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February 16, 2020April 9, 2024

Interregional Projects May Become Reality for SPP, MISO

NEW ORLEANS — Could this be the year SPP and MISO finally agree on an interregional transmission project?

Maybe. At least that’s what staff responsible for planning at the RTOs’ seam implied last week during a panel discussion at the Gulf Coast Power Association’s 7th annual MISO South Conference on Feb. 11.

An optimistic Casey Cathey, SPP’s manager of transmission planning and seams, assured a questioner that the grid operators will produce a coordinated system plan (CSP) this year. Two previous attempts have failed to yield an interregional project the organizations could agree on.

“We’re in heavy coordination and very close to coming up with some projects,” Cathey said. “For the first time in I don’t know how many years, we’ve got a good shot of getting a project through [the CSP].”

SPP’s desire for interregional projects has been driven by a wish to relieve congestion in eastern Kansas, which borders the MISO footprint. The growing impetus for MISO is the north-south transfer constraint between its Midwest and South regions.

As a result of a 2015 settlement agreement between the RTOs that also involves other parties, MISO is limited to 1,000 MW of contracted, firm transmission capacity between the two regions through SPP’s system, but it also has access to additional non-firm service capped at 3,000 MW in southbound flows and 2,500 MW northbound. (See SPP, MISO Reach Deal to End Transmission Dispute.)

Under the agreement, MISO pays SPP between $16 million and $38 million in base annual payments based on an annual available system capacity-usage factor. In February, that arrangement became subject to a 2 to 4% escalation rate. The limits also created problems during energy emergency alerts (EEAs) in 2018 and 2019, when MISO said the constraint prevented it from accessing resources to relieve the emergency.

With the agreement set to expire in February 2021, MISO is motivated to bring “operational certainty” to its members through new transmission projects or by purchasing additional firm capacity. (See MISO Floats New Option for Midwest-South Constraint.)

MISO Allocation Plan Fails on Local Project Treatment.)

“One of our objectives is to get to the point of long-term regional certainty,” said Jeremiah Doner, director of seams coordination for MISO.

“There will be another EEA event, with possible load shed,” Cooperative Energy COO Nathan Brown warned. “We really need some focus there.”

SPP could also be looking at its first international interregional project, Cathey said. The RTO shares a direct tie with Canada’s SaskPower through Basin Electric Power Cooperative’s existing transmission facilities in North Dakota and completed its first international transaction in 2015 when it imported power during an emergency situation. (See SPP, SaskPower Make First International Trade.)

A provision in SPP’s joint operating agreement with SaskPower allows joint planning analysis and coordinated system planning. With the oil-rich province of Saskatchewan facing continued load growth, SaskPower and SPP have held preliminary discussions.

“[SaskPower] can help fund projects in SPP and therefore improve their import capability,” Cathey said. “There are just so many things going on.”

Electric Industry Outpacing Others in Cybersecurity

SPP Director Mark Crisson opened a special briefing workshop GCPA held on the RTO by noting the growing importance of cybersecurity in the electric industry.

“Twelve years ago, this wasn’t on anyone’s radar,” he said. He recalled that when he became CEO of the American Public Power Association in 2007, he would receive “private, confidential” briefings from the Department of Homeland Security on industry cyber threats that were not to be shared with anyone else.

“It’s much more of an industry dialogue with the government now,” he said. “The nature of these threats evolve all the time. It’s hard to stay ahead of the bad guys, but it’s critical for our industry. We are way ahead of what other industries are doing, both with the steps we’re taking, the information we’re getting from the government, and the teamwork between us and the government.”

Crisson said SPP has developed its own set of cybersecurity criteria “that allows [us] to evaluate how effective or robust our cybersecurity really is.”

SPP currently scores itself above average, or between three and four on a five-point scale, Crisson said.

“We feel like we’re making good progress, but there’s a lot more to do here.”

Uncertainty Product a Key for SPP Reliability

The workshop mostly focused on the SPP Holistic Integrated Tariff Team’s work to integrate the growth of renewable energy, boost reliability, and improve transmission planning and the wholesale market. (See SPP Board Approves HITT’s Recommendations.)

Bill Grant, regional vice president of regulatory and strategic planning for Xcel Energy’s Southwestern Public Service, joined a panel of SPP members in explaining the HITT’s recommendation to develop an uncertainty product as “the art of dispatching.”

“We can handle the system a little differently if we have certainty,” said Grant, a former control center manager. “We have to develop tools for operators so they can react when there are any questions about the [generation] forecast.”

The HITT listed the uncertainty product as an “other reliability service,” which include new technologies that change the “underlying nature of grid operations that are not traditional operator tools.”

Grant pointed out that SPP’s market protocols and rules limit the flexibility dispatchers have to work with. However, the flexibility, or uncertainty product, is also needed as variable renewable generation takes a larger share of the fuel mix.

“Developing the uncertainty model will help us better learn about the market,” said Nebraska Public Power District’s Tom Kent, who chaired the HITT.

— Tom Kleckner

February 16, 2020

MISO Estimates up to $4B in 2019 Benefits

By Amanda Durish Cook

MISO saved members between $3.2 billion and $4 billion over the course of 2019, the RTO said last week.

The savings could be attributed to “enhanced reliability, more efficient use of the region’s existing assets and a reduced need for new assets,” MISO said in its annual Value Proposition study, which compares benefits of RTO membership against going it alone on the grid.

The estimated value to members was partially offset by $296 million in MISO administrative costs.

The savings are nearly identical to 2018, when MISO estimated it delivered between $3.2 billion and $3.9 billion in benefits to members. (See MISO Claims up to $3.9B in 2018 Benefits.) The RTO said it has documented nearly $27 billion in member benefits since 2009.

MISO executives discussed the most recent customer savings estimates during a special conference call Friday.

“Value Proposition on Valentine’s Day. Nothing could be more appropriate,” Executive Director of Market Operations Shawn McFarlane had joked at the Market Subcommittee meeting Feb. 6.

MISO said the lion’s share of last year’s value — $3.1 billion — could be chalked up to a diminished need for more grid assets. Those savings were further broken down to $415 million to $477 million from MISO’s wind generation integration, $154 million to $261 million from its demand response program and $2.2 billion to $2.7 billion from its vast geographic footprint.

Improved reliability accounted for a $405 million in savings, while a more efficient use of the footprint’s existing assets accounted for another $374 million, consisting of savings from more efficient dispatch ($283 million to $313 million), regulation reserves ($49 million to $54 million) and spinning reserves ($23 million to $25 million).

“The benefit of our large footprint is peaks occur at different times,” said Leonard Ashley, MISO senior business adviser of strategy and business development, adding that hot weather doesn’t often occur simultaneously in Indiana and the Dakotas, allowing the RTO to more easily distribute supply.

February 16, 2020

NERC: 2019 ‘Pivotal’ Year for ERO Enterprise

By Holden Mann

In its annual report, NERC cast 2019 as a “true pivot point” for the ERO Enterprise, thanks to initiatives aimed at improving the effectiveness of the organization and sharpening its focus on emerging challenges.

Consolidations Boost Efficiency, Engagement

The report highlighted several moves to reorganize the operation of the ERO Enterprise, with the transition of the Western Interconnection to multiple reliability coordinators singled out as “a significant accomplishment for all new RCs, their customers … and the grid.” The dissolution of Peak Reliability in December 2019 capped an 18-month process that saw the former RC hand over its functions to West’s RC Transition Earns Plaudits.)

NERC also held up SERC Reliability’s takeover of the Florida Reliability Coordinating Council in July as an example of effective integration to improve grid reliability. (See SERC Rethinking Board After FRCC Integration.) NERC applauded SERC’s “dedication to working together with affected registered entities … resulting in a stronger, more reliable and more efficient region.”

NERC ERO Enterprise — NERC CEO Jim Robb | © *ERO Insider*

High-level organizational changes were featured as well, including formation of the ERO Enterprise Executive Committee. NERC CEO Jim Robb said the committee, comprising the ERO’s senior leadership team and the CEOs of the regional entities, can “symbolize and operationalize” the organization’s commitment to respecting the independence of REs while working together toward a “common mission of assuring a reliable and secure bulk power system.”

NERC also touted the formation of the Stakeholder Engagement Team in May, which set in motion the creation of the new Reliability and Security Technical Committee (RSTC) to replace several existing bodies. (See Three NERC Committees Likely to Merge.)

Emerging Risks Highlighted

The organization’s work raising awareness of new risks garnered attention too, with its efforts divided into four key areas: grid transformation, extreme natural events, security risks and critical infrastructure interdependencies.

Security was the highlight of some of NERC’s biggest events in 2019. The most obvious example was the GridEx V security exercise in November, which featured the participation of more than 7,000 security professionals from nearly 530 industry and government organizations, 29 FBI field offices and 26 state governments. (See GridEx V Throws New Tech Curveball.) October’s GridSecCon 2019 provided opportunities for physical and cybersecurity experts to share knowledge on drones, insider threats, supply chain risks and a range of other topics. (See Overheard at GridSecCon 2019.)

Less visible, but equally important, was NERC’s behind-the-scenes work creating a base for knowledge-sharing and cooperation by players in the ERO Enterprise and industry. The Electricity Information Sharing and Analysis Center (E-ISAC) notched several key milestones last year, with the appointment of new CEO Manny Cancel and new information-sharing agreements with the natural gas, oil and water sectors, as well as state and local governments. (See Former Con Ed Exec to Lead E-ISAC.)

The organization also made progress in updating its reliability standards to address supply chain security risks, along with creating plans for recovery from an electromagnetic pulse attack. Task forces focused on each of these areas saw NERC’s Board of Trustees adopt their recommendations at its most recent meeting. (See “EMP, Supply Chain Recommendations Approved,” NERC Board of Trustees Briefs: Feb. 6, 2020.)

Knowledge Base Expansion Continues

Finally, NERC continued to develop its picture of the overall reliability landscape through the 2019 Long-Term Reliability Assessment, which predicted short-term challenges with resource adequacy in some regions but found opportunities for utilities in a changing resource mix. (See NERC Seeks Resilience Metrics, Focus on Resource Shifts.)

“NERC’s mission to enhance the reliability and resilience of the North American grid requires constant vigilance in the face of dramatic industry change and the emergence of new threats by bad actors,” board Chair Roy Thilly said. “I am pleased to report that NERC, together with industry and the regions, continues to be successful in meeting this important responsibility.”

February 16, 2020March 12, 2025

ORS Briefs: Feb. 11, 2020

NERC has finished transitioning to the latest version of its situational awareness tool and plans to introduce it to reliability coordinators once the vendor developing the system has implemented new modeling software, the vendor’s CEO told the ERO’s Operating Reliability Subcommittee on Feb. 11.

Michael Legatt, CEO of ResilientGrid — the Austin, Texas-based developer of Situational Awareness for Situational Awareness Tool Nears Rollout.)

Michael Legatt, ResilientGrid | © ERO Insider

Additional features being added to the tool include separate views for RCs, FERC and the ERO Enterprise, along with advanced data visualization tools incorporating a range of information such as substation performance, space weather, gas pipeline availability and fire tracking.

“We’re building a process that will allow you, the RCs, at very little manual work other than review, to continue to push updated model information into SAFNR v.3,” Legatt said. “Therefore, the impact to the RCs will be lower, and the accuracy of the tool will go up significantly.”

SAFNR v.3 went live for NERC and the ERO Enterprise in December 2019. Darrell Moore of NERC said that the tool will be rolled out to remaining stakeholders after ResilientGrid finishes building models with updated information from the RCs.

Clarity Sought on IROL Exceedance Metric

The task force revising the metric for identification of interconnection reliability operating limits (IROLs) brought two recommendations to the subcommittee for feedback: to ensure consistency in reporting by requiring operators to report all IROL exceedances with no operating margin added, and to change the threshold for reporting from 10 seconds to one minute.

“As the ORS is kind of our [forum] to talk to subject matter experts, we want your feedback on the proposed changes — should we start taking the steps to make this modification so that we can have a better, more valuable metric?” asked Maggie Peacock, manager of advanced analytics at SERC Reliability and chair of NERC’s Performance Analysis Subcommittee.

Several members of the subcommittee urged the task force to address what they saw as a lack of clarity in the recommendations. In particular, John Norden, director of operations at ISO-NE, said the metric should be clear as to whether it includes any buffer an operator has built into its system.

“It probably should be consistent, because the last thing we want to do is give doubt to an operator,” Norden said. “[If] you have a 1,000-MW transfer limit as your limit, and the operator gets to 28 minutes and he’s at 1,050, should he take action to get below 1,000 in the [last] two minutes, or should he say I have a buffer? … The limit’s the limit, as far as I’m concerned, and that’s what you should operate to, whatever you put in front of the operator.”

Members Object to RCIS 2021 Development

The group developing the successor to the Reliability Coordinator Information System (RCIS) is currently working on a request for proposals. It hopes to choose a vendor by the second quarter and introduce the tool by early next year.

Chris Pilong, PJM | © ERO Insider

Creation of the new software, called RCIS 2021, is being conducted by the Eastern Interconnect Data Sharing Network (EIDSN), a group created in 2014 to further develop industry tools that NERC has decided it no longer wants to maintain. NERC initiated the project in 2017 to replace the current RCIS with a more modern architecture and provide a common platform for instant communication between RCs, as well as between RCs, NERC, and transmission owners and operators.

Some at the meeting raised strong concerns about a perceived lack of input from Western operators into the system, as EIDSN is composed of representatives from the Eastern and Quebec interconnections. These were amplified when EIDSN Executive Director Jim Schinski said that use of RCIS 2021, which is required by several NERC standards, will be subject to a fee paid to EIDSN.

“Speaking for my company, and I think for others, we’re going to have some strong objections to that,” said Tim Beach, director of reliability coordination at RC West. “Because you’re [requiring] us to participate … and pay, with no control over requirements or cost in the future.

“I understand the tool needs to be replaced. Full agreement with that. … But the process of getting there and the requirement to use it seems a little upside-down to us in the West,” he added. [Editor’s Note: A previous version of this article mistakenly attributed this quote to Tim Reynolds, manager of event analysis and situation awareness for the Western Electricity Coordinating Council.]

Richard Mandes of EIDSN told members that “they’re paying for that functionality today through NERC” and that the fee paid to EIDSN would cover the same services they are getting now. He also promised that members would have an opportunity to provide input into the design of the system through NERC before it is introduced.

— Holden Mann

February 16, 2020

Spotty EV Growth, TOU Enrollment Challenges States

By Rich Heidorn Jr.

WASHINGTON — If they build it, will you drive?

Electric vehicle makers are now offering 90 models for sale in the U.S., and the nation’s charging infrastructure grew by 17% last year, according to data released last week by BloombergNEF.

Yet U.S. EV sales dropped 11% in 2019, accounting for just 1.8% of total vehicle sales, Bloomberg reported.

Nevertheless, state regulators said during a panel discussion at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit last week they remain upbeat about the potential for vehicle electrification to help decarbonization efforts — and maybe reduce system costs.

EV Growth — The number of public and workplace EV charging points rose 17% to 71,000 in 2019. Through 2018, about one-third of the EV chargers were in California. Most EV charging, however, is done at home. | *BloombergNEF*

“This is a really exciting time to talk about EVs,” said Al Freeman, an adviser for the Michigan Public Service Commission, who keeps a very busy Google alert to keep track of industry developments.

Michigan’s utilities have made “some really neat [pilot] proposals” to the commission, he said, including $13 million, three-year pilots by both Consumers Energy and DTE Energy, which were approved by the commission last year.

“There’s a lot of challenges, but they’re responding to it very well and being aggressive in the marketing and the education of it,” he said of Consumers. DTE has been similarly aggressive, he said. “A lot of their costs have come in below what they estimated, which will allow them to have a little bit more money for additional rebates.”

2 Questions

Hanna Terwilliger, economic analyst for the Minnesota Public Utilities Commission, said EV growth is outpacing rooftop solar in her state, although enrolling owners in time-of-use rates remains a key challenge.

Terwilliger said Minnesota is seeking to integrate EVs in a way that benefits all customers and avoids adverse system impacts. It’s also considering whether it should encourage widespread adoption of EVs to meet policy goals, such as carbon reductions.

“Each state will have different answers to these questions, but we all need to … make sure we’re prepared because … even just one EV charging at a house can double their electric consumption, and they’re coming faster than other types of [distributed energy resources] like rooftop solar,” she said.

Americans have purchased or leased 1.4 million battery-electric and plug-in hybrid electric vehicles since 2010, according to BloombergNEF. Minnesota has about 10,000 EVs, most in its metro areas but with some penetration in rural areas as well.

But while the Dakota Electric Association has almost half of their EVs enrolled in TOU or off-peak rates, Minnesota Power, Otter Tail Power and Xcel Energy have struggled to get participation above 10%. Terwilliger said a big challenge is the expense of installing a second TOU meter.

Asked to explain the disparity, Terwilliger noted that Dakota is an electric cooperative. “Anecdotally, from other co-ops that have similar rates, they’re also around 50%,” she said.

“There’s a number of reasons why co-ops have been more successful. They historically have had a lot more demand-response programs, and they’ve been able to expand those programs to include EVs. So, a lot of the infrastructure is already there. It’s less expensive to enroll customers in the rate. I think that co-ops also have a lot more direct communication with their members. Members want to read the newsletters that come out, versus if you’re trying to [communicate] something on a bill insert, there’s a lot of times people just throw it away.” Some customers get electronic bills and don’t receive bill inserts, she added.

She said utilities must enroll EV drivers in some type of managed charging rate when they purchase their cars. “Even if it’s not perfect, it’s much easier to switch a customer to more sophisticated program than it is to try and go and find them” after the sale.

It’s also important to have the rate structure ready to accommodate and encourage fleets switching to EVs, she said, noting Amazon’s plan to purchase 100,000 EV delivery vans, reportedly the largest EV order ever. “When they start coming into your service territory, Amazon does not want to wait for you to go through a regulatory process. They want a good solution there right now that’s going to save them money.”

Red State Message

Georgia PSC Vice Chair Tim Echols | © *RTO Insider*

Tim Echols, vice chair of the Georgia Public Service Commission, lamented that his state in 2015 abolished the $5,000 tax credit that had made it one of the early leaders in EV growth. He said the credit died because messaging about EVs’ environmental benefits took “all the oxygen in the … room.”

“I’m on my fourth EV. I’m a big proponent. But we’re making a switch [in messaging]. We have five Republican commissioners. Every constitutional officer in Georgia is a Republican. And we’re beginning to talk about how EVs charged at home overnight put downward pressure on rates. That’s the new red state message. Nothing else about the environment, because our left-leaning friends are going to come with us no matter what. … It’s the Republicans that are holding us up on this.”

February 14, 2020

State Regulators Endorse IEEE DER Standard

By Rich Heidorn Jr.

WASHINGTON — State regulators this week endorsed Institute of Electrical and Electronics Engineers’ updated standard 1547-2018 on the interconnection and interoperability of distributed energy resources.

The National Association of Regulatory Utility Commissioners’ board of directors approved a resolution Wednesday recommending state commissions adopt the standard. The vote came at NARUC’s Winter Policy Summit, where cybersecurity and reliability were the subject of numerous discussions. (See Cybersecurity, Resilience Talks Highlight NARUC Meeting.)

Published in April 2018, IEEE’s standard requires DER to perform grid-support functions for voltage, frequency, communications and controls “to ensure that increasing levels of DERs are reliable at both the distribution and bulk power system levels, and can be visible to grid operators,” NARUC said.

IEEE DER Standard — Ryan Quint, NERC; Jay Liu, PJM; and Michelle Rosier, Minnesota PUC, listen as Michael Ingram, NREL, discusses IEEE’s DER standard. | © *ERO Insider*

DER equipment compliant with the standard is expected to be available next year.

“Delaying implementation of IEEE 1547-2018 could result in new DERs being connected to the grid using legacy technical requirements and standards that could prevail for the duration of the DER’s lifetime,” NARUC said. “Significant logistical and legal barriers exist to modifying DER interconnection requirements post-installation, such that it is preferable to apply the desired DER configuration at the time of initial DER installation.”

NERC also backed the standard in a draft reliability guideline and the Electric Power Research Institute, National Renewable Energy Laboratory, Regulatory Assistance Project, Interstate Renewable Energy Council and National Rural Electric Cooperative Association have produced resources to help states implementing the standard, which will require integrating it into interconnection tariffs.

During a panel discussion on the standard Sunday, Ryan Quint, NERC’s senior manager of advanced system analytics and modeling, said planners and real-time operators in North America are currently relying on estimates of DER because of a limited information.

“Under low-penetration conditions, it’s a reasonable estimate,” he said. But he added that CAISO is growing increasingly concerned “because it has so much behind-the-meter generation that is not readily visible. Those forecasts are getting a little less solid, and they’re getting faced with new challenges because they don’t have the knobs that they used to be able to turn.

“If they’re already having problems, and they have requirements that every new rooftop [in California] must have a mini solar plant on it that we can’t see and can’t control,” problems will increase, Quint said. “We don’t necessarily need to control those things, but making sure they meet requirements and are tracked, and we know where they are and we can forecast them into the future — those things become really important.

“We’re going to need to change the paradigm of the way we operate the overall grid into the future,” he continued. “In North America, we’re not so sure how we’re going to do that. In Europe, for example, we have distribution system operators that coordinate a lot of this at the distribution level that are running real-time tools like the grid operator is doing.”

February 14, 2020

NARUC Advised to Consider Liability in Cybersecurity

By Michael Brooks

WASHINGTON — A panel at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Monday on the cybersecurity of natural gas infrastructure waded into the world of insurance.

Brian Finch, a partner with Pillsbury Winthrop Shaw Pittman, provided NARUC’s committees on Telecommunications, Critical Infrastructure and Gas with a stark reminder that it’s a matter of when, not if, a cyberattack on critical infrastructure occurs.

“The Defense Department, the Intelligence Community, the National Security Agency — all of whom spend billions of dollars on an annual basis to implement cybersecurity, have some of the smartest minds in the world working on their problems — have a saying: ‘We’ve learned to live with the adversary on the system.’”

The government expects U.S. enemies to penetrate every major defense and weapons system on a daily basis, Finch said, and there’s nothing it can do to prevent it. So too is it with the country’s energy systems.

“There’s no such thing as the elimination of the cyber risk. We are always, always vulnerable, and no matter what we you’ve done, there will always be another methodology, another way to bring risk and effectuate harm.”

Therefore, Finch argued, regulators should consider liability when crafting their requirements for how utilities manage their risk against cyberattacks.

“Sometimes the presumption is that if there is a successful cyberattack, someone must have failed somewhere,” Finch said. “When something does go wrong, is someone liable? … That’s a challenge that you as commissioners … need to contemplate on a daily basis. Is it really someone’s fault that a successful cyberattack occurred? Or should you be looking at, was it one that was inevitable, and did they recover in a sufficient amount of time? …

“We have to make sure that we’re not unintentionally creating new avenues of liability that would unfairly place the blame on entities who, in reality, could do nothing to stop, say, a foreign military.”

NARUC cybersecurity liability — From left to right: Alaska Regulatory Commissioner Robert Pickett; Indiana Utility Regulatory Commissioner Sarah Freeman; Suedeen Kelly, Jenner & Block; Zoe Cadore, American Petroleum Institute; Sharla Artz, Utilities Technology Council; and Brian Finch, Pillsbury Winthrop Shaw Pittman | © *ERO Insider*

Finch encouraged commissioners to look at the Support Anti-Terrorism by Fostering Effective Technologies (SAFETY) Act, signed into law in 2002 in the aftermath of the Sept. 11 terrorist attacks. Among other provisions, the law provides legal liability protections for providers and users of anti-terrorism technologies that are qualified by the Department of Homeland Security.

He noted that law doesn’t cover penalties administered by state agencies, “but it does minimize the likelihood of civil liability.” Finch’s bio on Pillsbury’s website notes that “he has helped more than 150 clients take advantage of SAFETY Act liability protections following terrorist or cyberattacks.” He said that of the estimated 350 entities that have been given protection, he’s aware of only two that for utility security programs.

Alaska Regulatory Commissioner Robert Pickett brought up the surge in ransomware attacks on municipalities last year, ranging from major cities such as Atlanta and Baltimore, to small towns across the country. Pickett said his own community was attacked, costing it about $4 million to $5 million, but their insurance coverage “was totally different from what the people thought they had.”

That prompted Finch to repeat an anecdote he heard from a friend: “‘If you’ve seen one cyber insurance policy, you’ve seen one.’

“There’s no standardization in the industry. Coverage varies widely depending on who you are, what you have to offer and how much you can pay,” he said.

Finch recalled the NotPetya attack of 2017, the victims of which included food producer Mondelēz. Because the perpetrator of the attack had been determined to be the Russian government, the company’s insurance provider did not cover the damages because it was an act of war.

Kansas Corporation Commissioner Dwight Keen asked to what extent are cyber threats state-sponsored, and which countries posed the most threats. Finch listed North Korea, China, Russia and Iran.

But Finch warned that attribution was almost irrelevant when it came to managing risk. He recalled the story of the Russian hacking group known as Turla. The NSA and the U.K.’s Secret Intelligence Service (MI6) had been tracking what they thought were a group of Iranian hackers for 18 months until they realized that the group was actually Russian: Turla had breached an Iranian hacking group and stolen their code and cyber tools to masquerade as them.

February 14, 2020

Industry Bullish on Digital Tech, Despite Risks

By Holden Mann

MANHATTAN BEACH, Calif. — NERC and utility operators see considerable benefit from applying digital technologies to the power grid, but adopters must take their vulnerabilities into account as well.

During a panel on digitization at NERC’s Member Representatives Committee meeting on Feb. 5, moderator Sylvain Clermont, director of operational technologies convergence at Hydro-Québec TransÉnergie, said operators are only scratching the surface of the long-term implications of new technologies — both positive and negative. Even at this early stage, the capabilities are too enticing to ignore.

“Most of us have started some kind of digitization of our grid and our facilities, but we are at the beginning of trying to see all the potential of that,” Clermont said. “Now you can access a relay … from any kind of control center. … So we will change the way we do maintenance by having all that data.”

Reward and Risk

However, participants in the panel also raised familiar warnings that bringing in smarter systems can also mean inviting unwanted guests. In the case of new hardware like drones, that could involve backdoors engineered by the manufacturers. Communication software can also contain inadvertent vulnerabilities that can be exploited by a growing list of unscrupulous actors targeting U.S. utilities. (See Report: Oil, Gas Hackers Expanding to Grid.)

NERC Digital Tech — Left to right: Howard Gugel, NERC; Eric Udren, Quanta Technology; Mukund Kaushik, Southern California Edison | © *ERO Insider*

Mukund Kaushik, director of digital at Southern California Edison, observed that most utilities are well aware of the risks of introducing new technology into their systems. At the same time, those who want to provide better service to their customers or keep their performance in line with the broader industry may feel they have no choice but to upgrade and address the risks that might arise as they go.

“Most of the innovation that’s happening on the IT side is happening on the cloud,” Kaushik said. “I’m constantly going back and forth [with] my cyber team in terms of how do we make sure we’re not compromising our security, but at the same [time] take advantage of some of the technology that exists out there to move the ball forward.”

Evolving Cybersecurity Threats

The danger of cyberattacks was a major focus of discussion, with Eric Udren, an executive advisor at Quanta Technology, admitting that “the adversaries will always be getting better at this.” However, utilities cannot become so focused on security risks that they fail to adopt new technologies to address a rapidly changing generation environment.

“There are some that would say — from a knee-jerk reaction — ‘Well, because of the cyber exposure of a microprocessor-based relay, let’s go back,’” said Howard Gugel, vice president and director of engineering and standards at NERC. “But there was a reason why we went to microprocessor-based relays. … In the ‘good old days,’ we were flying in the dark a lot of times.”

Gugel pointed out that security is only one challenge posed by integrating digital communication into the grid. Distributed energy resources such as rooftop solar panels and batteries are made possible by such technologies, but they have also been found to cause significant issues with monitoring and planning for grid stability. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)

In light of these emerging concerns, panelists agreed that NERC will need to move quickly to establish standards and procedures to ensure reliability and safety. At the same time, the ERO Enterprise must ensure that entities have the flexibility needed to pursue future innovations.

“In all new reliability standards, we should be thinking not only about what is the problem we’re solving now, but what will the industry be like in 10 or 20 years, and what are we putting in this standard that would not inhibit a direction that we see coming?” Udren said. “By all means, solve the current problem, but look ahead also.”

February 14, 2020

Northern Focus for MTEP 20

By Amanda Durish Cook

MISO will sharpen its focus on the northern portion of its footprint with two supplemental studies to be included in its 2020 Transmission Expansion Plan (MTEP 20) cycle.

The RTO has planned special transmission studies for both Michigan and the Minnesota-Wisconsin border, both of which it discussed at the Planning Advisory Committee’s meeting Wednesday.

MTEP 20 will contain a special study into the increasingly tight capacity import and export limits (CILs/CELs) in lower Michigan’s Zone 7. The study is being performed at the request of the Michigan Public Service Commission and will help the state “better understand the effects” of increasing either the CIL or CEL for Zone 7, according to MISO.

Tony Rowan, MISO senior manager of seasonal and generator deliverability, said decisions to move ahead with any projects to increase Zone 7’s CIL and CEL values would be up to transmission owners and the state, not RTO staff. He said the study “will help Michigan to meet it reliability goals and evaluate the potential costs and benefits of increased CILs and CELs.”

Zone 7 has a preliminary 3,200-MW CIL for the 2020/21 planning year, a five-year low. Last year, the zone had a 1,358-MW CEL, down from 2,578 MW in 2018/19. For the 2020/21 planning year, MISO’s analysis could not identify a CEL, officially listing it as “no limit found.”

As requested by the Michigan PSC, MISO will examine 500-, 1,500- and 3,000-MW incremental increases to the Zone 7 CIL. The RTO expects to have results by November.

MTEP 20 — Zone 7 requirements 2016-2021 | *MISO*

PSC Commissioner Dan Scripps said that while the commission only requested MISO investigate lower Michigan, Zone 2 (Wisconsin and the Upper Peninsula) and Mississippi’s Zone 10 also have narrow limits that could be ripe for study.

MISO staff late last year said Zones 2 and 7 are the closest to being unable to meet their local clearing requirements based on results from the RTO’s 2019 resource adequacy survey with the Organization of MISO States (OMS). (See MISO Planning Reserve Margin to Climb in 2020.)

WEC Energy Group’s Chris Plante asked whether the PSC’s study request could strain MISO planners, wondering what would happen if several other stakeholders requested one-off studies.

“At what point does this become a burden on MISO’s resources?” he asked.

“We’ll let you know,” MISO Director of Planning Jeff Webb joked, then adding more seriously that the RTO will monitor its ability to accommodate targeted study requests. He said MISO might one day institute “a global import study of all zones.”

“We have a special place in our hearts for state regulators, and when they ask, we try to do our best to accommodate them,” Webb said.

Indiana Utility Regulatory Commission staffer David Johnston also pointed out that OMS rarely exercises its right to request studies from MISO.

Meanwhile, MISO will hold a special meeting at the end of the month on its special analysis of the Minnesota-Wisconsin export (MWEX) interface limitation.

The MWEX transfer limit is the subject of another special MTEP 20 study, dubbed the North Region Economic Transfer Study. MISO said it’s expecting “bottle necks” especially in its North Region, which already contains high wind penetration. (See MWEX Study Could Elicit New Tx Planning for MISO.)

MISO has scheduled a Feb. 28 workshop for a technical discussion of the study’s assumptions and scope.

“Our focus here is to really study how this constraint limits economic dispatch,” MISO Resource Interconnection Planning Manager Neil Shah said.

MTEP 20 Schedule Change

The approval of MTEP 20 will also be held to a different timeline than in previous years.

MISO Project Manager Sandy Boegeman said the RTO will this year revise the schedule to allow the Board of Directors’ System Planning Committee more time to review the MTEP package prior to the full board vote in early December.

That means the PAC will also review, then vote on, whether to recommend the draft MTEP 20 report about a month earlier than usual. MISO plans to post the report on Aug. 19 instead of the usual mid-September. The PAC vote will move up to the committee’s Sept. 23 meeting instead of mid- to late-October.

Finally, the System Planning Committee will decide whether to advance the MTEP 20 report to the full board on Oct. 26 instead of late November.

February 14, 2020March 12, 2025

NYISO Business Issues Committee Briefs: Feb. 12, 2020

NYISO can import 505 MW above grandfathered rights from its neighboring control areas for capability year 2020/21, with 332 MW available from ISO-NE and 152 MW from PJM, under the revised installed capacity (ICAP) values approved by the Business Issues Committee on Wednesday. Quebec and Ontario can add another 21 MW.

Including existing transmission capacity for native load, and other grandfathered rights, the ISO’s biggest import sources are PJM (1,232 MW) and Quebec (1,116 MW).

The individual limits allowed under the ISO’s MARS simulations were prorated to ensure they do not violate the loss-of-load expectation criterion. All of the resulting imports were deemed deliverable, said Frank Ciani, of NYISO’s capacity market operations unit.

NYISO can import 505 MW above grandfathered rights from its neighboring control areas for capability year 2020/21, with 332 MW available from ISO-NE and 152 MW from PJM. The grandfathered rights include existing transmission capacity for native load. | NYISO

The analysis excluded interface facilities with unforced capacity deliverability rights, controllable lines from PJM into the New York Control Area and the Northeast Utilities Service Co. 1385 line.

The BIC approved a motion to update Section 4.9.6 of the Installed Capacity Manual to reflect the results without opposition or discussion during the brief meeting.

The revised limits represent an increase of 62 MW over 2019/20, with PJM’s limit increased by 120 MW and Ontario’s reduced by 113 MW. The summer capability period strip auction opens March 30.

Transmission Congestion Contracts

In its only other action, the BIC approved revisions to the Transmission Congestion Contracts Manual, which was last updated in 2017.

The revisions add the historic fixed-price transmission congestion contracts extension product and incorporate technical bulletins on the PJM-NYISO interconnection scheduling protocol and modeling of the Rainey and Blissville phase-angle regulators.

– Rich Heidorn Jr.