SolarWinds attack in 2020, or in the chaos of cyberattacks, said McMillian.

Thousands of federal and private systems were breached when they updated SolarWinds’ Orion network management software after it was hit by a Trojan horse-style attack by suspected Russian hackers, according to the Government Accountability Office.

While new standards generally involve responding to past incidents, McMillian said her office can be more proactive by sharing information on the latest threats through DOE and other agencies that work with critical infrastructure.

Manny Cancel, CEO of NERC’s Electricity Information Sharing and Analysis Center (E-ISAC) | FERC

The federal government has increased information sharing in recent years as barriers have been lowered, said NERC Senior Vice President Manny Cancel, the CEO of the Electricity Information Sharing and Analysis Center. But mandatory CIP standards have also helped ensure that the industry has a good baseline of security.

“The CIP standards help a great deal in terms of protecting us,” Cancel said. “When you go back to the SolarWinds compromise … there really was no compromise in the electricity sector. I think a lot of that had to do with some of the protections we put in place with the NERC CIP standards.”

One area that needs to be looked at is how the standards should be applied to different classes of assets, he added. They have different levels of protection for high, medium and low risk assets.

Glick questioned whether those three categories should be scrapped, noting that a cyberattack could originate at a lower risk site and spread to infrastructure that has a much bigger impact on the grid.

Mara Winn, deputy director of DOE’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER) | FERC

“You have to assume at this point that something is going to go wrong,” said CESER Deputy Director Mara Winn. “Whether it is a natural disaster, whether it is a direct attack, something will go wrong. And making sure you spend the time in advance to really analyze that resiliency planning [is important] so that you can prioritize.”

The interconnectivity between lower risk systems and higher risk ones needs to be analyzed to ensure that it does not lead to major, cascading problems, she added.

Some value exists in classifying assets by their risk profiles, but because of the hyperconnectivity in cyberspace the spread of risks from lower profile systems is inevitable, said Marty Edwards, deputy chief technical officer for cybersecurity firm Tenable.

“I think what we need to take a look at is having a certain baseline standard of care that applies across the board and then look at [whether] you have to embellish it in some of the higher criticality implementations,” he said.

Marty Edwards, Tenable | FERC

While cybersecurity issues in the supply chain and elsewhere are constantly evolving, several power industry witnesses argued FERC and NERC should not be overly prescriptive in any future standards.

“We know that the standard development process is not a rapid, overnight process,” said Jeffrey Sweet, director of security assessments for American Electric Power (NASDAQ:AEP). “It takes time, and so we have to have that flexibility to be able to respond to the threats that we’re seeing every day. And I believe the standards give us that flexibility.”

Industry responsiveness to those standards could be improved through other ways, such as the cybersecurity incentive policy proposed by FERC in September, he said. (See FERC Reluctantly Proposes Cybersecurity Incentives.)

“Are the standards sufficient? Yes, they are,” said Edison Electric Institute Senior Vice President of Security and Preparedness Scott Aaronson. “They create a very solid foundation on which we can ensure there is a minimum baseline level of security.”

But the industry needs to go above and beyond the standards to protect high risk assets, Aaronson said. That includes ensuring resilience of the power system so it can quickly bounce back from any attacks that do succeed, he said.

Jeffrey Sweet, AEP | FERC

“I think that absolutely we need to consider updating the reliability standards we talked about earlier as they relate to the supply chain,” said Glick. “Clearly, things have changed, and we need to act more quickly. I know that the NERC standards process doesn’t necessarily lead to acting quickly, but it’s important that we start considering that now.”

In an afternoon session, Dick Brooks, co-founder and lead software engineer for Reliable Energy Analytics, cautioned against new standards, saying the industry already faces a “tsunami” from the Office of Management and Budget’s memorandum M-22-18 on federal agencies’ software supply chain risk management and the Cyber Incident Reporting for Critical Infrastructure Act of 2022, which requires entities in energy and other critical infrastructures to notify CISA of cyber incidents and ransomware payments within 72 hours.

“It would be a good time to consider … what’s coming out of that before we initiate any new standards development.” Brooks said. “Because we wouldn’t want to take the risk of going down one path and finding out that this new law is really sending us in a different direction.”

December 8, 2022December 12, 2023

NERC RSTC Briefs: Dec. 6-7, 2022

Members Approve IRPS SARs

At its final meeting of 2022, NERC’s Reliability and Security Technical Committee (RSTC) voted to endorse two standard authorization requests (SAR) focused on inverter-based resources (IBR), while calling for comments on two more SARs focused on distributed energy resources (DER).

The first two SARs originated in NERC’s Inverter-based Resources Performance Subcommittee (IRPS), which submitted them for comment at the RSTC’s last meeting in September. With the full committee’s endorsement, the SARs — modified in response to members’ feedback — will be sent to NERC’s Standards Committee for approval so that work can begin on the standards.

One SAR would update reliability standard EOP-004-4 (Event Reporting), which identifies the events that utilities must report to regional entities or other responsible authorities. The IRPS identified the standard as having “relatively large generator loss size thresholds” that could leave IBR-related events unreported, as well as “language more suitable for synchronous generation.” The new SAR proposes to lower the generator loss threshold and clarify the language to include IBRs as well.

For the other SAR, IRPS proposed to create a new standard that would require generator owners (GO) to “identify, analyze, and develop mitigations for any abnormal performance issues identified,” while creating requirements for GOs’ mitigation plans to meet. The new standard would also give balancing authorities and reliability coordinators the ability to identify potential issues using their own monitoring capabilities.

The SPIDERWG’s SARs are at an earlier stage of development and not ready for submission to the Standards Committee, the working group’s chair Shayan Rizvi told the RSTC. They would modify FAC-001-4 (Facility Interconnection Requirements) and FAC-002-4 (Facility Interconnection Studies) to require more consideration of potential reliability impacts from DERs before they are integrated to the bulk power system. The SARs will be open for comment by RSTC members through Jan. 13, 2023.

SPIDERWG also brought a reliability guideline for developing parameters for NERC’s DER_A model, as well as a white paper on battery energy storage systems and how they can be incorporated into DER models. The RSTC approved both measures.

White Paper Sparks Debate

Another white paper — this one related to cybersecurity for DERs — led to a lengthy debate as members suggested one of its recommendations was not appropriate for the setting.

The white paper aimed to provide guidance to industry on cybersecurity for DERs and DER aggregators, including suggestions for “certification and standards support” by industry. But several attendees pushed back against a recommendation that the RSTC and its stakeholder groups “identify possible reliability and security risks these entities could pose if compromised.”

Kayla Messamore of Evergy pointed out that “there’s a lot of activity ongoing in that space already,” and questioned whether the recommendation would lead to confusion among industry stakeholders trying to navigate a complex topic. Dominion Energy’s Sean Bodkin added that while there was merit to the recommendation, it should be made in another venue.

“I think … we need to get out in front of [this], but I also have to agree with what Kayla said, that this is not the appropriate place to do it,” Bodkin said. “This is a technical document, not a document about registration or about getting out in front of what would be a NERC initiative to change the registration criteria.”

However, an amendment to strip the controversial language from the white paper failed, and the document received the RSTC’s approval as originally written.

Future Meetings

Despite the committee’s recent return to in-person meetings — the September event was held at the Midwest Reliability Organization’s offices in Minnesota — RSTC leadership announced that most of next year’s meetings will be virtual in some form. (See NERC RSTC Briefs: Sept. 13-14, 2022.)

At a recent meeting of the RSTC executive committee, leaders decided that only the first meeting of 2023 will be fully in-person, Secretary Stephen Crutchfield told participants. That gathering will occur March 21-23. The location is yet to be finalized, but Crutchfield said management aims to hold it in Tampa, Florida. NERC’s headquarters in Atlanta will serve as a backup.

For the June 20-22 meeting, the RSTC will gather at the MRO offices again for a hybrid session in which only members will meet in person, with other observers attending virtually. The committee’s Sept. 19-21 meeting will follow the same format, while the final meeting of the year Dec. 6-7 will be entirely virtual. The March, June and September sessions will be three days long because of the inclusion of an informational session on the first day.

The RSTC’s meeting plan for next year is similar to that of NERC’s Board of Trustees, which announced at its most recent meeting in November that it would hold only two in-person meetings next year, with the others to be either hybrid or fully virtual. (See “Board Makes Meeting Changes Official,” NERC Board of Trustees/MRC Briefs: Nov. 15-16, 2022.) NERC management said the schedule is intended to reduce the cost of attending meetings for stakeholders.

December 8, 2022December 31, 2023

Biden Orders Cut to Federal Building Emissions

The White House Council on Environmental Quality on Wednesday issued a federal building performance standard requiring agencies to cut energy use and electrify equipment and appliances in 30% of their building space by 2030.

The Department of Energy simultaneously proposed new standards limiting on-site emissions from new and newly renovated federal properties. Beginning in 2025, new buildings and buildings undergoing major renovations would have to limit emissions to 90% of those recorded at federal properties in 2003.

The federal government owns 300,000 buildings.

The new rules come one year after President Biden issued an executive order announcing the goal to achieve federal energy sustainability while jumpstarting clean energy industries.

The administration’s long-term target is to achieve net-zero emissions at all federal buildings by 2045, cutting carbon dioxide emissions by 1.86 million tons and methane emissions by 22,800 tons.

“Ridding pollution from our buildings and adopting clean electricity are some of the most cost-effective and future-oriented solutions we have to combat climate change,” Energy Secretary Jennifer Granholm said in a release. “For the first time ever, DOE is establishing a firm timetable to reduce the government’s carbon footprint in new and existing federal facilities — ensuring the Biden-Harris administration is leading by example in the effort to reach the nation’s ambitious climate goals.”

DOE will solicit comments on its proposal in the coming weeks and will host a webinar on Jan. 5 explaining in greater detail the scope of the rule and proposed timeline.

December 8, 2022

ERCOT Opens Curtailment Program to Crypto Load

ERCOT has created a voluntary curtailment program for bitcoin miners and other large flexible loads that it says will reduce power use during periods of high demand, even as the cryptocurrency industry shows signs of an implosion.

The grid operator said the curtailment program is primarily intended for large flexible customers, but any large customer directly connected to a transmission service provider’s facility can participate, subject to approval by ERCOT. Registration began Tuesday and the program is expected to go live in January.

The program is temporary until ERCOT establishes a long-term set of rules of for the large loads. The grid operator created a Large Flexible Load Task Force earlier this year to develop policy recommendations to integrate the loads. The group has been considering policies related to planning, markets, operations, and large load interconnection processes and reviewing related market rules.

Woody Rickerson, ERCOT vice president of system planning, said the goal is to work with large customers to support system reliability.

“These customers are large power users but have the flexibility and willingness to reduce their energy use quickly, if needed,” Rickerson said in a press release.

Under the program, ERCOT will request curtailment of crypto mining consumption when physical responsive capability declines after non-spinning reserve service has been deployed, but before emergency response service is called on.

Program participants will not be considered market participants and are subject to the grid operator’s confirmation. ERCOT said it will not refer participants to the Public Utility Commission if they fail to comply with any curtailment request under the program.

ERCOT currently has about 1.5 GW of crypto mining load and said in August it was studying 17 GW of load from the sector. By November, 37 GW of crypto load were requesting to be interconnected. (See “Staff Studying 17 GW of Crypto Load,” ERCOT Board of Directors Briefs: Aug. 16, 2022.)

“Not all of that will be constructed, but the challenge is how much will be there in three to four years,” Jeff Billo, ERCOT director of operations planning, told the grid operator’s Board of Directors in August.

Texas Gov. Greg Abbott and former interim CEO Brad Jones have both welcomed miners with open arms, pointing to their ability to quickly shut down should ERCOT need their capacity to meet demand. Jones said earlier this year that crypto offers a “fantastic” resource and said miners are effective in balancing supply and demand.

“We need to work with these folks to bring them in,” Jones told the Gulf Coast Power Association in April. At the time, he expected ERCOT’s crypto load to reach 5 GW in two years.

“I see that as a positive, but we’ve got to think about some policy issues,” he said. (See “Jones: Will Stay as Interim CEO,” Overheard at GCPA’s 2022 Spring Conference.)

ERCOT’s flexible load task force, having agreed on some high-level concepts, has paused until January. That gives staff time to develop language for protocol changes necessary to accommodate the large loads, said Longhorn Power’s Bob Wittmeyer, the group’s vice chair.

ERCOT pays industrial users to shut down during tight conditions. The grid operator’s low wholesale energy prices have also been a draw for crypto miners, but they have been rising recently.

The bankruptcy of FTX, a $32 billion cryptocurrency exchange, has sent shivers through the industry. The financial losses, criminal investigations and skepticism in Washington, D.C. have cast further gloom.