Page 1222 – RTO Insider

July 19, 2019

FERC Orders Cold Weather Reliability Standard

By Rich Heidorn Jr.

FERC on Thursday called for reliability rules requiring generator owners and operators to winterize their units and provide their reliability coordinators (RCs) and balancing authorities (BAs) with information about their preparations.

The commission issued the directive as a result of a joint FERC-NERC investigation into the abnormal cold and higher-than-forecast demand that caused MISO and SPP to seek voluntary load reductions and nearly forced load shedding in MISO South on Jan. 17, 2018. (See FERC, NERC to Probe January Outages in MISO South.)

“Today’s report finds that, despite prior guidance from FERC and NERC, cold weather events continue to result in unplanned outages that imperil reliable system operations,” the regulators said in a press release. Although the system remained stable, “continued reliable operation would have required shedding firm load if MISO had experienced its largest single generation contingency in MISO South.”

They said the need for a new reliability standard to improve generator performance was demonstrated by the 2018 incident as well as the large-scale unplanned outages during the 2014 polar vortex and the 2011 Southwest cold weather event.

“Learning from near-miss events is extremely important,” Chairman Neil Chatterjee said in announcing the report at Thursday’s open meeting.

The report said the 2018 incident resulted from both gas supply shortages and a failure to properly winterize generation facilities. It made 13 recommendations, calling for improvements in generator performance, load forecasts, communication and planning.

9 States Affected

The event affected all or parts of nine states, including MISO South (Arkansas, eastern Texas, Louisiana and Mississippi); southeastern SPP (lower Kansas-Missouri border, the eastern half of Oklahoma, Arkansas, eastern Texas and Louisiana); the western portion of the Tennessee Valley Authority (western Tennessee, lower Missouri, northeastern Oklahoma, northern Mississippi and Alabama) and the western portion of the Southeastern Reliability Coordinator (SeRC)/Southern Co. footprint (southern Mississippi and Alabama).

MISO did not expect to have a problem meeting its South load on Jan. 17, based on anticipated generator availability and precautionary measures it took to increase projected reserves. But conditions worsened because of the “extraordinary” level of generation outages and derates.

The report found 183 generating units in the RC footprints of SPP, MISO, TVA and SeRC suffered an outage, derate or failure to start between Monday, Jan. 15, and Thursday, Jan. 19.

Reliability — Generation outages and derates by RC footprint beginning Jan. 17, 2018 | *FERC*

Including generation already derated or on planned or unplanned outages before Jan. 15, the four RCs had more than 30,000 MW of generation unavailable in the South-Central portions of their footprints by the Jan. 17 morning peak.

MISO South had as much as 17,000 MW of generation unavailable — all but 4,000 MW unplanned — including 57% of generation in Louisiana and 23.5% of that in Arkansas.

“Had MISO’s next single contingency generation outage in MISO South of 1,163 MW occurred, continued reliable [bulk electric system] operations would have depended on system operators shedding firm load promptly to prevent further degradation of BES conditions,” the report said.

Weather Impact

Generator owners and operators (GOs and GOPs) directly blamed 14% of the generator failures between Jan. 15 and 19 on the cold weather, citing frozen sensing lines, frozen equipment, frozen water lines, frozen valves, blade icing and low-temperature cutoff limits.

An additional 30% were indirectly linked to the weather, including fuel curtailments to gas-fired generators (16%) and mechanical causes related to cold weather (14%), such as freezing of gas purge valve and steam turbine intercept valves, drops in oil pressure, wet or frozen coal and the loss of feedwater.

The report recommended GOs and GOPs implement freeze protection measures, such as installing wind breaks on generating units and conducting regular maintenance, and inspection of other protections, such as heat tracing equipment and thermal insulation.

The investigators noted about 70% of the unplanned outages occurred in gas-fired units. They recommended requiring gas generators to inform their RCs and BAs whether they have firm gas supplies.

Ambient Temperature Ratings

The report also recommended better information sharing on the impact of ambient temperatures on generators and transmission lines.

It said GOs and GOPs should ensure the accuracy of generating units’ ambient temperature design specifications and share them with RCs and BAs.

All four of the RCs experienced transmission constraints, and MISO declared an energy emergency because it lacked enough reserves to balance generation and load in South. But the researchers said some system operating limits that became constraints were based on summer temperatures or static, year-round ratings, which understated the lines’ winter capabilities.

The report said SOLs and their associated equipment ratings should be based on “at a minimum, ambient temperature conditions that would be expected during high summer load and high winter load conditions, respectively.”

Power Transfers

The report also noted that increased electricity demand resulted in large power transfers, with MISO and SPP dispatching remote wind generation and SPP importing power over its HVDC ties with ERCOT. In addition, MISO’s regional directional transfer (RDT) from Midwest to South exceeded its contractual firm and non-firm limit of 3,000 MW, peaking at 4,331 MW about 6:30 a.m. CT.

“Although MISO exceeded the RDTL, and did not reduce the RDT below the 3,000-MW limit within 30 minutes as contemplated by the settlement agreement [with SPP and neighboring RCs], MISO operators communicated with adjacent RCs … that MISO would be exceeding the limit, and that if MISO’s RDT flows caused a system emergency for the adjacent RCs, MISO would take appropriate actions,” the report said.

The report also called for improvements to the joint Regional Transfer Operations Procedure that governs MISO’s use of the RDT. The recommendations included changes to clarify roles and timing and a requirement that affected entities declare an emergency before MISO sheds firm load to reduce the RDT.

The report also recommended that RCs consider the deliverability of reserves, noting that the constraints “caused reserves to be stranded from MISO South.”

It also said MISO should notify the other RCs when it is counting on the as-available, non-firm portion of the RDT to deliver reserves for MISO South.

Inaccurate Load Forecasts

The investigators gave good marks to the RCs’ system operators, saying their actions were “effective and timely.” But they said they were hampered by inaccurate load forecasts for MISO South. MISO’s five-day forecast for Jan. 17 underestimated load by about 6,000 MW (18.9%), and its three-day forecast was 1,900 MW low (6.1%). The report said MISO should work with its local BAs and adjacent RCs to improve its accuracy.

“While MISO and its neighbors worked together to maintain system reliability during the event, we recognize the opportunity to collaborate on changes that improve coordination during extreme events,” MISO spokeswoman Julie Munsell said Thursday. “We look forward to reviewing the findings and recommendations in the final report.”

Studies and Drills

Several of the recommendations concerned additional studies.

The report recommends studies that consider “stressed but realistic conditions,” noting that none of the RCs had anticipated the widespread transmission constraints on Jan. 17.

MISO and SPP should “jointly perform seasonal transfer studies and sensitivity analyses in which MISO and SPP model same-direction simultaneous transfers (e.g. north to south, south to north, west to east) to determine constrained facilities so that they can develop mitigation plans or other procedures for the operators,” it said.

It also said planning coordinators and transmission planners should jointly develop and study scenarios to prepare them for extreme weather. It said the studies should include removing generation units entirely to represent actual generation outages as opposed to scaling generating unit outputs.

The study team also recommended that MISO and other RCs perform:

Voltage stability analyses in future constrained conditions and benchmark planning and operations models against actual events that stressed the system;
Periodic impact studies to identify which elements in the adjacent RCs’ systems have the most impact on their own systems; and
Drills to “execute load-shedding for maintaining reserves while at the same time alleviating severe transmission conditions.”

July 19, 2019

NARUC Offers Tools for Measuring Cybersecurity

By Rich Heidorn Jr.

The National Association of Regulatory Utility Commissioners this week completed the release of a suite of tools it says will allow state regulators to gauge their utilities’ cybersecurity preparedness — without becoming technical experts.

NARUC said the two newest offerings, a template of questions and an evaluation tool, will help regulators make “well informed … decisions regarding the effectiveness of utilities’ cybersecurity preparedness efforts and the prudence of related expenditures.”

“The threat posed by cybersecurity incidents is very real, and it is essential that regulators have a clear understanding of the work being done by our utilities to safeguard vital systems and address current and future cyber threats,” said Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille, who heads NARUC’s Critical Infrastructure Committee.

Understanding Cybersecurity Preparedness: Questions for Utilities supplements prior NARUC cybersecurity publications, providing a list of queries that regulators can use to evaluate a utility’s cybersecurity risk management program and practices.

The Cybersecurity Preparedness Evaluation Tool (CPET) provides a way to measure the maturity of individual utilities’ cybersecurity risk management programs over time. It is intended to be used with the questions on an iterative basis to help regulators identify utilities’ cybersecurity gaps and press them for continued improvement.

“As regulators, we must assess utilities’ decisions to invest in risk management tools and other protections for business and customer information, but we are not cybersecurity experts,” Washington Utilities and Transportation Commissioner Ann Rendahl said. “CPET will help us dive into risk management and cybersecurity topics without each commission reinventing the wheel.”

The two new publications supplement three previously released resources: the Cybersecurity Strategy Development Guide (2018), which provides a “roadmap” for regulators to structure “long-term engagement” with utilities on cybersecurity; the Cybersecurity Tabletop Exercise (TTX) Guide (2019), an aid for creating exercises to gauge utilities’ and other stakeholders’ ability to respond to and recover from a cybersecurity incident; and a Cybersecurity Glossary (2019), which defines cybersecurity terms used in the other publications.

The content builds on NARUC’s Cybersecurity Primer, which was released in 2012 and updated in 2017.

Questions Template

The new questions document is organized by the five cyber risk management functions defined in the National Institute of Standards and Technology’s industry-agnostic Cybersecurity Framework (CSF).

The questions are divided into two categories: policy and plans, and implementation and operations.

NARUC recommends regulators consider creating cross-functional teams, including personnel familiar with utility operations, IT specialists and legal staff, to conduct the evaluations. Some commissions may hire cybersecurity consultants to assist.

The questions align with NERC’s Critical Infrastructure Protection standards. Some samples: Does an asset inventory exist? Do you require specialized cybersecurity training for personnel with IT or OT [operational technology] responsibilities? Do you budget for cybersecurity tools and technology separately from IT? Have you identified minimal operational functionality for recovery of critical assets?

Evaluation Tool

NARUC said its cybersecurity evaluation tool is intended to be more accessible than other resources, such as the Department of Energy’s Cybersecurity Capability Maturity Model (C2M2).

“Feedback from NARUC working groups and interviews consistently reveal that many [commissions] do not have access to the resources and technical knowledge necessary to apply highly technical tools like the C2M2,” it said. “By focusing only on the aspects of cybersecurity most important to commissions, completing an assessment using the CPET is likely to be less resource intensive on both the commission and the utility than assessments using other maturity models.”

The CPET helps regulators determine whether utilities have sufficient cyber plans and policies ready and have protected their IT and OT systems and are prepared to respond and recover quickly to attacks. While C2M2 can be used to evaluate generation, transmission or distribution operations separately, the CPET is intended to provide an overall assessment.

“By regularly engaging with utilities (e.g., annually, semiannually) using the Questions for Utilities and analyzing the information received using the CPET, commissions can assess the year-over-year change in cybersecurity preparedness of individual utilities within a [commission’s] jurisdiction, promote continuous improvement, and increase the overall awareness and visibility of cybersecurity preparedness and resilience across the utility landscape within their states,” NARUC said.

The CPET allows regulators to assign one of six maturity levels for nine topic areas consistent with the NIST CSF and NERC CIP standards.

NARUC recommends state regulators perform the cybersecurity evaluations separately from regulatory proceedings, saying it is likely to produce more openness from the utilities.

The CPET is not intended to be used to compare utilities’ maturity levels “as the operating environment and resource availability for each utility is unique and does not lend to a one-to-one comparison,” NARUC said.

“Although the CPET is not intended to assess utilities against each other, commissions can use the data collected from its analysis to develop a comprehensive view of cybersecurity preparedness across its jurisdiction, including strengths, challenges, best practices and other valuable information that will help guide their long-term activities and future engagements with utilities.”

July 19, 2019

FERC Clears MISO 2015/16 Auction Results

By Amanda Durish Cook and Rich Heidorn Jr.

In a decision marked by minor controversy, FERC on Thursday capped a three-year-old investigation into MISO’s 2015/16 Planning Resource Auction by finding no market manipulation on Dynegy’s part.

The commission also found the $150/MW-day clearing price in Southern Illinois’ Zone 4 was just and reasonable, despite ordering MISO to change capacity auction rules following the auction. Thursday’s order also declined to set up an evidentiary hearing to possibly recalibrate the auction results (EL15-70).

The investigation centered on an auction in which Zone 4 cleared at $150/MW-day, a nine-fold price increase compared with just $16.75/MW-day a year earlier. MISO’s other nine local resource zones cleared below $3.50/MW-day that year.

Complaints followed swiftly, questioning the justness of Zone 4 prices, and included then-Illinois Attorney General Lisa Madigan, Southwestern Electric Cooperative, Illinois industrial energy consumers and the public interest group Public Citizen. All questioned Dynegy’s market behavior because the company controlled a significant portion of the capacity available in Zone 4. (See FERC Launches Probe into MISO Capacity Auction.)

Two years before the auction, Dynegy acquired from Ameren four coal-fired generators in Zone 4 with a total installed capacity of more than 3 GW. At the time of the transaction, Dynegy’s market share in MISO’s capacity market was analyzed on a systemwide basis — rather than at the zonal level — because the 2013/14 auction cleared at a single price of $1.05/MW-day. Dynegy has since been acquired by Vistra Energy.

In early 2016, FERC determined that MISO’s $155.79/MW-day maximum bid was too high, needing to be set closer to $25/MW-day, and that the RTO didn’t accurately gauge power exports. As a result, MISO revised capacity import limits, set the initial reference level for capacity at $0/MW-day and developed default technology-specific avoidable costs. (See FERC Orders MISO to Change Auction Rules.)

In the auction, Dynegy offered 1,709 MW of capacity at $0/MW-day, 270 MW at $108/MW-day, 651 MW at $150/MW-day and 2,775 MW at $167/MW-day.

In Thursday’s order, FERC said that although Dynegy had pivotal supplier status and that substantial price separation occurred, MISO had conducted the auction in accordance with its Tariff and market power mitigation rules.

The commission noted that all Dynegy’s offers were made below Zone 4’s $247.40/MW-day cost of new entry and said it agreed with MISO and Dynegy that a clearing price isn’t unjust simply because it’s higher than expected.

“We find no evidence in the record to support a finding that Dynegy’s offers violated MISO’s Tariff, and we conclude … that the resulting auction clearing price was just and reasonable,” FERC determined.

MISO Independent Market Monitor David Patton had argued the RTO’s previous auctions, not the 2015/16 auction, were the problem, saying that previous “near-zero” clearing prices “undervalued the reliability provided by that capacity.”

“The price increase in Zone 4 merely reflects that prices were unreasonably low in previous planning years,” the Monitor said.

‘Full and Thorough’

The commission also said that contrary to complainants’ arguments, its Office of Enforcement conducted “a full and thorough investigation” into the matter, spanning more than three years, with review of about 500,000 pages of documents and 17 days of testimony from 11 witnesses.

“We reject any implication that the investigation was not sufficiently complete to consider the conduct at issue,” FERC said, adding it would take no further action to investigate allegations of market manipulation in the auction.

Southwestern Electric Cooperative’s complaint went a step further, arguing that all sellers in Zone 4 stood to be enriched by the high clearing price. Madigan also argued that all Zone 4 sellers should refund excess charges to customers.

But FERC dismissed that complaint, saying Southwestern Electric failed to specify any alleged violations of statutory or regulatory standards on the part of Zone 4 sellers.

Glick Miffed at Chair’s Action

During Thursday’s open meeting, Commissioners Cheryl LaFleur and Richard Glick noted pointedly that — although the investigation had been authorized by the entire commission — they were not consulted before Chairman Neil Chatterjee unilaterally ended the probe.

While LaFleur said she concluded that there was no evidence of market manipulation, Glick said Chatterjee “cut short” the probe prematurely.

Glick, who dissented on the order, noted that Congress gave the commission expanded authority to police market manipulation as part of the Energy Policy Act of 2005.

“I really don’t believe that when Congress enacted the law, they intended for there to be one commissioner to be able to make the decision about whether to conclude an investigation or not,” Glick said. “I think that Congress intended for all commissioners to … take a vote on those decisions.”

He echoed LaFleur in saying “reasonable minds very much could disagree” on whether the investigation should have continued. But because the evidence is not public, he said, “we can’t really have a discussion on the record. There’s not really any transparency about it. So, one of the things we should do is release as much of the information as we can. People need to have a lot of confidence in what we do and confidence in the markets.”

Glick said the commission’s ruling in the MISO case, and a separate rulemaking that reduced the amount of data the commission will require in market power reviews, “don’t really instill the kind of confidence we need to have in our markets.”

In his dissent, Glick called Thursday’s order a “wholly unsatisfactory response to the allegations of market manipulation” and derided the commission’s explanation behind terminating the investigation as “a series of statements, none of which adequately support the commission’s finding that those results were just and reasonable.”

“Today’s order does not provide even the scantest reasoning to support its finding that the nearly 1,000% year-over-year increase in the MISO Zone 4 capacity price had nothing to do with market manipulation,” Glick wrote. “Instead, all we have is the commission’s unsubstantiated assurance that no one violated the commission’s regulations regarding market manipulation.”

Asked by reporters after the meeting why he decided to close the investigation without consulting his colleagues, Chatterjee said, “It has always been the chairman’s prerogative to close an investigation. I’m not getting into the particulars of exactly when and how the investigation was closed, because that’s nonpublic. But the results of the investigation were made available to my colleagues, and as you can see, a majority of us agreed that market manipulation did not occur.”

Michael Brooks contributed to this article reporting from Washington.

July 17, 2019

MISO Makes Second Attempt at More Rigorous Queue

By Amanda Durish Cook

CARMEL, Ind. — MISO will this month take a second shot at a FERC filing that would change its generator interconnection fee structure and require customers to secure locations for projects earlier in the queue.

The commission in March rejected a plan to impose more stringent site control requirements and increase milestone payments for interconnection customers, ruling that the RTO didn’t adequately demonstrate its proposals were reasonable and not unduly discriminatory. But it did agree that more stringent site control requirements and higher milestones could help reduce speculative and duplicative projects. (See MISO Promises Refile on Stricter Queue Requirements.)

This time around, MISO will not make changes to its first milestone payment, which would remain $4,000/MW instead of becoming a variable cost representing 10% of the average network upgrade cost from the last three definitive planning phase (DPP) cycles. FERC said the RTO’s percentage proposal would have resulted in inconsistent payment amounts.

However, the new plan will add a refund mechanism to the total milestone fees imposed on a customer. The “true down” feature will cap total milestones at 20% of a project’s network upgrade cost, with any excess payment refunded back to interconnection customers after a project clears the second decision point, roughly 250 days into the queue.

Like MISO’s first filing, 50% of milestone fees are considered at risk of not being refunded if they’re needed to help defray network upgrade costs should a project withdraw at the first decision point, about 180 days into the queue. At the second decision point, the percentage of at-risk fees drops to 25%. The RTO currently considers all milestone fees at risk of acquisition to help pay for promised system upgrades at both decision points.

MISO will request an Oct. 1 effective date in its new filing, Manager of Resource Interconnection Arash Ghodsian said during a meeting of the Interconnection Process Working Group on Tuesday.

“We understand that the process is working as is … but we’re looking to fine-tune. The goal is to provide the highest amount of certainty for projects coming through the queue,” Ghodsian said.

He said the new filing will occur within the month. “Exact date TBD. But we’re shooting for the near future. Soon.”

Multi-project Sites

MISO is also proposing to amend the Tariff to allow different fuel types and multiple generation projects to share the same site. The RTO said its new proposal will allow “multiple proposal submissions provided they are concurrently viable.”

FERC had said MISO’s earlier requirement that project owners demonstrate “exclusive use” site control conflicted with a Tariff section that allows interconnection customers to submit “multiple interconnection requests for a single site” and a policy that requires customers to submit separate requests for generating units that use multiple fuel sources.

MISO will propose to require all projects sharing a location to identify each other in their respective interconnection requests and provide a common diagram of land usage. It would then analyze whether all the projects can be developed on the same parcel of land.

Site Maps vs. Secured Acreage

Stakeholders argued that interconnection customers’ responsibility to demonstrate an acreage-per-megawatt minimum can be done without providing a site plan map. MISO would require customers provide a location map as part of site control 90 days prior to the start of planning studies.

Some stakeholders still contended that an acre-per-megawatt demonstration and a project site map are two different requirements. Coming up with a site map is an administrative burden, they said.

“I just don’t see how you demonstrate site control without providing a map,” responded Paul Muncy, of MISO’s transmission access planning division.

Mike Blackwell, with MISO’s legal staff, said he didn’t see how a site plan map amounted to an administrative burden because any prospective project applying to the queue should at least already have a location map or parcels for lease options.

Ghodsian said interconnection customers should be prepared to submit an approximate project layout, even if the location changes from the final site control demonstration due at the time of signing the generator interconnection agreement.

“Initially what we’re asking is, ‘Do you have enough land for your project?’ … I don’t think this is that burdensome. If your project is ready, you should be able to put land on a site map for us,” Ghodsian said.

Other stakeholders pointed out that the queue takes three years to complete, and providing a facility site map so early in the process all but guarantees location changes.

Ghodsian said early site maps will help MISO determine whether multiple projects are proposing to develop on the same property. Maps help weed out site overlap instances later in the queue, he said.

Stakeholders also questioned MISO’s proposal that interconnection customers provide a full demonstration of site control prior to entering the DPP, pointing out that two years ago, FERC deemed sufficient a 75% demonstration of site control at the time of interconnection application.

Ghodsian said the 100% site control requirement was not up for renegotiation in the refiling. He said the new proposal will stick to the same principles as the original but take FERC guidance into account.

MISO Resource Interconnection Planning Manager Neil Shah said the changes are as important as ever, given that the RTO received 45 GW of new project requests this spring, bringing the queue to more than 100 GW.

“Everybody involved in that process knows that not all are going to go through,” Shah told Planning Advisory Committee members in June. “In short, the urgency is about processing the projects in the queue as quickly as possible.”

MISO’s current generator interconnection queue includes 642 prospective projects totaling 100.6 GW.

Except for its western region, MISO will begin processing the slate of projects received in April in October or November. Because of the large number of interconnection requests in the west, the RTO will begin work on those projects in August.

MISO has negotiated more than 30 interconnection and construction agreements so far in 2019; the RTO projects it will negotiate upward of 130 agreements by year-end.

Other Time Savers

The RTO is also pursuing other avenues to reduce the amount of time projects spend in the interconnection process.

Queue engineer Will Buchanan said MISO will continue building DPP system models in-house after a successful trial run.

“MISO was able to save a considerable amount of time in the 2018 cycle versus past years,” Buchanan said.

Buchanan said the RTO’s handling of queue modeling will maintain a consistency it couldn’t achieve when it outsourced modeling work to third parties. The move also cut out the “months of delay” that it experienced with modeling vendors, Buchanan said.

MISO will also create an instant, online application for interconnection requests, replacing its previous print-and-return PDF form.

Finally, MISO is betting it can shave an additional 10 days off the queue by requiring the bulk of stakeholder model reviews take place prior to the kickoff of DPP cycles. It will allow 10 business days from model posting for stakeholder review and another five business days for any final review after the official start of the DPP.

Stakeholders said shortening the timeline on model review may increase the margin for error, especially in MISO’s western states, which currently account for 69 project requests alone in the DPP. But RTO staff countered that no review time would be lost, with the idea being that MISO releases models sooner so stakeholders can begin sizing them up earlier.

“If we can get the models out earlier, it gives people more time to review. … We’re trying to give you an extended period. It just doesn’t look the same as it does now,” Buchanan said.

July 17, 2019

Con Ed: Failed Relay Protections Caused NYC Blackout

By Rich Heidorn Jr.

Consolidated Edison blamed a failed relay protection system for the blackout that darkened Broadway stages and left Manhattan residents without air conditioning, subways or elevators for up to five hours Saturday. About 72,000 customers were affected between West 30th and West 72nd streets, and from the Hudson River to Fifth Avenue.

The outage, which came on the 42nd anniversary of the city’s 1977 blackout, forced the cancellation of most Broadway shows, leading to impromptu performances outside theaters by cast members. Civilians took to the streets to direct traffic.

New York officials said about 2,800 stranded commuters had to be rescued from subways and hundreds more from more than 400 frozen elevators. Fans of singer Jennifer Lopez were evacuated from Madison Square Garden shortly her sold-out concert began. Temperatures were in the low 80s, with typical New York summer humidity.

The company said it restored power within five hours and that more than half the affected customers got power in less than three hours.

Source Identified

Con Ed said it had traced the outage to the failure of a relay protection system at its West 65th Street substation, which is designed to detect faults and cause circuit breakers to isolate and de-energize the faults.

“The relay protection system is designed with redundancies to provide high levels of reliability. In this case, primary and backup relay systems did not isolate a faulted 13,000-volt distribution cable at West 64th Street and West End Avenue,” Con Ed said in a statement. “The failure of the protective relay systems ultimately resulted in isolation of the fault at the West 49th Street transmission substation, and the subsequent loss of several electrical networks, starting at 6:47 p.m.”

The company had initially said the 13-kV cable fault was unrelated to the outage. “While the cable fault was an initiating event, the customer outages were the result of the failure of the protective relay systems,” it said.

Consolidated Edison Company of New York (CECONY) President Timothy Cawley told The New York Times that at least two parts of the utility’s system failed to operate properly and prevent cascading to six neighborhood networks. He said he had never “experienced a case like this.”

Although it could take weeks before the company completes its investigation of the outage, he insisted he was “very confident” there would be no repeat.

But he said investigators had determined that the protective relay system there failed to operate as designed on two levels and those failures triggered the halt of the flow of electricity.

Reaction

The incident prompted howls of outrage.

The New York Post used the incident to call for the ou s ter of Mayor Bill de Blasio, a 2020 presidential candidate who was campaigning in Iowa when the lights went out.

U.S. Sen. Chuck Schumer (D-N.Y.) tweeted that the Department of Energy should investigate the outage with state and city officials. “This type of massive blackout is entirely preventable with the right investments in our grid,” he said.

Gov. Andrew Cuomo warned in interviews that Con Ed “does not have a franchise granted by God” and “can be replaced.”

“We got very lucky the other night. When you have a blackout in a city like New York, you are one step away from chaos and mayhem,” Cuomo said in a television inte r view. The 1977 blackout, which lasted more than a day, led to looting and arson that caused millions in damage. About 3,800 people were arrested.

Cuomo said the incident was just the latest in a series of failures, citing the outage following a fire in a Queens substation in December, a September 2017 power failure at a Brooklyn substation and an April 2017 subway outage blamed on the failure of Con Ed’s electric supply.

On Tuesday night, about 2,100 Con Ed customers lost power for up to seven hours after a fire at a substation on Staten Island.

Con Ed spokesman Michael Clendenin responded in a televised interview that the company’s system “is probably better than any other” in the U.S.

PA Consulting Group last year selected Con Ed as the Northeast region national winner of its ReliabilityOne Award for its 2017 performance.

In January, CECONY, which serves New York City and Westchester County, asked the state Public Service Commission for a $485 million (8.6%) rate increase. Its sister company, Orange and Rockland Utilities, was among four companies penalized by state regulators last month for poor service. (See NY Utilities Dinged for 2018 Reliability, Safety.)

The fact that the incident occurred on the anniversary of the 1977 blackout led some — including “The Daily Show” host Trevor Noah — to spe c ulate without evidence that sabotage might have been the cause.

NERC spokeswoman Kimberly Mielcarek rejected that idea.

“A root cause analysis of the outage is underway, but at this time, there is no evidence of suspicious activity or long-term impacts to infrastructure,” she said. “The bulk power system remained stable and unaffected by the outage.”

FERC spokeswoman Mary O’Driscoll said the commission “will be closely monitoring NERC’s steps in responding to this event.” New York PSC spokesman James Denn said state officials were investigating, “as directed by Gov. Cuomo.”

Although Con Ed officials said summer air conditioning loads were unrelated to the outage, they were making no promises about the system’s ability to withstand the coming weekend’s heat, when temperatures are expected to reach the upper 90s.

“We expect that there could be service outages,” Clendenin said. “Those things happen during heat waves.”

July 16, 2019

FERC Staff Hear Doubts on ISO-NE Fuel Security Plan

By Michael Kuser and Rich Heidorn Jr.

WASHINGTON — New England regulators and stakeholders told FERC on Monday they fear ISO-NE’s fuel security proposal could increase costs without solving the region’s winter supply concerns, urging the commission to postpone the RTO’s Oct. 15 filing deadline and require it to provide more analysis before drafting Tariff changes.

FERC staff heard testimony on the ISO-NE Fuel Security improvements — FERC staff heard state regulators and NEPOOL members weigh in on ISO-NE’s proposed winter energy security improvements Monday. | © *RTO Insider*

The “ISO, to its credit, has done a lot of hard work in a short amount of time,” Matthew Nelson, chairman of the Massachusetts Department of Public Utilities, told FERC staff during a daylong public meeting (EL18-182, et. al.). “But … this is a case of too much, too fast.”

“We don’t want to buy things we don’t need to buy,” said New Hampshire Public Utilities Commissioner Kathryn Bailey, who said the proposal could increase the region’s already high electric rates. “The current design suggests that we have a winter problem, but we’re going to pay for ancillary services year-round.”

Last July, FERC ordered ISO-NE to develop a long-term plan to address concerns over insufficient natural gas supplies for generation in winter. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.) In March, the commission pushed the original July 1 filing deadline back to Oct. 15.

In April, the RTO, the New England States Committee on Electricity (NESCOE) and the New England Power Pool requested the public meeting with staff, saying that ex parte rules had prevented stakeholders from seeking guidance from the commission.

ISO-NE Chief Economist Matthew White and Christopher Parent, director of market development, opened the meeting Monday with an overview of the RTO’s “energy security improvements” (ESI) proposal, which includes day-ahead energy option products, a multiday-ahead market (M-DAM) and seasonal forward markets.

White said the proposal’s energy option design — the only part of the proposal the RTO plans to file in October — solves the “misalignment” between the high price implicit in energy interruptions and the lower energy prices suppliers receive. The RTO gave its most recent outline of the proposal to NEPOOL members at last week’s Markets Committee meeting. (See related story, “ESI Conceptual Design,” NEPOOL Markets Committee Briefs: July 8-10, 2019.)

Seeking Delay

Regulators and NEPOOL members told FERC staff Monday that the RTO’s plan for a deterministic impact analysis was insufficient and should include probabilistic results. Some complained that the RTO had failed to adequately define the problem or had ignored how offshore wind, LNG tanker deliveries and energy efficiency could reduce winter concerns. And numerous witnesses said the RTO’s plan to submit a Tariff filing in mid-October is premature.

Jeff Bentz, NESCOE’s director of analysis, said the schedule could be delayed by six months without impacting the proposed implementation.

“The ISO will not review its impact analysis until July 30. It will still be preliminary at the September 2019 Markets Committee vote, and a number of the modeling cases and specific assumptions are unclear at this point,” Bentz said. “With that backdrop though, ISO is encouraging state and stakeholder proposal amendments by mid-August, which is about two weeks after we get the impact analysis. … We have more questions than firm views at this point.”

NEPOOL Chair Nancy Chafetz, of Customized Energy Solutions, asked FERC to “keep an open mind” on the proposals. Although NEPOOL members have “jump ball” rights to propose an alternative to the RTO’s proposal, Chafetz said the stakeholder body won’t have an official position until it votes in October. And even then, she said, “some of our stakeholders may have difficulty in taking a position when we vote because of” the aspects of the plan that the RTO said it would have to deal with later.

Bentz and others also expressed concerns about the ability to mitigate market power. “We think it’s going to be hard to mitigate these call options. There’s a lot of subjective inputs in determining what your option bid is going to be,” he said.

What’s the Target?

Phil Bartlett, chairman of the Maine Public Utilities Commission, said the RTO’s “problem statement” is not specific enough because it fails to define the level of reliability it is seeking.

“We think this is a very aggressive time frame, so we would support any kind of delay to ensure there’s better analysis, to make sure that we have a fully developed solution and we know what the results are going to be,” he said. “If we end up … mostly just compensating existing generators for doing what they’re already doing, we’ll see significantly higher costs without much benefit. I think that’s a very real risk with this proposal.”

Liz Delaney, director of energy market policy for the Environmental Defense Fund, raised a similar concern. “While the ISO has made efforts to justify its targets and to tie them to NERC standards, it’s still unclear if this target is calibrated with enough precision to ensure that it’s procuring essential and not excessive quantities. ISO New England has not assessed whether a more modest procurement would still uphold the NERC standards.”

David Cavanaugh, vice president of regulatory and market affairs for Energy New England, said NEPOOL’s publicly owned utilities sector is not convinced the M-DAM is needed. “The M-DAM significantly complicates the design and implementation and would increase the cost of business for publicly owned entity members through increased IT requirements and staff with yet-to-be-determined benefits,” he said.

Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection, said regulators have been chastened by previous market overhauls touted as fixes, such as the Pay-for-Performance capacity market program.

She noted that the RTO is proposing not just three new ancillary services markets, but also the M-DAM and a new futures market. “With all of these new markets, we know that they will raise costs. The questions that we’re not prepared today to be able to address is whether they will solve the problem and whether they will solve the problem fully.”

Penalties or Incentives?

FERC Commissioner Richard Glick, who attended part of the hearing, also cited the incentives in the PfP program in expressing skepticism over the ESI plan. He questioned whether the RTO should be using a “carrot or stick” approach.

“There was an expectation that resources were going to firm up their fuel supply arrangements … and I understand that didn’t really occur,” Glick said. “Is this something we should be solving … with incentives or should we be providing penalties?”

“Whether it’s structured as an incentive or penalty, what it really comes down to in influencing the commercial decisions of entities … is the delta in their profit and loss if they take [action] or they don’t,” ISO-NE’s White responded. “I don’t look at it as there’s a fork in the road [where] you can create incentives or penalties. I think that’s not the most constructive way to approach it.”

Massachusetts DPU Chair Nelson said he worries “that a stick approach might spur on more [plant] retirements.”

But James Daly, vice president of energy supply for Eversource Energy, said prior markets mechanisms have failed to deliver needed infrastructure. “FERC should require ISO-NE to make fuel assurance mandatory and not an option,” he said.

OSW, LNG Ignored?

David Ismay, senior attorney for the Conservation Law Foundation, said the proposal underestimates the contribution of state-sponsored clean energy resources to winter reliability.

The “ISO confirmed that, had it been operating at the time, the 800 MW of offshore wind that will be brought online in the next few years for Massachusetts would have had significant energy security and cost benefits during a representative cold snap [such as] one that we experienced in the 2017-18 winter,” he said.

White said the RTO has done some modeling of prospective offshore wind. “The challenge, of course, is that it is prospective. There is only the one very small facility [operating currently],” he said, referring to the 30-MW Block Island Wind Farm. “It’s difficult to reliably simulate the potential variability when there isn’t enough data to go on.”

Brett Kruse, vice president of market design for Calpine, said the RTO’s decision to sign Exelon’s Mystic generating plant to out-of-market contracts for Forward Capacity Auction 14 assumed there would be no LNG imports to the Northeast Gateway Deepwater Port Facility, which his company has used to supply its 2,000 MW of gas-fired generation in the region.

“We certainly believed that we could enter into similar agreements for the delivery years for FCA 13 and 14. In fact, we believe that many other alternatives (including additional oil backup) would have been available to ISO-NE at less than half the cost of the Mystic contract, if only ISO-NE would have opened their fuel security efforts to competition,” he said.

Other Proposals

Kruse and several other witnesses also offered alternatives to the RTO’s proposal.

Calpine proposed procuring fuel-secure megawatt-hours for the winter months three years in advance, a proposal it called the “forward enhanced reserves market.”

“We believe the forward market is the critical piece. Not the spot market,” Kruse said.

Neal Fitch, senior director of regulatory affairs for NRG Energy, said a seasonal forward market that incented purchases of oil and LNG four to six months ahead of real time would be most effective. But he said it will come with a cost. “Revenue-neutral solutions are really no solution at all,” he said.

ISO-NE’s Parent said the RTO will begin outlining its forward market proposal to stakeholders in August, but it won’t be included in its October filing. “Forward markets require sound spot markets. … to design a forward market in the absence of understanding how the spot market works is premature,” he said.

Tom Kaslow, vice president of market policy for FirstLight Power Resources, proposed the RTO limit the qualified capacity of gas-only resources in winter “to the level of such generation that the ISO-NE analysis indicates can be simultaneously fueled.”

“Qualifying a higher level doesn’t give you any more” capacity, he said.

July 16, 2019

States, Public Power Challenge FERC Storage Rule

By Christen Smith

State regulators, utilities and public power groups have asked the D.C. Circuit Court of Appeals to overturn part of FERC’s landmark rulemaking on energy storage participation, challenging the commission’s refusal to allow states to opt out.

The National Association of Regulatory Utility Commissioners’ (NARUC) petition seeks an order that portions of Order 841 and its rehearing order (841-A) “are arbitrary and capricious” and “not in accordance with law.” The Edison Electric Institute, the American Public Power Association, the National Rural Electric Cooperative Association and American Municipal Power filed a separate petition Monday also challenging the orders.

In a press release Tuesday, NARUC said it hopes states and “relevant electric retail regulatory authorities” (RERRAs) will be permitted to manage electric storage resources (ESRs) in the same way they oversee demand response aggregation. NRECA t o l d the House Energy and Commerce Committee in June FERC had overstepped its authority and local regulating authorities should be able to determine when and how ESRs join the marketplace.

In May, FERC ruled 3-1 to reject requests it allow RERRAs the ability to opt out of its storage provisions, as the commission did for demand response under Order 719. Commissioner Bernard McNamee was the lone dissent. (See FER C Upholds Electric Storage Order.)

The majority said the Federal Power Act gives FERC clear jurisdiction over storage, citing the Supreme Court’s 2016 EPSA ruling. EPSA upheld FERC’s jurisdiction over the participation in RTO markets of DR resources, which are generally located on the distribution system. “The court did not find the commission’s authority to be lessened by the location of demand response resources behind the retail customer meter,” the commission said.

“We disagree with assertions by petitioners and the dissent that, unless the commission adopts an opt-out, the commission’s regulation of the RTO/ISO market participation of distribution-connected and behind-the-meter electric storage resources violates FPA Section 201. We find the Supreme Court’s jurisdictional findings in EPSA regarding wholesale demand response apply with at least as much force to participation in RTO/ISO markets by electric storage resources engaged in wholesale sales in interstate commerce, even where those resources are interconnected on a distribution system or located behind a retail meter.”

McNamee said the majority “fails to recognize the states’ interests in ESRs located behind a retail meter (behind-the-meter) or connected to distribution facilities.”

“I believe Order Nos. 841 and 841-A are on solid footing when they deal with ESRs connected to the transmission system and how ESRs may participate in the wholesale market, and I concur in those aspects of today’s order. I am troubled, however, that the storage orders do not fully respect or consider the impact they may have on local distribution systems, the states that regulate those local distribution systems and local retail customers,” McNamee wrote.

NARUC’s criticism echoes comments from RTOs, utilities and states who said FERC’s order exceeded the commission’s authority. (See States, Utilities, RTOs Push Back o n Storage Order.) NARUC spokeswoman Regina Davis said the group’s petition won’t impact implementation of new rules because no stay was requested. There is no official timeline for court action, either, she said.

All six jurisdictional RTOs and ISOs are facing a December deadline for compliance with Order 841, which requires them to revise their market participation models to allow storage resources 100 kW and larger to provide capacity, energy and ancillary services within their technical ability. In April, the commission sought more information on the grid operators’ plans that were submitted five months prior. (See FERC Asks RTOs for more Details on Storag e Rules.)

Supporters of FERC Order 841 said some of the submitted plans currently under review are impractical and burdensome.

Astrape Consulting released a st u dy Monday — funded by the U.S. Energy Storage Association (ESA) and the National Resources Defense Council (NRDC) — that concluded PJM’s proposal requiring a storage asset to run for 10 continuous hours in order to qualify its full output for the capacity market “is unnecessary and unduly restrictive.”

“Energy storage is being installed on electric grids across the country at a rapid pace, helping transform our electric system to a more resilient, efficient, sustainable and affordable one,” said ESA CEO Kelly Speakes-Backman. “We stand behind the leadership at FERC to modernize energy rules to enable this transition. This study clearly affirms FERC’s judgement to include a broader set of technologies to participate, saving consumers money and supporting a diverse supply of clean energy generation.”

PJM spokesman Jeff Shields said Tuesday the RTO is awaiting FERC’s order on its Order 841 compliance filing. “Subject to FERC’s order, we are planning to implement in December 2019 as Order No. 841 proposed,” Shields said. “We will monitor any court developments in the meantime.”

FERC Chairman Neil Chatterjee last month described Order 841-A as one of the commission’s most important rulings it issued this year, calling it “one of the most significant federal actions we took to reduce carbon emissions.”

July 15, 2019

ERCOT Briefs: Week of July 8, 2019

ERCOT staff and stakeholders are preparing to bring a first set of real-time co-optimization (RTC) policy principles to the Technical Advisory Committee in a key test of their efforts to improve the Texas grid operator’s market design.

The Real-Time Co-Optimization Task Force, which is responsible for developing the RTC principles to align the ERCOT market with the direction given by the Public Utility Commission of Texas, will present five key principles to the TAC for approval during its July 24 meeting:

KP 1.4: System inputs into RTC
KP 1.5: Process for deploying ancillary services (AS)
KP 1.6: AS imbalance settlement with RTC
KP 3: Reliability unit commitment
KP 4: Supplemental AS market (SASM)

Stakeholders will debate KPs 1.5 and 3 and their alternative positions before the committee.

“The votes at the July TAC meeting will be a good indicator of whether the RTC Task Force’s efforts will be efficient in moving key design decisions through the stakeholder process,” said task force Chair Matt Mereness, ERCOT’s compliance director, following the group’s meeting Friday.

The task force is following guidelines set by PUC Chair DeAnn Walker for RTC, a market tool that procures both energy and AS every five minutes to find the most cost-effective solution for both requirements. (See ERCOT Real-time Co-optimization Falls into Place.)

Mereness said it was “helpful” to “have the PUC set direction on a number of key design issues.”

The RTCTF is also trying to engage other RTOs on lessons learned with their design and implementation of RTC. It hopes to bring MISO, PJM and SPP to Texas for a meeting in September.

ERCOT Comes Close to June Demand Record

The ERCOT system came about 1.5% shy of setting a new demand record for the month of June when it recorded a peak of 68.1 GW on June 19, compared to the all-time record set last year at 69.1 GW.

June’s peak set a high for the year that has since been broken in July. The system twice surpassed 70 GW on Wednesday, registering a peak demand of 70.5 GW for the hour ending at 5 p.m.

ERCOT is expecting a record peak demand this summer of 74.9 GW, 1.4 GW higher than the all-time record of 73.5 GW set last July. The grid operator has 78.9 GW of available capacity.

— Tom Kleckner

July 15, 2019November 30, 2023

FERC Proposes $6.8M Fine for CAISO Market Manipulation

By Hudson Sangree

FERC on Wednesday ordered energy firm Vitol and one of its senior traders to show cause why they should not be fined for manipulating CAISO’s market to limit losses on the company’s congestion revenue rights (IN14-4).

The trader, Federico Corteggiano, had helped create software for CAISO’s CRR market and had engaged in similar market manipulation before while at Deutsche Bank, FERC’s Office of Enforcement said.

In the more recent instance, he sold power at a loss of about $4,500 to save Vitol more than $1.2 million on its CRRs, FERC’s enforcement staff alleged.

In its ruling, FERC proposed ordering Vitol to return the savings, with interest, and fining it $6 million. The commission proposed fining Corteggiano $800,000. The commission gave Vitol and Corteggiano 30 days to respond.

Vitol and Corteggiano disputed FERC’s findings in testimony and prior filings, saying the trades were intended to take advantage of high prices, not to benefit Vitol’s CRRs. FERC found the arguments unpersuasive.

In their report, FERC enforcement staff said that during five days in the fall of 2013, Vitol “sold one product — electric power — at a financial loss in CAISO’s day-ahead market to benefit its separate financial product — respondents’ congestion revenue rights. Corteggiano, co-head of Vitol’s financial transmission rights trading operation, was the architect of this scheme.”

In 2013, Corteggiano purchased CRRs through CAISO’s auction for the Cragview node, the point where CAISO transfers power from the PacifiCorp-West balancing authority area in far Northern California.

The LMP at Cragview reflects 100% of the congestion on the Cascade intertie, the FERC report noted. “Vitol’s CRRs would earn money from import congestion on the Cascade intertie and lose money from export congestion,” it said.

In mid-October 2013, CAISO partially derated the Cascade intertie — limiting exports while still allowing imports during portions of late October, November and December. In October, Cragview’s LMP hit an unusual high of more than $388/MWh. Export congestion accounted for about $350/MWh of that price, FERC said.

Vitol’s export CRRs would lose money every hour. The firm was able to buy counter-flow CRRs for November and December, mitigating its losses and flattening its position, FERC said. “However, because the monthly CRR auction for October had closed, it was too late to flatten Vitol’s CRR position for the last week of October.”

Corteggiano, who holds a Ph.D. in power system engineering, found a way to get around that problem — one he’d used before, FERC staff alleged.

“Corteggiano knew that he could likely eliminate the problematic export congestion for that week by importing physical power in the day-ahead market at Cragview. Working with other Vitol employees, Corteggiano arranged to buy [5 MW of] physical power in the Pacific Northwest and successfully offered it for import at Cragview. Vitol’s imports over the Cascade intertie achieved their intended purpose, preventing export congestion from occurring during the period of Vitol’s imports. …

“Respondents lost money on the imports, but by making them, [they] were able to eliminate the export congestion and thereby avoid the far larger financial losses they otherwise would have incurred on the CRRs at Cragview.”

‘Phantom Congestion’

While at Deutsche Bank, Corteggiano had figured out how to manipulate congestion costs at another partially derated intertie linking CAISO to northern Nevada, FERC staff said. He had bought CRRs that profited Deutsche Bank when there was export congestion on the Silver Peak intertie but lost money when there was import congestion.

“In January 2010, CAISO partially derated the Silver Peak intertie to 0 MW in the import direction and 13 MW in the export direction. Import congestion appeared on the intertie, and Corteggiano’s CRRs began to lose money. Corteggiano found that he could substantially alter or eliminate what he called ‘phantom congestion’ by trading small quantities of physical power in the opposite direction of the derate,” FERC enforcement staff said.

“Corteggiano testified that ‘phantom congestion’ is ‘congestion that is not triggered by market behavior or by physical flows in the system,’” the report said. “‘Phantom congestion’ is Corteggiano’s own description of a pricing outcome rather than an industry-recognized term.

“Corteggiano admitted to Enforcement in 2010 that he made unprofitable physical trades on behalf of Deutsche Bank to benefit CRR positions that otherwise would have been harmed by the congestion associated with partial derates at Silver Peak. This was the only time in his career that Corteggiano traded physical power, until he did so at Cragview in late October 2013,” FERC said.

Enforcement staff investigated Corteggiano’s conduct at Deutsche Bank, resulting in the settlement of manipulation allegations with Deutsche Bank, a civil penalty of $1.5 million and disgorgement of $172,645, plus interest, in January 2013 (IN12-4).

At the Cragview node, “Respondents’ manipulative trading enabled Vitol to avoid paying CAISO $1,227,143 on Vitol’s CRRs,” the report said. “Moreover, respondents caused $2,515,738 in market harm consisting of (a) $2,429,385 in reduced funding of CAISO’s CRR balancing account, and (b) $86,353 in losses suffered by the holders of CRR counter-flow positions at Cragview.

“Although Corteggiano was not identified by name in the Order to Show Cause in the Deutsche Bank enforcement matter, the public Enforcement staff report attached to the order explained his central role in the trading scheme and referred to him by name,” the report said.

CAISO’s CRR auction has cost ratepayers $860 million because of the difference between revenues and payments to CRR holders, the ISO’s Department of Market Monitoring has found. The ISO has tried to stem the losses through changes to its CRR auctions, which appeared to reduce the disparity between payments and income in the first quarter of 2019. (See Gas Spike Drove High CAISO Power Costs in Q1.)

Vitol was one of the companies that opposed those changes last year. (See FERC OKs Tighter Rules for CRR Auctions.)

July 15, 2019

House Presses Reliability Officials on Cyber Threats

By Michael Brooks

WASHINGTON — House Energy and Commerce Committee members seeking details about foreign cyber threats were left wanting Friday as grid reliability officials declined to discuss specifics.

Appearing before the committee’s Subcommittee on Energy, NERC CEO Jim Robb, FERC Office of Electric Reliability Director Andy Dodge and Karen Evans — assistant secretary of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER) — all seemed hesitant to answer members’ questions directly. Instead, they often talked generally about their agencies’ efforts to protect the bulk electric system from cyberattacks. Sometimes they outright declined to answer, citing classified information.

Ranking member Fred Upton (R-Mich.) acknowledged the many security exercises the industry conducts, but he asked if any of them involved simulating cyberattacks against natural gas pipelines. Dodge said DOE held a classified security briefing, followed by a joint tabletop drill with FERC that “involved electricity industry officials, natural gas industry officials [and] all the RTOs and ISOs. And it was a rather extensive event. There were lessons learned … and the items from those we’re actively following up on.”

Neither he nor Evans said when the exercise was held. Upton followed up by asking them if their agencies were planning another exercise. Robb jumped in, speaking at length about NERC’s fifth Grid Security Exercise (GridEx), which will be held Nov. 13-14.

Rep. Scott Peters (D-Calif.) asked Evans if she knew “how many cyberattacks the electric grid sustains on … an average day.”

“It depends on how we talk about a cyberattack,” said Evans, who appeared to be choosing her words carefully. “We are in constant communications with the ISACs [information sharing and analysis centers], and we constantly monitor what is happening in the state of the sector as a whole. So beyond that, I am happy to come back in a more appropriate setting to give you more details if you’d like.”

“Well, you didn’t tell me a number,” Peters responded. “Do you know the number yourself?”

Evans repeated that it depends how you define a cyberattack. Peters followed up by asking if CESER was able to determine “how much of that activity is coming from state actors.” Evans gave a blank stare before smiling and saying, “So, again, I would be happy to talk about that more, but the way we are designing the system…”

“I’m not asking to tell me if it’s coming from state actors,” Peters interrupted. “I’m asking, do you know whether it’s coming from state actors? Is that something you don’t want to answer here?”

“I would like to answer that in a more appropriate setting.”

Similarly, Rep. Jerry McNerney (D-Calif.) asked Evans if she was “aware of any foreign governments embedding cyber weapons into our utility grid today to be used in possible future attacks.”

“I would reference back to the unclassified version of the Worldwide Threat Assessment,” Evans replied. “I think that the [director of national intelligence] has been very specific about what our adversaries’ capabilities are.” She said she has memorized the widely disseminated quotes from the report about Russia’s and China’s activities: They have “the ability to execute cyberattacks in the United States that generate localized, temporary disruptive effects on critical infrastructure…”

Rep. Ann M. Kuster (D-N.H.) asked Dodge whether FERC publicly discloses the names of utilities that have been assessed penalties for noncompliance with critical infrastructure protection (CIP) standards. Last month, Public Citizen filed a complaint with FERC requesting it release the names of two entities that violated 25 CIP standards between them (NP19-10, NP19-11). NERC issued penalties of $1 million against each of the entities.

Dodge said that over the past year, the commission has received “a number of” requests for critical energy/electric infrastructure information, including the identities of entities that have violated CIP standards, under the Freedom of Information Act. “We review them in excruciating detail, and we’ve determined which ones to release [and] which ones not to release,” he said. “We are still working through that, and we have released the names of some entities where we did not believe it would be a threat to security of that entity.”

Throughout the hearing, the panelists emphasized that interagency collaboration and information sharing between government and industry was critical to protecting the grid. Several representatives asked what Congress could do through legislation to help facilitate that.

“The most important thing from our perspective would be for government to be able to more rapidly declassify information, to get it into actionable insights that we can get out to industry,” Robb said. “Industry doesn’t need to know the origin, we don’t need to know the sources, we just need to know the what’s.”

McNerney asked Robb if “the security clearances of utility officials was an obstacle to effective data sharing of cybersecurity information.”

“I would say yes,” Robb replied. “Just the sheer number of individuals who are waiting for a clearance and don’t yet have them is problematic.”

McNerney then asked how Congress could fix that.

“I don’t have an answer to that question, but it’s a problem that needs to be resolved,” Robb said.