MISO’s 2019 Transmission Expansion Plan (MTEP 19) will advance to the Board of Directors without any recommended changes tacked on by the RTO’s Planning Advisory Committee.
The plan cleared the committee’s October email vote with six sectors in favor, none opposed and three abstentions. The PAC’s vote is only considered advisory.
The $3.97 billion, 479-project plan now moves to the board’s System Planning Committee for a comprehensive review Friday. The full board will vote whether to approve it at its Dec. 10 meeting as part of MISO Board Week in Indianapolis.
The PAC proposed no changes to the expansion plan, with a pair of motions to convert the Helena-to-Hampton Corners project into a market efficiency project and to delay MISO’s first storage-as-transmission project for more analysis both failing in the same email vote. (See Changes Proposed for MTEP 19 as PAC Vote Nears.)
At the same meeting, MISO proposed to conduct a special North Region operational limitation impact study for MTEP 20 in addition to the usual slate of planning studies.
Project Manager Sandy Boegeman said the study, added at stakeholders’ behest, will analyze the Minnesota-Wisconsin transfer limitation, known as MWEX.
“Due to the voltage stability nature of this constraint and its location between high renewable penetration areas and customers in the eastern areas of MISO, it presents a valuable opportunity to better understand the implication of a non-thermal constraint within the MISO footprint,” the RTO said.
“This study got a fair amount of support from stakeholders. And we think we have the bandwidth to do this,” MISO Director of Planning Jeff Webb said. The RTO will discuss the scope and objectives of the study at the PAC early next year, he said.
MISO promised unique, targeted studies to identify possible transmission projects in lieu of a fresh set of planning futures for MTEP 2020. (See “Special MTEP 20 Studies,” Changes Proposed for MTEP 19 as PAC Vote Nears.)
Even with MTEP 19 not yet finalized, MISO is already expediting a substation expansion for MTEP 20. Michigan Electric Transmission Co. is planning to expand its Riverview substation to accommodate new load requested by Consumers Energy near the city of Kalamazoo, Mich. The RTO said the 18-month project deserved fast-track status to avoid overloads. It will add the substation expansion to the Appendix A list of projects in MTEP 20.
The New York Public Service Commission on Thursday granted the New York Power Authority a certificate of environmental compatibility and public need to rebuild about 86 miles of upstate transmission lines (Case 18-T-0207).
The NYPSC held its regular monthly session in Albany on Nov. 14.
The Moses-Adirondack 1 and 2 lines extend from the St. Lawrence Power Project’s Moses-Saunders Power Dam switchyard in Massena to the Adirondack substation in Croghan. Thursday’s order also grants NYPA the right to build several upgrades to both the switchyard and the substation.
Chair John Rhodes
“I see this as a smart, careful, timely project that’s valuable for the statewide system needs and the statewide renewable energy needs,” PSC Chair John B. Rhodes said. “It’s well designed, has good minimization of impact with the very good use of existing right of way, attention to land use, attention to habitats and as a result is, on balance, very much in the public interest.”
NYPA proposed to divide the project into two phases, the first consisting of replacing 78 miles of the two lines currently configured as single circuits on separate wooden H-frame structures with two new single-circuit lines on steel monopoles.
The initial operating voltage would be 230 kV, with the second phase involving replacing the remaining length of the transmission lines with two single circuits on steel monopoles and upgrading the Moses-Saunders switchyard and the Adirondack substation to operate at 345 kV.
NYPA proposed to construct the project entirely within an existing right of way, except for a 1-mile reroute at the State University of New York at Canton campus.
CES Budget for 2020
The commission also approved a 2020 operating budget of nearly $13 million for the New York State Energy Research and Development Authority to run the state’s Clean Energy Standard and related programs (Case 15-E-0302).
Commissioner Diane Burman
The order authorizes NYSERDA to reallocate up to $12,138,093 of uncommitted system benefits charge, energy efficiency portfolio standard and renewable portfolio standard funds and $824,791 of previously authorized — but unspent — 2018 CES compliance period funding to cover administrative costs for next year’s RPS and zero-emission credit programs.
Commissioner Diane Burman dissented on the CES budget, saying, “I appreciate the work that NYSERDA does, but this budget request seems very bulky to me.”
The commission performs good due diligence by “not just accepting from utilities a bulky budget, and we work with them in streamlining that as much as we can and really trying to figure out what is absolutely appropriate and necessary,” Burman said.
Consent Agenda
The PSC approved nearly $5.2 million in sales of street lighting by National Grid to three municipalities in order for the towns to install and profit from more energy-efficient lighting. The sales were for Utica ($4.1 million), Dunkirk ($1 million) and Medina ($70,000).
Burman abstained from several items on the consent agenda, including those related to National Grid’s natural gas subsidiaries in Brooklyn and Long Island, and to Consolidated Edison’s gas business, because “we are not addressing some of the core issues around gas, and therefore, looking at these in isolation is very troubling to me.”
The National Grid items were for tariff filings to modify the companies’ gas tariff schedule to establish non-firm demand response service classes. The Con Ed items regarded revisions to its daily delivery service to institute a voluntary physical storage program, and to interruptible gas service program violations or strike rules.
Rhodes on Oct. 11 signed an order forcing National Grid subsidiaries Brooklyn Union Gas (KEDNY) and KeySpan Gas East (KEDLI) to connect 1,100 of 3,300 customers that had been denied natural gas service connections (Case 19-G-0678). KEDNY has approximately 1.2 million customers, and KEDLI has 590,000 customers.
National Grid found itself at odds with Gov. Andrew Cuomo last week when he issued a letter demanding that its gas subsidiaries connect all customers to whom it had denied service under a moratorium on new hook-ups or he would seek “to revoke National Grid’s certificate to operate its downstate gas franchise.” (See related story, National Grid Vows to Expand NY Gas Service.)
Commissioner Tracey Edwards
Commissioner Tracey Edwards said she wanted “to make sure that the definition of critical care customers is inclusive, so that it speaks to areas of refuge; it speaks to hospitals and nursing homes. I want to make sure that it includes assisted living facilities and homeless shelters, so I would like some follow-up information to make sure we’re looking at critical care in an overall perspective and not leaving anyone out.”
Burman also concurred with comment on items related to municipal tariff filings to modify the municipalities’ electric tariff schedules to include rules and regulations governing the purchase of renewable energy from new distributed generators and to implement net metering schemes.
The two items “appear to be addressing in a proper way the need for these tariffs. … These cases as well as others have sought to modify the tariffs on a voluntary basis because they’re not subject to the utility tax,” Burman said. “I’m flagging this because I want us to be looking at how the munis are doing it differently. … However, we really do need to watch if there are any negative ramifications to the customers, especially on the cash-out that goes to the developers.”
Burman concurred on a petition by 1115 Solar Development for compensation according to the Alternative 2 capacity value calculation set in the Value of Distributed Energy Resources (VDER) transition order, noting that a PSC staff white paper on the subject from last January did not mean that the commission thought of it “as a done deal.”
FOLSOM, Calif. — CAISO is moving ahead expeditiously with a plan to stem systemwide market power, even though not everyone is convinced the effort is necessary or needs to move so quickly.
The project stems from analysis by CAISO staff and the ISO’s Department of Market Monitoring earlier this year that detected a limited number of hours when the potential for the exercise of systemwide market power existed.
The report led to a sometimes tense meeting in August of the ISO’s Market Surveillance Committee, in which participants voiced opposing views on the need for market power mitigation measures and the speed at which the process was moving. (See CAISO Stakeholders Split on Market Power Efforts.)
On Wednesday, Brad Cooper, CAISO’s senior manager of market design policy, briefed the Board of Governors on the ISO’s decision to kick off a stakeholder initiative to design a mitigation program. Staff issued a conceptual proposal in September and last month released a scoping document setting out the guiding principles for the effort.
Cooper said it has proven tricky to design a process that limits market power without unintended negative consequences. Of particular concern, he said, is being careful not to deter electricity imports from other states by controlling prices too much. Those imports will be necessary for meeting California’s needs going forward, he said.
“We want to make sure we don’t cut off our nose to spite our face, so to speak,” Cooper said.
The predicted potential for noncompetitive conditions occurs at the ISO’s balancing area level, not the local level, he said. It can involve hours when supply is constrained by transmission bottlenecks or a lack of resources, he said.
Though the problem isn’t immediate, CAISO leaders and staff members are concerned that system market power could become more of a factor in the next few years. Starting in 2021, the retirement of fossil fuel plants and the inability of solar power to meet evening peak demand will create a much tighter energy market than today, according to CAISO projections.
Stakeholders, however, remain divided on the need for mitigation efforts, Cooper told the board. Electricity suppliers have argued there’s no real evidence of the exercise of systemwide market power — only the potential for it to happen.
“PacifiCorp agrees with other stakeholders that nothing in the CAISO’s system market power analysis indicates an urgent need for the CAISO to conduct a policy initiative to design and implement new price mitigation procedures to address system-level market power,” the utility, a major exporter of energy into California, wrote in comments filed with the ISO.
The state’s investor-owned utilities and the California Public Utilities Commission have contended the effort is critically important, he said.
“System market power mitigation is vital to ensure competitive outcomes in a market that has become structurally uncompetitive at the system level in a higher number of hour and intervals. When the market is structurally uncompetitive, market power can be exercised, and uncompetitive bidding practices can successfully drive up the price,” Pacific Gas and Electric said in comments.
Staff plan to issue a straw proposal next month and bring a final plan to the board early next year so that it can be implemented by the spring of 2021 — before the anticipated shortfalls of summer that year. The designers are looking at a phased-in approach that will first address issues in the real-time market and then move to the day-ahead market in phase two, Cooper said.
Some commenters Wednesday took issue with the two-phased approach.
Raisa Ledesma Rodriguez, with the CPUC’s Energy Division, said the phased-in effort may be insufficient to head off the exercise of market power. A representative from PG&E said the day-ahead market is where the greatest potential for problems occurs.
CAISO CEO Stephen Berberich told the board that applying market power mitigation measures in the day-ahead market is more complex than in the real-time market. Staff are moving ahead on the project with a sense of urgency, he said.
“Our analysis doesn’t show a burning bridge at this point,” but it’s important get ahead of the issue, Berberich said.
WASHINGTON — Deputy Energy Secretary Dan Brouillette appeared well on his way to taking over for his outgoing boss after facing little substantive questioning at his confirmation hearing Thursday and little, if any, opposition from Democrats.
Much of the hearing was taken up by members of the Senate Energy and Natural Resources Committee, on both sides of the dais, extolling the virtues of a particular technology and cordially asking Brouillette for his commitment and assurances that he would continue the Department of Energy’s work in advancing the research and commercialization of those technologies, including LNG, carbon capture and sequestration, battery storage, and advanced nuclear energy.
Brouillette has been serving as deputy to Energy Secretary Rick Perry since August 2017, when the Senate confirmed him 79-17. He was considered by the committee in May of that year alongside eventual FERC Chairman Neil Chatterjee and former Commissioner Robert Powelson. (See No Fireworks for FERC Nominees at Senate Hearing.) Chatterjee was among those in a packed audience Thursday that included five National Laboratory directors and Brouillette’s nine children.
Brouillette previously worked at the department in the George W. Bush administration as assistant secretary for congressional and intergovernmental affairs from 2001 to 2003. He worked as staff director for the House Energy and Commerce Committee for a year after leaving the department. Before returning to DOE, he had been a senior vice president for USAA since 2006.
President Trump formally nominated Brouillette on Nov. 7. Calling him “the obvious choice to replace Secretary Perry,” Senate ENR Committee Chair Lisa Murkowski (R-Alaska) told Brouillette it was her “intention to try and move you through the committee process just as rapidly as possible.” But regardless of if — or when — the Senate confirms him, Brouillette will take over leadership of the department, at least in an acting capacity, when Perry retires on Dec. 1.
Baseload and Resilience
Sen. Steve Daines (R-Mont.) said his state’s “balanced energy portfolio is coming under attack with the premature, forced closures” of two units at the coal-fired Colstrip plant because of “extreme, radical groups that litigate.” He told Brouillette he believed “that there is a role for you and the Department of Energy to play in order to maintain baseload supply in Montana” before asking him to “commit to working with me and this committee to protecting and growing baseload power like Colstrip and maintaining a secure and balanced energy portfolio.”
“It’s been the policy of this administration, and possibly the previous administration, to pursue an all-of-the-above energy strategy,” Brouillette replied. “In our view, diversity of energy supply means energy security, not only for our nation but for our allies across the world. … Until we are able to develop battery storage that has more capacity, is longer lasting [and] is perhaps more flexible in some respects, it is important that baseload power exist, because without it, if we are objective and candid, the introduction of renewables to our electric grid is very, very difficult.”
Through the department’s in-development North American Energy Resilience Model, “we’re going to look at these types of facilities and see if they fit that potential model and see if there’s anything that we should be concerned about potentially about the loss of those” plants, he said.
Asked by reporters after the hearing how he would go about saving baseload plants, Brouillette answered, “It’s not about saving the plants. It’s about working with regulators; showing them the things that we’re seeing; allowing the FERC to do its job.
“It’s not about simply ‘saving the plants.’ It’s about looking at the entirety of the grid, looking at the entirety of the energy sector and making sure that we have either distortions or artificial impacts on it that might preclude us from either adopting renewable technology or create some level of a security risk. … We’re looking at that resilience model as a way to show us in real time what’s happening on the grid.”
Ukraine Matters
The breezy hearing intersected briefly with the political firestorm taking place on the other side of Capitol Hill. Brouillette said he had no knowledge of or involvement in conversations with Ukrainian officials about matters at the heart of the House of Representatives’ inquiry into impeaching Trump.
“I have not been involved in any of the conversations that are related to the House’s inquiry,” Brouillette told ranking member Joe Manchin (D-W.Va.). He did say the department has worked with Ukraine, “at their request, to help them interconnect their electricity grid [and] their pipeline grid,” and that it has advised U.S. allies in Eastern Europe on building LNG import facilities as part of an effort to lessen their dependence on Russian natural gas.
Perry — along with U.S. Ambassador to the E.U. Gordon Sondland and Kurt Volker, special U.S. envoy to Ukraine — is one of the White House’s “three amigos” on Ukraine policy, according to Sondland. Perry had traveled to Ukraine in May for the inauguration of President Volodymyr Zelenskiy and provided him with a list of suggestions for the supervisory board of Naftogaz, the country’s state-owned energy company.
Sen. Ron Wyden (D-Ore.) asked if Brouillette was aware of “any contacts between Secretary Perry, or any other senior DOE officials, and representatives of Naftogaz.”
“I am aware that the secretary met on occasion with individuals who were asking for assistance with the restructuring” of the company, Brouillette replied. But he said he was not aware of any conversations between Perry and Trump’s personal lawyer, Rudy Giuliani, or anyone in the Ukrainian government about the makeup of the board.
CARMEL, Ind. — MISO’s grid will be only minimally susceptible to the impacts of possible water scarcity in the future, in part because of increased adoption of renewables, new RTO models show.
The RTO will only have a “relatively modest” need for incremental new generation to meet demand under water scarcity, Senior Adviser Eli Massey told stakeholders at a Planning Advisory Committee meeting Wednesday.
“The results of this first round of modeling suggest that MISO isn’t susceptible to either a short-term or long-term water scarcity scenario,” Massey said.
The modeling relied on data from Sandia National Laboratory to estimate the “water intensity factor” for MISO generation, which represents the relationship between the amount of cooling water and fuel needed to produce 1 MWh of energy. That data point was cross-referenced with estimates for the volume of water available for generation under short- and long-term scarcity conditions.
The Fermi 2 Power Plant on Lake Erie | DTE Energy
Most water scarcity concerns can be mitigated by economically redispatching MISO’s resource portfolio “around low to moderate water scarcity.” He also said the continued evolution of the resource portfolio toward renewables “is moving MISO in a direction that makes it less susceptible to water scarcity in the future.”
“Wind doesn’t need water,” he said.
MISO doesn’t collect cooling water use statistics from its members, and Sandia could only provide usage stats for about half the generation in its footprint, Massey said. He said MISO consulted with Sandia and the National Renewable Energy Laboratory on their methodology to fill in missing estimates.
MISO modeled both a six-year drought and recovery, and a 15-year water scarcity scenario in which water available for generation is limited by varying degrees. Scientists have repeatedly predicted that climate change, bringing long dry spells and more severe flooding, will intensify water shortages in some geographic areas. RTO staff did not mention climate change during the presentation.
Massey said energy served by MISO’s thermal resources is disrupted only in the most extreme water shortage scenarios.
“MISO is always looking at environmental issues or operational risks to reliability,” Massey explained to stakeholders. “We always felt like we thought we were OK, but we never quantified it.”
The effort is MISO’s first attempt to understand the potential impacts of water scarcity, Massey said, adding that the RTO will perform more analyses, possibly on a seasonal or subregional level, to understand the impacts of water constraints in the footprint.
“This isn’t the only avenue we’re exploring. MISO is partnering with NREL and other labs to understand water risk,” Massey said.
He also said MISO may explore requesting more accurate water use statistics from its thermal generation operators. He asked stakeholders to communicate their interest in having the RTO analyze more detailed data.
CARMEL, Ind. — MISO on Wednesday dismayed some stakeholders when it doubled back on a cost allocation proposal that would have lowered voltage thresholds and raised cost minimums for economically beneficial transmission projects.
FERC rejected MISO’s first cost allocation filing in June, finding it would have violated the principle of cost causation because projects proposed under the local economic transmission category would be required to demonstrate regional benefits while only being cost-shared on a local level.
That plan also sought to lower the regional market efficiency project (MEP) voltage threshold from 345 kV to 230 kV while keeping the current $5 million cost minimum for those projects, a measure that FERC did not address in its rejection.
In September, MISO circulated a proposal that sought to address the local project issue by lowering the voltage thresholds for regional MEPs to 100 kV, while increasing cost minimums to $25 million, a move intended to cover local projects with wider benefits. The plan would have also set a 100-kV threshold for interregional MEPs with Key Details Change in MISO MEP Cost Allocation Plan.)
MISO’s latest proposal, revealed during a Wednesday conference call of the Regional Expansion Criteria and Benefits Working Group (RECBWG), would restore key points of the original filing, including setting the voltage threshold for regional MEPs to 230 kV and observing a $5 million cost minimum. It would also require that local economic projects between 100 and 230 kV be allocated only locally.
But unlike the rejected plan, the proposal would also stipulate that local projects be reviewed on a local basis only, and not have to show regional benefits. MISO Senior Manager of System Planning Jarred Miland said the RTO now plans to perform only local benefit-to-cost analyses for local economic projects that are based on transmission pricing zones. If the lower-voltage projects show at least a 1.25:1 benefit-to-cost ratio to the transmission pricing zone where the project is located, then the costs of that project would be allocated to that zone.
MISO would first screen projects for possible benefits, then test them in modeling, Miland explained during Wednesday’s call.
“Since there’s not regional test, there’s not regional allocation. The difference is the local economic projects are going to be locally allocated to the local” transmission pricing zone, Miland said.
Blind to Benefits?
But several stakeholders said MISO’s new proposal is still at odds with cost causation.
They said MISO is wrongly presuming that all sub-230 kV projects cannot deliver regional benefits. Some asked if the RTO planned allocation exceptions for highly beneficial lower-voltage projects.
“I would say right now, the plan is what the plan is. There’s no intention to try to make those projects regional,” Miland responded. He said the new proposal is similar to MISO’s current practice, where all projects below 345 kV cannot be considered MEPs.
“We’re still dropping down from 345 kV to 230 kV. So that still helps,” Miland said, adding that MISO would still be positioned to approve more MEPs than it does now.
LS Power Manager of Transmission Policy Pat Hayes argued that because MISO would already screen lower-voltage projects for footprint-wide benefits, it wouldn’t take much additional effort to estimate regional benefits.
“You just can’t turn the model off and shield yourself from seeing adjusted production costs,” he argued.
MISO officials confirmed that they would see possible regional benefits in modeling lower-voltage projects but wouldn’t share them externally.
‘Head in the Sand’
WEC Energy Group’s Chris Plante said the regional economic benefits of projects 230 kV and below exist even if MISO doesn’t name them.
“The first proposal failed because we failed to identify beneficiaries of projects. This proposal is akin to putting a bucket of sand in the corner and sticking your head in it. Just because we don’t look elsewhere and don’t identify beneficiaries, doesn’t meant they don’t exist. … I think that this thought process is dead-on-arrival at FERC — it’s not going to fly,” Plante said.
Clean Grid Alliance’s Natalie McIntire agreed, saying MISO is choosing to be willfully blind to some project benefits and setting itself up to block some beneficial projects from proceeding.
“There isn’t a clear path forward for lower-voltage projects that bring wider benefits to zones,” she said.
However, other stakeholders said the new allocation plan was reasonable and that the 230-kV threshold isn’t arbitrary. Some pointed out that MISO only discloses regional benefits for projects 345 kV and above.
Plante said MISO might “temper” its proposal by making cost allocation “optional” for the zone that might host a regionally beneficial local economic project. That way, single zones wouldn’t be forced to foot the bill on projects positioned to benefit other transmission pricing zones, he said.
Miland said stakeholder opinions on the September proposal can be broken down into “those that didn’t like what we did and those that did like it.” MISO said a majority of its state regulators wanted it to follow FERC’s June rejection and refile the proposal, this time scrapping the local economic project category altogether, leaving projects below 230 kV again relegated to the RTO’s “economic other” project category, which also dictates that smaller economically beneficial projects are allocated to the transmission pricing zone where they are located.
Still other stakeholders said they didn’t support MISO’s proposed $25 million threshold or the competitive bidding exception for reliability projects that it determines have an immediate need. As in the first filing, the new plan would exempt from competitive bidding any MEPs needed within three years to mitigate reliability issues. The new proposal preserves that option.
MISO maintains that its proposal will better “align who pays with who benefits over time from a regional transmission expansion perspective.”
Stakeholders on the call asked if MISO has met with FERC staff to vet its newest proposal. Staff said they had not.
“We’ve been trying to weigh the feedback we received with what we think is the best path forward,” Miland said. “This hasn’t been taken lightly by any means internally here in MISO. This has been a full-time job for several of us for a handful of months.”
The change in tack on lower-voltage projects pushes out MISO’s refiling target.
“We were hoping to get a filing out the door before Thanksgiving. That’s probably not going to happen now,” Miland said.
A simulated social media hack was among the surprises lobbed at participants in GridEx V, the latest entry in NERC’s series of exercises testing industry preparedness for cyber and physical attacks.
More than 425 organizations across industry and government participated in the two-day exercise, which began on Wednesday with a distributed play model representing a wide array of threat vectors that Steve McElwee, PJM’s chief information security officer, called a “true doomsday scenario.”
Along with utility companies and regulators, the drill included representatives from farther-flung sectors, such as natural gas, electrical equipment manufacturing, telecommunications and even finance, in an attempt to game out the broader social impacts of an attack on the shared electrical grid.
An unnamed staffer at NERC’s Electricity Information Sharing and Analysis Center (E-ISAC) participates in day one of GridEx V. | NERC
Stacking the Deck
“One of the important design parameters that we use when we develop GridEx is we essentially break the system,” NERC CEO Jim Robb said in a media briefing Thursday. “That’s how the electricity industry learns: We break things, and then we figure out how to fix them and prevent the breakage from happening next time. So, it’s purposefully an overwhelming act of violence.”
This year’s challenges included the takeover of one utility’s Twitter account by malicious hackers that then used it to spread disinformation to the public and other participants, which one player described as the major “curveball” of the scenario. Additional threats included technological incursions such as the use of rogue USB devices and ransomware, which — along with physical attacks such as intruders in headquarters buildings and vehicle fires at regional facilities — put essential infrastructure out of commission. Utilities were tested both on their ability to handle the initial attacks and their capacity to ride out the damage and get their systems back online.
NERC CEO Jim Robb (left) with Southern Co. CEO Tom Fanning at a press briefing | NERC
The distributed play exercise was joined in its second day by a similarly comprehensive but more targeted scenario in Thursday’s executive tabletop session, which presented an attack on the northeastern part of the North American grid. Test designers decided on this scenario, the first region-specific exercise in the history of GridEx, in hopes of gaining deeper insights than were available in previous years. The northeastern setting gave participants the opportunity to explore characteristics of the region such as U.S.-Canada relations, the interdependence of the electric and natural gas sectors, and the impact of a prolonged outage on financial players in New York City.
“There are very few cyber-only or physical-only incidents, and as our world grows more interconnected and our infrastructure grows more interdependent with other systems and functions, we must look at our risks [from] both a physical and cyber perspective,” said Brian Harrell, assistant director of the Cybersecurity and Infrastructure Security Agency at the Department of Homeland Security. “The scenario is real, it’s relevant, and it focuses on industry and government partnerships and how we [can] collectively get better.”
Fighting Back
As Harrell suggested, risk is not the sole focus of GridEx. The scenario also provides a sandbox for the public and private sector to test mitigation tools without danger to the general public. This year’s scenario was no different, with participants aiming to address vulnerabilities identified in previous GridEx iterations.
One focus for industry players in this year’s scenario was to actively engage with the vendor supply chain. Vulnerabilities often center on specific equipment, yet in the public report following GridEx IV, NERC called out utility operators for failing to engage with vendors to the degree they did with other utilities, government, and law enforcement. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.) The criticism spurred greater efforts in this year’s exercise, though participants acknowledged that considerable work is still needed.
Kevin Wailes (left), Lincoln Electric, and Brian Harrell, DHS, at a press briefing | NERC
“The supply chain issue is extraordinarily complex and hard to think about over time, because the threat vectors change continuously and … a good device today may be exposed tomorrow,” said Southern Co. CEO Tom Fanning, co-chair of the Electricity Subsector Coordinating Council. “So, it isn’t [enough to] have certified equipment in our supply chain. … We must have a process of cyber hygiene and collaboration over time.”
On the public side, GridEx V provided a chance to test out the responsibilities granted to the Department of Energy since the last exercise under the FAST Act, amended in 2018 to designate the department as the lead agency on cybersecurity for the energy sector. The change gave broad new authority to DOE to coordinate with state and local governments, in addition to utilities, and GridEx provided an opportunity to test the practical limits of these powers prior to a real emergency.
“What we don’t want … is to be in an actual situation where we’re figuring out the right policies and how we share that information, and what type of information [to share], so that we can have the situational awareness to advise the president,” said Karen Evans, assistant secretary in DOE’s Office of Cybersecurity, Energy Security and Emergency Response.
Ongoing Development
The GridEx exercises have expanded considerably since the first iteration in 2011, which involved just 75 industry and government organizations across the U.S. and Canada. Unlike that scenario, which was inspired by the Stuxnet attack in Iran and focused exclusively on cybersecurity, GridEx now aims to include the widest possible range of participants so that every aspect of the system can be tested.
ERCOT staff participate in GridEx V. | ERCOT
This has led to criticism that the scenarios presented are unrealistic, with participants in previous years comparing the prepared situations to a “disaster movie” rather than helpful practice for recovery. NERC acknowledged these issues but said they overlook the true goal of the exercise.
“The grid is designed with a tremendous amount of redundancy, it operates in real time, and the loss of even a major power station in many cases is not a catastrophic consequence because the industry is prepared for that and designs around it,” Robb said.
“That makes a scenario [such as the one] we’ve laid out implausible but still worth testing,” he added, citing the potential to uncover unsuspected vulnerabilities and suggest new avenues of cooperation.
NERC will release its report on GridEx V by March 2020.
RTOs Take Part
RTO officials also gave their take on the exercise Thursday.
Keri Glitch, MISO’s vice president and chief information security officer, said the scenarios included “network breaches caused by an internal source, a potential intruder in the headquarters building, as well as a vehicle fire near a regional facility.”
“Our employees and industry partners collaborated well and learned a lot from the drill,” Glitch said.
About 120 CAISO employees took part in the exercise, along with representatives from federal, state and local agencies and 39 RC West participants, IT Enterprise Support and Campus Operations Director Matt Turner said.
“We assessed how employees reacted and communicated the scenario injects, which included a plan to return to normal operations. During the simulation, we injected additional issues, such as making key personnel unavailable, to evaluate the depth we have on the team and their ability to adapt to the situation,” Turner said. “Our exercise is designed to push the limits, as far as we could, to identify areas for improvement.”
New York state was “hit” hard during GridEx V, which included a “focused regional attack in the Northeast,” according to NERC CEO Jim Robb. Above, New York Power Authority staff participate in the exercise. | NYPA
SPP said more than 200 staffers took part, after more than a year of preparation by the RTO’s leadership team. “SPP’s incident coordination team led IT, operations and other staff in response to simulated threats to system reliability, communications channels and cyber assets, all in the interest of strengthening defenses, enhancing resilience and refining emergency response procedures,” spokesman Derek Wingfield said. “In the weeks leading up to the go-live of our Western reliability coordination service, GridEx also gave us the opportunity to test our preparedness alongside some of our new customers in the Western Interconnection.”
NYISO, ISO-NE and ERCOT also confirmed their participation. “Physical and cybersecurity measures are a constant practice of vigilance and focus of attention,” NYISO CEO Rich Dewey said.
“Past GridEx exercises have proven to be valuable training opportunities for many departments within ISO New England, and we look forward to practicing and improving our response capabilities,” RTO spokesman Matthew Kakley said.
While PJM regularly conducts simulator drills with its transmission owners and other critical players, GridEx allows the RTO to test its operations under extreme conditions, McElwee said. “It’s far beyond any situation we’ve experienced.”
Amanda Durish Cook, Tom Kleckner, Michael Kuser, Hudson Sangree and Christen Smith contributed to this article.
NERC announced Tuesday that the Board of Trustees has promoted Sonia Mendonca to senior vice president, general counsel and corporate secretary following a nationwide search.
Mendonca, who joined NERC in 2011, had been serving in an interim capacity since the retirement of former General Counsel Charles Berardesco in September.
Before Berardesco’s departure, Mendonca was vice president, deputy general counsel and director of enforcement, responsible for corporate governance, legal compliance, regulatory activities and oversight of the Compliance Monitoring and Enforcement Program for the ERO Enterprise.
She also served as NERC’s acting general counsel from November 2017 to April 2018, when Berardesco filled in as acting CEO after the resignation of Gerry Cauley and before the appointment of Jim Robb.
In her new role, she will be chief legal adviser to Robb, the board, staff and stakeholders.
“During her eight years at NERC, she has been instrumental in streamlining our enforcement process to make it more effective and efficient, among countless other initiatives,” Robb said in a statement. “Sonia’s dedication to the mission of the ERO Enterprise over the years made her a top candidate for this important job. I know she will continue to excel.”
Mendonca is a graduate of the Federal University of Rio de Janeiro Law School and the American University Washington College of Law.
CARMEL, Ind. — MISO is revising how it handles generator interconnections along its seams with neighboring balancing areas in a bid to satisfy several recent FERC mandates.
FERC issued the directives to MISO, PJM and SPP in September after finding that their joint operating agreements lack transparency around how they manage their affected-system impact studies. The commission ordered study procedures must contain:
Easily referenced business practice manuals;
Descriptions of modeling standards;
Clearer modeling details for interconnection customers;
A description of how MISO and SPP study the impacts on each other;
Descriptions of how the three RTOs monitor each other’s systems during the course of each of their interconnection studies.
Compliance filings are due from the RTOs by Feb. 3.
FERC’s directives were the product of 18 months of examination after EDF Renewable Energy complained about the RTOs’ affected-system coordination. (See Affected-system Rules Unclear, FERC Says.)
At a Nov. 12 meeting of the Interconnection Process Working Group (IPWG), resource interconnection engineer Sumit Mundade said the RTO’s interconnection staff have worked up “preliminary language” in JOAs with both PJM and SPP to comply with all six directives. MISO has set aside time through January to continue revising its JOAs, he said.
MISO seams | MISO
Mundade said MISO and SPP won’t be able comply with FERC’s requirement that they set specific dates to exchange affected-system information and study results and instead proposed they use “formula dates” based on the start of the studies and include deadlines for data exchanges.
“With MISO and now SPP’s adoption of a three-phase group study process, fixed calendar dates are not optimal because kick-off dates are not fixed in advance,” Mundade explained.
MISO will also add JOA language to clarify MISO’s study criteria only apply to its facilities.
“FERC wanted to know whose criteria applies to which facilities,” Mundade said. “SPP study criteria apply to SPP facilities, and MISO criteria apply to MISO facilities.”
MISO is also proposing to apply its external resource interconnection service study criteria when it studies SPP and PJM interconnection projects, rather using its network resource interconnection service criteria.
“FERC only asked us to describe this, not change anything,” Mundade said.
MISO still faces the task of explaining how it monitors neighboring transmission systems for impacts during interconnection studies. Mundade said while monitoring will include “an identification of MISO projects with potential impacts to the SPP or PJM transmission system based on each RTO’s criteria,” those JOA revisions are still in the works.
MISO has also not yet decided how it will detail the process used to determine projects’ queue priority in an affected-system analysis and how it will allocate the costs of network upgrades required on an affected system.
“The proposed language is under development,” Mundade said, promising to return to the January IPWG with more specifics.
In addition to the two compliance filings, MISO plans to make two separate filings to change some aspects of the JOAs with SPP and PJM.
Pending approval from its neighbors, MISO will add separate JOA language requiring MISO and SPP to share cost estimates and construction schedules of network upgrades and to synchronize information-sharing with PJM so studies line up more closely with PJM’s interconnection timeline.
The additional filings will also make clearer that interconnection customers bear the costs of the affected-systems studies. Mundade said the separate JOA filings contain affected-system changes not required by FERC but represent improvements nonetheless.
NERC opened a final ballot Wednesday on a proposal requiring entities that fail to meet performance requirements for “supplemental” geomagnetic disturbances (GMD) to develop corrective action plans (CAP) to minimize their vulnerability.
Voting will be open until 8 p.m. E.T. Nov. 22 on reliability standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events), which was prompted by FERC Order 851. In addition to requiring CAPs, FERC ordered NERC to authorize extensions of CAP deadlines on a case-by-case basis. (See Revised NERC GMD Standard Approved.)
GMDs, which occur when charged particles ejected from the sun cause changes in Earth’s magnetic fields, can cause voltage instability or collapse, damaging electrical equipment.
NERC’s original GMD standard required applicable entities to assess the vulnerability of their transmission systems to a “benchmark” GMD event, defined as a one-in-100-year event that would cause an 8-V/km “reference peak geoelectric field amplitude” at 60 degrees north geomagnetic latitude using Quebec’s ground conductivity. The standard applies to planning coordinators, transmission planners, transmission owners and generation owners connected at 200 kV or higher.
“Supplemental” GMD events refer to localized “spikes” of intense and damaging magnetic fields that can be created during an event that appears less severe based on spatially averaged measurements over a large area.
The standard opened for comment is virtually identical to the draft that received a 71% affirmative vote, clearing the 67% threshold, in a 45-day ballot period that closed Sept. 9. Organizations that voted in that round will see their votes carried over to the final ballot unless they choose otherwise.
The only change since the initial ballot is language specifying the “Compliance Enforcement Authority” (CEA) — NERC or the regional entity in the U.S. and any entity designated by Canadian officials — will handle requests for extensions. The original version said extensions would be subject to the “ERO.”
TPL-007-4 was created by an 11-member standard drafting team with input from industry and compliance leadership from each regional entity.
Deadlines
The standard requires completion of a CAP within a year after completion of a supplemental GMD vulnerability assessment that concludes the entity does not meet performance requirements. It lists as potential corrective measures the installation, modification or removal of transmission or generation facilities; operating procedures, protection systems or remedial action schemes and demand-side management. Hardware mitigation must be completed within four years after completion of the CAP, with non-hardware measures due within two years.
Under NERC’s CAP Extension Request Review Process, extension requests must be submitted no later than 60 days before the completion date specified in the CAP. The CEA is to convey its decision within 45 days after that.
Extensions will be granted only when implementation has been prevented for reasons outside the control of the responsible entity, such as delays resulting from permitting, equipment lead times or stakeholder processes required by tariff.
“If it was due to a lapse of planning properly or missing a date inadvertently, that’s not beyond the control of the responsible entity,” Steven Noess, NERC director of regulatory programs, said during a webinar Tuesday. “But there might be delays that are [due to] permitting, regulatory processes … [changes in] tariffs or lead times … specific equipment, right of way questions, things of that nature, [and we] certainly want to make it easy for folks to identify them.”
Flexibility Assured
In addition to clarifying the extension process, the standard drafting team also attempted to address industry questions about the level of rigidity in the Implementation Guidance for TPL-007-4 regarding specific mitigation measures. Several of the commenters on the first ballot asked for reassurance the revisions would permit utilities the flexibility to devise their own strategies.
PJM’s Emanuel Bernabeu, who chaired the standard drafting team, emphasized the recommendations in the implementation guidelines are for guidance only. While the team wanted to provide an example of a workable solution, any measure that achieves the goal and is in line with the current scientific understanding may be approved.
“Substantively [it] is the same information we had before, [but] we’ve tried to clarify the language so it’s absolutely clear that this is only [one] acceptable approach, and there are actually other approaches [to] the supplemental events that would be valued,” said Bernabeu.
The NERC Board of Trustees is expected to approve the standard in February 2020.
