FERC on Thursday proposed changes to NERC’s draft critical infrastructure protection (CIP) standard addressing the cybersecurity of real-time communications between control centers.
The Notice of Proposed Rulemaking, which builds on a proposal by NERC, seeks comment on requiring the electric reliability organization to add protections on the availability of communication links and data communicated between control centers. It also sought comment on requiring NERC to clarify the types of data that must be protected (RM18-20).
NERC proposed standard CIP-012-1 in response to FERC Order 822 (RM15-14), issued in 2016. In addition to approving seven modified CIP standards, FERC’s order directed NERC to require responsible entities to implement controls to protect communications links and sensitive data communicated between control centers. (See FERC Postpones Action on Supply Chain Protections.)
PPL’s control room | Barco Inc.
The order acknowledged that not all communication network components and data require the same level of protection because they pose different risks to bulk electric system reliability. As a result, NERC said its standards drafting team focused on the types of real-time data a control center will communicate and whether their compromise would pose a high risk to grid reliability.
NERC proposed exempting operational planning analysis data used in next-day operations, saying if there is a risk such data have been compromised, the responsible entity can verify the data prior to any impact on real-time operations. Although “an operational planning analysis factors into how an entity operates, there is less of a risk that an entity would act on compromised data from an operational planning analysis given it will base its operating actions on real-time inputs,” NERC said.
Also exempt are oral communications, which are covered by standard COM-001-3.
‘Largely Responsive’
NERC’s proposed standard would apply to balancing authorities, generator operators, reliability coordinators, transmission operators and transmission owners that operate control centers. It would require them to identify security protections, where they are applied and the responsibilities of each entity for control centers owned or operated by different entities.
FERC’s NOPR called NERC’s proposal “largely responsive” to Order 822, saying it supports situational awareness and reliability by requiring rules to prevent the unauthorized disclosure or modification of real-time assessment and monitoring data transmitted between control centers.
But the commission said NERC’s proposal may not address all cybersecurity risks, saying it does not require protections regarding the availability of communication links and data. The commission said it disagreed with NERC’s contention that the issue of data availability is adequately covered by standards IRO-002-5 and TOP-001-4.
The commission said those two standards only require redundant and diversely routed data exchange infrastructure within control centers, not between them.
It also said the standard must be revised to add a definition of “real-time monitoring,” which is not spelled out in the standard or the NERC Glossary.
FERC said NERC has “broadly defined” real-time assessments, which RCs and transmission operators must perform every 30 minutes to identify any actual or potential exceedances of system operating limits or interconnection reliability operating limits.
But it said “real-time monitoring is not defined at all.”
“We are concerned that without further clarity, reliability standard CIP-012-1 may be implemented and enforced in an inconsistent manner,” the commission said.
Comments on the NOPR are due 60 days from publication in the Federal Register.
FERC on Thursday directed SPP to eliminate its exit fee for members who are not transmission owners or load-serving entities, granting a complaint by the American Wind Energy Association and the Wind Coalition (EL19-11).
The commission found the RTO’s exit fee to be unjust and unreasonable “because it creates a barrier to SPP membership for non-transmission owners and because it appears to be excessive.”
“SPP’s exit fee for non-transmission owners … is not needed to maintain SPP’s financial solvency or avoid cost shifts, and is excessive as a means of ensuring stability in membership and members’ financial commitment,” the commission said.
AWEA applauded FERC’s decision, saying the exit fee prevented environmental groups, consumer advocates, independent power producers, power marketers and other market participants from “contributing to [SPP’s] decision-making process.”
“We look forward to working with SPP to develop a more inclusive stakeholder process that will lead to better outcomes for ratepayers,” Amy Farrell, AWEA’s senior vice president of government and public affairs, said in a statement.
SPP said it was unable to respond to the order until it reviews it to “fully determine its implications.”
AWEA and the Wind Coalition, now known as the Advanced Power Alliance (APA), filed the complaint in November, charging that the exit fee results in unjust and unreasonable rates “because there is no causal relationship between a non-TO/LSE’s termination of membership and the majority of the exit fee” and because the exit fee is “a practice that directly affects jurisdictional rates … by creating a barrier to membership for non-TOs/LSEs,” resulting in their under-representation as voting members in SPP.
The complainants argued than an administrative fee would be a more “appropriate mechanism” for SPP to recover its ongoing obligations, as do other RTOs and ISOs. They contended SPP does not attempt to correlate the exit fee’s assessment with the amount of costs caused by a withdrawing non-TO/LSE member, saying a public interest entity with no market activity would pay the same exit fee as an entity with thousands of megawatts of generation in the RTO.
FERC agreed, noting the only instance of an exit fee’s assessment came in 2015 when Trans-Elect Development Co. was charged $822,008 upon the involuntary termination of its membership for nonpayment of obligations. The commission said SPP calculates that the exit fee for an entity without load would be approximately $621,851, as of October 2018, and found that at even that level, the exit fee “could place a significant burden on smaller entities or new market entrants that are not transmission owners.”
The commission pointed to comments from DC Energy, EDF Renewables, E.ON Climate & Renewables, Invenergy Energy Management, TradeWind Energy, Texas Industrial Energy Consumers, Interwest Energy Alliance and public interest organizations that indicated they had not become members “because of the potential burden associated with paying the exit fee.”
SPP requires its members to pay a $6,000 annual membership fee. The exit fee is defined as the sum of the withdrawing member’s existing obligations (including any unpaid dues or assessments and any costs directly incurred by SPP because of the membership termination) and the member’s share of SPP’s outstanding long-term financial obligations (loans, leases and pensions) and general and administrative overhead for a three-month period.
FERC said SPP has grown “significantly” since 2006, when it last ruled on its exit fees. At the time, long-term financial obligations amounted to about $25 million, the commission said. But as the RTO has grown by building out its transmission footprint and administering an energy imbalance market and its Integrated Marketplace, it said, so have SPP’s long-term obligations.
SPP’s long-term debt peaked at more than $258 million in 2012, when it was developing the Integrated Marketplace. The markets went live in 2014, and SPP’s long-term debt has subsequently dropped to more than $215 million.
Membership benefits include the ability to: vote on SPP initiatives; elect members to the Board of Directors; propose changes to the Tariff, business practice manuals and governing documents; serve on committees, task forces and working groups; participate in closed or executive session discussions; request dispute resolution; and appeal decisions to the board.
Nonmembers or their representatives can attend open meetings and submit comments on proposals. They can also participate in the Integrated Marketplace and take transmission service under the Tariff.
Steve Gaw, a former Missouri legislator and regulator, has long represented the APA at SPP stakeholder meetings. As a regulator, Gaw also served on SPP’s first Regional State Committee.
SPP Granted Delay for Tariff Revisions
In a second order Thursday, the commission granted SPP’s request to defer revisions to its Tariff because of an implementation delay in a new settlement management system (ER17-1568).
SPP said several Tariff revisions were dependent on changes built into the settlement system, but that the system had “encountered developmental delays.”
The new settlement system was originally projected to go live May 1. However, that date has now been pushed back to Feb. 1, 2020.
FERC Chairman Neil Chatterjee on Thursday named veteran commission attorney Maria Farinella as chief of staff to replace Anthony Pugliese.
FERC attorney Maria Farinella receives applause after being announced as the commission’s chief of staff. | FERC
“Maria’s longstanding career as an energy attorney, both at FERC for the past decade and in private practice, makes her uniquely qualified to fulfill this key role,” Chatterjee said in a press release.
Farinella worked as a senior attorney in the Office of the General Counsel’s Energy Markets Division from 2009 to 2011, and as a senior legal adviser in the general counsel’s front office from 2011 to 2019. She was a legal adviser to Chairman Joseph T. Kelliher from 2007 to 2009. She is a graduate of Smith College and American University’s Washington College of Law.
Pugliese, who abruptly left the commission March 15, had served as chief of staff since August 2017, before the arrival of Kevin McIntyre as chair in December of that year. He stirred controversy last July for remarks he made at a conference of the American Nuclear Society and on the “Breitbart Radio Show,” in which he praised President Trump and criticized Democratic governors for blocking gas pipelines.
At his regular press conference after Thursday’s monthly meeting, Chatterjee declined to comment on whether he agreed with Commissioner Richard Glick’s criticism of the New England Power Pool’s policy of excluding the public and press from stakeholder meetings.
On April 10, the commission voted 3-0 to dismiss RTO Insider’s complaint under Federal Power Act Section 206 asking it to force NEPOOL to open its meetings or to strip it of its role as the stakeholder body for ISO-NE.
Chatterjee joined Glick and Commissioner Bernard McNamee in concluding FERC lacked jurisdiction to force such a rule change (EL18-196). Glick filed a concurrence, saying that while he agreed with his colleagues on the jurisdictional issue, NEPOOL’s meeting policies are “misguided” and should be changed. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)
New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
Chatterjee declined Thursday to say whether he shared Glick’s view that NEPOOL’s meetings should be open. “I voted for the order. I think it speaks for itself,” he said, declining to elaborate.
The recusals led to speculation that LaFleur — who announced Jan. 31 that she would not be appointed to a third term — has begun to search for her next job. Although her term ends June 30, she could serve the remainder of this year if no replacement is confirmed.
ClearView Energy Partners said such recusals are “common when a sitting commissioner is interviewing with an entity that may be involved in proceedings before the commission.”
LaFleur, a New Englander, came to FERC after serving as executive vice president and acting CEO of National Grid USA.
LaFleur — who previously declined to give the reason for her recusal on the NEPOOL order — did not offer any clues to her plans at Thursday’s meeting, where she introduced her son and husband in the audience.
“For the members of our friendly press corps, the fact that I have my family here does not mean this is my last meeting,” she said, turning to reporters. “I will let you know when it’s my last meeting. I promise.”
PJM MOPR Issue ‘Really Complicated’
Chatterjee said the commission hasn’t yet acted on PJM’s proposed changes to its capacity market because of the complexity of the issues.
PJM, which normally holds its annual capacity auction in May, delayed it until August in the hopes that would give the commission time to rule on its proposed changes to its minimum offer price rule (MOPR). In June 2018, the commission ruled the RTO’s existing MOPR was unjust and unreasonable because it didn’t address price suppression from state subsidies for renewable and nuclear power. (See PJM to Hold Capacity Auction in August.)
Chatterjee was asked at his press conference whether FERC’s failure to act on the proposal suggested a 2-2 split among the current commissioners and the need to fill its fifth seat.
The chairman said although he was prohibited from discussing internal deliberations, he could comment “at the macro level.”
“When it comes to wholesale power markets, these aren’t things that break down on ideological or political lines,” he said. “It’s just something my colleagues and I and staff are working towards. It is not something that we’re gridlocked because of some kind of political difference. It’s really, really, really complicated.”
WASHINGTON — FERC Chairman Neil Chatterjee on Thursday denied a report that he lobbied to block the nomination of Republican David Hill to the commission.
Citing interviews with a dozen industry and political sources who requested anonymity, E&E News reported April 12 that Chatterjee made calls to energy companies and Republican allies to block Hill from replacing him as chairman. E&E quoted Hill, an energy attorney who served in the George W. Bush administration, as confirming that the White House told him he would be appointed FERC chair.
Chatterjee did not respond to E&E’s requests for comment before publication of the article. But in his regular news conference following the commission’s monthly open meeting Thursday, Chatterjee attempted to discredit the report.
Hill was the Department of Energy’s general counsel from 2005 until 2009 and NRG Energy’s general counsel between 2012 and 2018.
E&E said Hill’s nomination was all but official until lobbying efforts by Chatterjee, Energy Secretary Rick Perry and the coal industry caused the White House to abandon him. Hill had publicly criticized DOE’s bids to provide subsidies for struggling coal and nuclear generators.
Chatterjee gave his rebuttal Thursday when E&E reporter Rod Kukro, one of the authors of the article, asked him when he became aware that the White House intended to replace him with Hill.
Chatterjee challenged Kukro’s premise, saying two other reporters had pursued the story and published nothing because they were unable to verify it.
“I know you cited 12 sources that you talked to. I know for a fact that at least two of those sources pushed back aggressively on the story line, yet their statements weren’t reflected anywhere in the article. I also know that at least a couple of those sources directed you towards the actual people that were involved in this process and knew the details of it, and you ran the story without contacting the folks that were actually in the room and knew the circumstances of the story. You had no named sources. No corroboration.”
Chatterjee challenged E&E’s account that the White House and Hill began preliminary discussions in September 2018 about taking over for ailing Chairman Kevin McIntyre.
McIntyre, who was visibly unwell in his last commission meeting in July, relinquished the chairmanship to Chatterjee Oct. 24 after revealing that he had suffered a “serious setback” in his cancer fight. He died Jan. 2.
David Hill | LinkedIn
“David Hill is a good man, and I find it almost impossible to believe that David Hill would have been negotiating in September to be chairman of the commission while Kevin McIntyre was still alive and serving,” Chatterjee said.
“Well [Hill] was the source, and he was named in the story,” Kukro shot back. “Are you saying he’s lying that [National Economic Council Director] Larry Kudlow told him he was going to be chairman?”
“I can’t speak for conversations you had with David Hill,” Chatterjee responded. “I don’t know that that’s ever been corroborated by anybody.”
RTO Insider asked the chairman why he did not respond prior to the article’s publication.
“The story was so baseless that I didn’t think it merited a response,” Chatterjee said.
“So, you’re saying you had no conversations with anyone regarding Hill’s candidacy?” he was asked.
“No reporter has been able to identify a single individual that I contacted or what I talked about,” Chatterjee said.
“That doesn’t sound like a denial,” the reporter said.
The MISO Planning Advisory Committee will vote by email on a DTE Energy proposal to broaden the scope of the RTO’s effort to create new rules allowing storage projects to solve transmission needs.
DTE’s motion proposes that stakeholders and the PAC recommend that MISO include a path for non-transmission owners as well as TOs to own and operate storage-as-transmission assets (SATA). The motion will appear on an email ballot April 22-26.
MISO’s Carmel, Ind., control room | MISO
In developing the rules, MISO determined that only registered TOs should be eligible to own SATA in order to avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services.
DTE says non-TO SATA should be permitted to bypass the interconnection queue and connect to MISO’s transmission system via newly conceived storage interconnection agreements.
To be eligible to secure a storage interconnection agreement, DTE proposes that resources must resolve a transmission-reliability issue identified in the annual Transmission Expansion Plan (MTEP) process, “satisfy the same performance criteria” as other SATA in the MTEP analyses, and “be operated strictly at the direction of MISO’s transmission-reliability function to address such issues.”
DTE’s Nick Griffin said the motion will close an “equity gap” in MISO’s first SATA filing with FERC. Absent DTE’s provision, he said, the SATA ruleset would create preferential treatment for TOs and “create barriers for entry for storage.”
Griffin said the motion does not yet address cost recovery.
In a complicated interpretation of MISO’s stakeholder process, the Steering Committee last month directed the PAC to revisit the possibility of non-TOs owning SATA in response to DTE’s request. (See MISO Planning Committee to Reconsider Non-TO Storage as Tx.) Some stakeholders were concerned that PAC leadership prematurely suppressed conversation on DTE’s proposals by not holding a vote to gauge whether stakeholders thought the idea warranted further debate.
MISO has said stakeholders agreed before drafting the SATA rules that they would neither address non-transmission alternatives (NTAs) nor create an entirely new cost allocation as a part of the SATA policy development.
But MISO Director of Planning Jeff Webb said the RTO’s existing process to consider NTAs in transmission planning may cover what DTE seeks.
“As a general matter, we do not require non-transmission alternatives to complete the generator interconnection process unless the asset is a generation facility seeking access to the market,” Webb explained.
Not that Simple, Stakeholders Say
Entergy’s Yarrow Etheredge pointed out there is no structure in place for MISO to assume functional control over assets other than transmission. She said DTE’s proposal wasn’t as simple as minor Business Practices Manual or Tariff changes.
Great River Energy’s Jared Alholinna agreed that DTE’s motion would create a “gray area” around what is and isn’t transmission and could ultimately undermine the FERC definition of transmission.
“This is being characterized as quite narrow, but it really balloons out,” American Transmission Co.’s Bob McKee said.
Griffin said non-TO SATA could have similar treatment to a generator under a system support resource agreement, in which MISO dictates that assets be available for dispatch.
“We think with a few minor BPM and Tariff changes, we could achieve analogous treatment,” Griffin said.
But Etheredge said an SSR-style treatment still lacks the automatic controls that MISO has established with its TOs.
Xcel Energy’s Drew Siebenaler said the motion could create the discriminatory treatment DTE claims to combat because the proposal names a special interconnection path meant only for storage devices.
“I would view that as a discriminatory filing,” Siebenaler said.
DTE coming forward without a defined cost allocation was problematic as well, added Xcel’s Carolyn Wetterlin. She said she had never heard of a MISO project gaining approval without first having an established cost allocation method.
MISO’s Environmental sector took the discussion as an opportunity to call out the SATA proposal as too limiting in the first place. Clean Grid Alliance’s Natalie McIntire said the current plan ignores the full spectrum of storage capabilities. She said MISO has rushed the first SATA proposal and “unreasonably” limited the scope of a possibly “precedent-setting” ruleset.
Webb acknowledged that MISO’s “first stage” SATA rules are intentionally narrow so that storage doesn’t have to scale the approximate three-year interconnection queue before being eligible to solve a transmission need.
“We wanted to clear that barrier first,” he said.
Webb promised MISO stakeholders future Tariff proposals that would allow expanded and multifaceted storage use in the footprint.
The PAC will hold a May 15 conference call to discuss refinement of the SATA filing and announce the ballot results on DTE’s motion.
MISO hopes to file the new rules with FERC in June or July. One SATA project is currently moving through MTEP 19 in the hopes that rules are in place by the end of the year.
The ERCOT Technical Advisory Committee’s leadership has canceled the committee’s April 24 meeting because of a “limited number of items to be considered” and does not plan to hold an email vote.
Instead, ERCOT will use the date to hold a workshop on outage activity related to its operating condition notice (OCN) in late February. The OCN set in motion events that resulted in market complaints about the grid operator’s communication practices and transparency. (See ERCOT Generators Upset over Early March Weather Event.)
The workshop will begin at 9:30 a.m. The TAC’s next regularly scheduled meeting is May 22.
SALT LAKE CITY — Regulators and industry experts from across the West last week heard about cyberattacks and natural disasters, having enough renewable energy to meet demand, and the possibility of using compact nuclear reactors to backstop wind and solar.
The spring joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) focused on grid reliability and protecting crucial infrastructure. The conference spread across three days, with roughly 16 hours of panel discussions and approximately 175 people in attendance.
It opened with a panel on small modular nuclear reactor power plants, in which NuScale Power showed its design for a 60-MW reactor that is far more compact than traditional nuclear units. NuScale is working with the Utah Associated Municipal Power Systems (UAMPS) and the Idaho National Laboratory (INL) to develop a working module by 2026. (See With Big Nukes Dwindling, Supporters Focus on Modular.)
The NuScale unit looks like a 75-foot-tall, 15-foot-wide torpedo. Twelve of the units could be combined to form a 720-MW power plant covering 35 acres, much less ground than is usual today, said Chris Colbert, NuScale’s chief strategy officer.
“We’ve moved a number of components into the reactor pressure vessel, and what that allows us to do is to get rid of the piping and the pumps” that occupy much of the area in a traditional nuclear generating station, Colbert said. “When you go to a smaller design, you’re able to eliminate over two-thirds of the systems and components you find a in a typical reactor.”
That makes the unit simpler, with “less to operate it, less to maintain it and less things that can go wrong,” he said.
A compact nuclear unit designed by NuScale. | NuScale
Colbert and his fellow panelists acknowledged the public blowback that’s likely to greet any proposal for a new nuclear plant.
“Obviously we’ve got a lot of risk here,” UAMPS CEO Doug Hunter said.
The developers said they are planning to build the first generator at the Idaho National Laboratory, a nuclear research site larger than Delaware, with construction slated to start in 2023. They’re hoping the isolated site and lots of public outreach “will allow a new generation of reactors to exist,” said George Griffith, an INL relationship manager.
Colbert said the units will be needed to ensure reliability as older fossil-fuel generators are retired and a fast-growing number of states and cities establish carbon-free mandates. Wind, solar and hydroelectric may not be enough to keep the lights on because of varying weather and rainfall, he said.
“For those of you who’ve ever lost power for more than a day, you know what that can be like,” Colbert said. “Imagine if it did it all the time.”
Resource Adequacy Concerns
The same scenario was on the minds of state regulators and utility representatives who spoke at the meeting.
In a panel on Western resource adequacy and market purchases, Rick Link, vice president of resource planning and acquisition for Pacific Power, said diminished demand in the wake of the 2008 financial crisis had created surpluses and made it relatively easy to depend on market purchases to supply needed power.
The thinking went, he said, that “it may be cheaper to do that, as long as [the power’s] there, than spending $700 million to build a new gas facility.”
But supply is tightening, and the situation is changing, he said. Those tasked with ensuring grid reliability can no longer just talk about economics and the best use of existing resources. Instead, they need to look at the development of new resources and innovative responses.
“It’s great timing to have this discussion,” Link said. “We may be transitioning into a period where we at least have to ask the question, ‘Will [the electricity] be there?’ So, it is more one of reliability, and that needs to be pushed front and center.”
Panelists focused on the need for a regional entity to coordinate purchases and generation throughout the Western Interconnection and having sufficient transmission capacity. States will have to play a bigger role in regulation and coordination, they said. And utilities need to be able to share information about their activities to avoid conflicts, some contended.
Washington Utilities and Transportation Commissioner Ann Rendahl said regulators are concerned that utilities are overly reliant on market purchases, putting consumers at risk of rising prices in times of high demand and tight supply.
“What we don’t know is whether [the utilities are] all basically relying on the same resources,” Rendahl said. That would become clear in a cold snap or heat wave when supply tightens and prices shoot up, she and others said.
“There’s increasing uncertainty that there is sufficient resource adequacy in the next five years, creating an increasing possibility of a regional capacity condition” in the Pacific Northwest, Rendahl said. “Everyone is agreeing that we’re approaching this point.”
The “capacity surplus is quickly dwindling,” she said, “and the utilities … are not stepping forward to build capacity, leading to this very tight capacity market.”
Disaster Readiness
Other panels at the meeting dealt with electric vehicles and the need to protect utility infrastructure from terrorist attacks. (See Western EIM Looks to Expand Its Authority.)
The discussion returned repeatedly to the theme of making sure the lights stay on.
During a presentation on the Initiative for Resilience in Energy Through Vehicles (iRev), panelists — including Laura Nelson, executive director of Utah Gov. Gary Herbert’s Office of Energy, and David Terry, executive director of the National Association of State Energy Officials — discussed EVs in the context of catastrophes. EVs could allow evacuations in situations where gas is unavailable and could ensure emergency workers have vehicles that run, they said.
Most areas only have a week’s worth of gas on hand at a given time, they said. Terry showed a photo of cars crowding a gas station after Superstorm Sandy in 2012.
Natural disasters such as Hurricane Katrina in 2005 and the 1989 Loma Prieta earthquake in the San Francisco Bay Area had shown the potential for the grid to go down for extended periods, said Doug Little, senior adviser in the U.S. Department of Energy’s Office of Electricity.
“Imagine if you had to live for a week without electricity. It’s pretty scary,” Little said during his talk on protecting defense-critical electric infrastructure in the West.
“Katrina got pretty ugly” in New Orleans, and San Francisco lost power for several days after Loma Prieta, he said.
“Now we have to worry about destruction by terrorists that have become more and more resourceful,” Little said. “We could see casualties and effects on security and economy from a cyberattack that would be comparable to weapons of mass destruction.”
The federal government’s Advanced Research Projects Agency-Energy is investigating longer-duration battery storage to power the grid from 10 to 100 hours during disasters, Little said.
“If there was ever a time for megawatt-scale storage to be important, this is it,” he said.
FERC on Thursday proposed changes to NERC’s draft critical infrastructure protection (CIP) standard addressing the cybersecurity of real-time communications between control centers.
The Notice of Proposed Rulemaking, which builds on a proposal by NERC, seeks comment on requiring the electric reliability organization to add protections on the availability of communication links and data communicated between control centers. It also sought comment on requiring NERC to clarify the types of data that must be protected (RM18-20).
NERC proposed standard CIP-012-1 in response to FERC Order 822 (RM15-14), issued in 2016. In addition to approving seven modified CIP standards, FERC’s order directed NERC to require responsible entities to implement controls to protect communications links and sensitive data communicated between control centers. (See FERC Postpones Action on Supply Chain Protections.)
The order acknowledged that not all communication network components and data require the same level of protection because they pose different risks to bulk electric system reliability. As a result, NERC said its standards drafting team focused on the types of real-time data a control center will communicate and whether their compromise would pose a high risk to grid reliability.
NERC proposed exempting operational planning analysis data used in next-day operations, saying if there is a risk such data have been compromised, the responsible entity can verify the data prior to any impact on real-time operations. Although “an operational planning analysis factors into how an entity operates, there is less of a risk that an entity would act on compromised data from an operational planning analysis given it will base its operating actions on real-time inputs,” NERC said.
Also exempt are oral communications, which are covered by standard COM-001-3.
PPL’s control room | Barco Inc.
‘Largely Responsive’
NERC’s proposed standard would apply to balancing authorities, generator operators, reliability coordinators, transmission operators and transmission owners that operate control centers. It would require them to identify security protections, where they are applied and the responsibilities of each entity for control centers owned or operated by different entities.
FERC’s NOPR called NERC’s proposal “largely responsive” to Order 822, saying it supports situational awareness and reliability by requiring rules to prevent the unauthorized disclosure or modification of real-time assessment and monitoring data transmitted between control centers.
But the commission said NERC’s proposal may not address all cybersecurity risks, saying it does not require protections regarding the availability of communication links and data. The commission said it disagreed with NERC’s contention that the issue of data availability is adequately covered by standards IRO-002-5 and TOP-001-4.
The commission said those two standards only require redundant and diversely routed data exchange infrastructure within control centers, not between them.
It also said the standard must be revised to add a definition of “real-time monitoring,” which is not spelled out in the standard or the NERC Glossary.
FERC said NERC has “broadly defined” real-time assessments, which RCs and transmission operators must perform every 30 minutes to identify any actual or potential exceedances of system operating limits or interconnection reliability operating limits.
But it said “real-time monitoring is not defined at all.”
“We are concerned that without further clarity, reliability standard CIP-012-1 may be implemented and enforced in an inconsistent manner,” the commission said.
Comments on the NOPR are due 60 days from publication in the Federal Register.
WASHINGTON — FERC on Thursday finalized a streamlined licensing process for hydropower projects at non-powered dams and closed-loop pumped storage projects, a response to a Congressional directive.
Under the new rule, the commission said it “will seek to ensure a final decision” within two years after receipt of a completed license application (Order 858, RM19-6).
Chairman Neil Chatterjee said the commission completed the rulemaking with three days to spare under the 180-day deadline set by Congress in the America’s Water Infrastructure Act of 2018, which became law in October.
The expedited rules will apply to existing non-powered dams that are not already licensed or exempted from the licensing requirements of the Federal Power Act. The facilities must generate power through “withdrawals, diversions, releases or flows” from non-powered dams and must not make any material changes to the storage, release or flow operations of the dams.
Closed-loop pumped storage projects can qualify if they cause little or no change in existing surface and groundwater flows and uses and are unlikely to adversely affect threatened or endangered species. Reservoirs at natural waterways, lakes, wetlands and other natural surface water features would not qualify.
The rule permits only temporary withdrawals from surface waters or groundwater for the “initial fill and periodic recharge” of the storage facility.
The rule requires developers to document their consultation with stakeholders, including tribes, dam owners and federal and state agencies responsible for required authorizations under the Clean Water Act, the Endangered Species Act and the National Historic Preservation Act.
Applicants for projects at a non-powered dam must prove the owner of the dam is not opposed to hydropower development. Projects using any park, recreation area or wildlife area created by state or local law must provide documentation that the managing entity is not opposed.
FERC said it issued the new rule after consulting with 28 federal agencies, state agencies and tribes, which participated in an interagency task force.
Kentucky Dam and Lock 11 Hydropower Project | Rye Development
The new licensing option will be voluntary and will not change the commission’s current three prefiling process choices for developers to use in preparing license applications.
“I hope that we have a large number of license applicants” under the new rule, Commissioner Cheryl LaFleur said. “There are approximately 80,000 unpowered dams in the United States. Many of them are probably not suited for power production, but some of them are and could be brought online to help contribute reliable, carbon-free flexible electricity.”
The rule will take effect 90 days after publication in the Federal Register.
WASHINGTON — Anti-gas protester Ted Glick has been thrown out of FERC open meetings so many times that he’s no longer allowed in.
So, on Thursday morning, he and fellow protester Drew Hudson climbed a large ladder and took up residence on the three-story awning over the building’s main entrance, dropping a banner calling for renaming the agency the “Federal Renewable Energy Commission.”
The protest was timed for the commission’s monthly open meeting, at which the commissioners voted 3-1 to approve two additional LNG export projects. The meeting was interrupted twice by other members of the protest group, Beyond Extreme Energy, who were led out of the meeting room by security.
Glick and Hudson broadcast their protest from the awning via Facebook Live, saying that LNG export projects will be rendered obsolete as the nation moves to 100% renewable energy to combat climate change.
FERC Chairman Neil Chatterjee said he sympathized with the protesters’ climate concerns but that LNG exports provide net environmental benefits.
“This was a very big deal,” he said after joining with fellow Republican Bernard McNamee and Democrat Cheryl LaFleur to approve the Driftwood (CP17-117, et. al.) and Port Arthur (CP17-20, et. al.) LNG projects and associated pipelines. Democrat Richard Glick — no relation to the protester — dissented.
Ted Glick (left) and Drew Hudson broadcast from the top of FERC’s awning via Facebook Live. | Facebook
The Driftwood project in Calcasieu Parish, La., will export an estimated 27.6 million metric tons of LNG annually, while the Port Arthur, Texas, project has a capacity of 13.5 million metric tons per year. There are currently 10 LNG export projects pending before the commission.
The U.S., which became a net exporter of natural gas in 2017, will see its role grow this year, FERC’s Adam Bennett said during a presentation of the commission’s annual State of the Markets report. “By the end of this year there should be six fully operational LNG export terminals here in the U.S.,” he said. “This year alone, domestic export capability is likely to double.”
Chatterjee said U.S. exports have “geopolitical” impacts, calling the LNG approvals “a very bad day for Russia,” which has sought to use its natural gas exports as leverage over its European neighbors.
In a press conference after the meeting, Chatterjee said he respects the passion of the protesters, “particularly the folks who risked their physical safety to climb the building to make the point that they felt was important to make.”
“I’ve been very vocal that I care deeply about climate change and the need to mitigate global emissions,” he said, contending that U.S. LNG is “being used to displace dirtier sources of energy in other parts of the world.”
“If people roll their eyes at me because I’m saying that the U.S. movement in LNG has … a positive impact on climate and carbon emissions, we’re never going to be able to have a reasonable conversation here. I’m trying to be constructive. It is significant and is not something that should be dismissed.”
Chatterjee and McNamee have won LaFleur’s votes on LNG projects since February by agreeing to include in the orders calculations of the direct greenhouse gas emissions from the liquefaction process.
But Chatterjee continued to reject calls by Commissioner Glick to quantify the downstream GHG impacts of such projects, saying it could leave the orders open to reversal. “I am not certain we have the capacity to do that. It could potentially jeopardize the orders in court,” he said.
At the March commission meeting, Glick rejected Chatterjee’s claim of a bipartisan “breakthrough” on the commission’s evaluation of LNG projects, joining with LaFleur to say the panel was still ignoring the projects’ impact on climate change. (See Glick Disputes FERC ‘Breakthrough’ on LNG Projects.)
Glick said the commission could require LNG exporters to mitigate their impacts on GHG emissions, as it does on environmental impacts on land, water and endangered species. “I think everyone knows what’s going on here,” the commissioner said. “This is climate change. That’s why we can’t talk about it.”
LaFleur said she has included in her concurring opinions her own analysis of the projects’ climate impacts as an alternative to dissenting.
“In spite of the fact that we have reached compromises on some language … it’s getting harder, not easier, to do that,” she said. “We treat climate change in our environmental analyses differently than every other environmental impact, and I think we’re just waiting for the court to impose requirements on us that could add unnecessary complexities and legal risk to these very big projects.”
