Three years into the project to replace its market platform, MISO is now set to begin moving information to its new private cloud to begin testing.
MISO Director of Digital Delivery Foundations Kevin Larson said the RTO has completed much of the platform design work this year and will next year focus on upgrading technology infrastructure. He said it is making sure the platform is adaptable.
“We’re focused on the performance of the day-ahead clearing of the market engines: How fast can we do that with all the new [market] products and services?” Larson told stakeholders at a Market Subcommittee meeting Thursday.
He said MISO’s motto regarding the new cloud-based platform is “continuous integration, continuous delivery,” allowing for more regular improvements instead of “a few big deployments infrequently” using the existing server-based platform.
“As we look into 2020, we’re going to start migrating applications to the MISO private cloud,” Larson said. (See New MISO Platform Headed to the Cloud.)
MISO still expects to announce its preferred vendors on the platform build by the end of the year. So far, General Electric is still the major vendor.
“We’ve now had some early software deliveries for testing, and it’s been solid,” Executive Director of Digital Strategy Jeff Bladen told the Board of Directors in September.
Bladen said the quality of the software was up to MISO standards, and GE’s performance was much improved from its earlier delays. Board members at the time were pleased with the turnaround. (See “Vendor Delay on Market Platform Replacement,” MISO Board of Director Briefs: June 20, 2019.)
“We’re pleased to say early results are quite positive and encouraging,” CEO John Bear reported at the Oct. 22 Informational Forum.
MISO executives will deliver another market platform update at the Dec. 12 board meeting in Indianapolis.
ATLANTA — NERC’s briefing on its revised ERO Enterprise Long-Term Strategy last week prompted a discussion on whether it is feasible to apply cost-benefit analyses to reliability standards.
“We’ve been struggling with that issue for a while,” Hydro-Québec’s Sylvain Clermont said during the discussion at the Members Representative Committee’s quarterly meeting. “It’s like an oasis in the desert. We know there is an oasis in the desert. We even think we heard someone who saw the oasis. But nobody can quite find the oasis.”
“This is a really tricky area,” NERC Board of Trustees Chair Roy Thilly said. “Every survey we have done points out that stakeholder concern that cost really be considered in the standard [development] process.”
But doing a formal cost-benefit analysis before implementing a standard is difficult, Thilly said. “The effect on one entity may be very different than the effect on another entity, given where they already are in dealing with the issue.”
Industry can help NERC determine the least-cost way to accomplish the goal of a standard, he said. And an after-the-fact review once there is experience with a standard may be possible. “There may be much better information” then, he said.
Cost Effectiveness More Realistic?
Clermont agreed that cost effectiveness may be a more realistic goal.
“If there are two ways to implement a standard, which is more effective than the other one? That’s perhaps an easier question than is there a [positive] cost-benefit or is there a business case to develop a standard,” he said. “I would say that there is most likely never a business case to develop a standard.”
NERC CEO Jim Robb said the ERO is aware of the industry’s challenge in funding improvements for security and resilience “against the backdrop of flat to no load growth in many jurisdictions.”
“Everyone, when they cast a vote for a standard or against a standard, is making their own assessment as to whether or not it’s worth the [cost]. I don’t think we ever want to get to the point where we have a big econometric department at NERC … but I think we want to make sure we are reaching out and getting input from industry so the work we do is economically informed, even though that’s on the fringes of our mandate.”
State/Municipal Utility sector representative Carol Chinn of the Florida Municipal Power Agency said it would be helpful to “have compliance in the room when standards are developed.”
“I think there’s a lot of unknowns when standards are approved about how can you comply with it. These things are complex. When you look at, for example, CIP-003 … it’s [effective] Jan. 1. What are the expectations for compliance? What do we need to do?”
The strategy document was revised following comments from six industry groups, which also included the Edison Electric Institute and the ISO/RTO Council. It is set to be brought to an endorsement vote at the board’s Dec. 12 conference call after input from regional entities.
‘Focus Areas’
The new plan is based on four “Enterprise Value Drivers”:
Organizing and deploying top talent.
Developing and delivering innovative and risk-based programs and tools.
Collaborating effectively with industry and other stakeholders.
Maintaining independence and objectivity.
It identifies five “strategic focus areas”:
Expand risk-based focus in all standards, compliance monitoring and enforcement programs.
Capture effectiveness, efficiency and continuous improvement opportunities.
Assess and catalyze steps to mitigate known and emerging risks to reliability and security.
Build a strong, Electricity Information Sharing and Analysis Center-based security capability.
Strengthen engagement and collaboration across the reliability and security ecosystem in North America.
“We recognize that the electric system as it is today isn’t our grandfather’s electric system. … Lots of changes [are] coming at us in a lot of different directions,” Robb said. “So we always need to be thinking about … whether the programs we execute — many of which were designed 10 to 12 years ago — are still the right programs.”
The goal, he said, is “keeping eyes on the big issues [and] not getting distracted by the trivial.”
“Many of the things that we do have their roots in not only reliability and security but also … the resilience of the system, so you’ll see more references to resilience in the new document” than the 2017 strategy document it will replace, Robb said.
Funding
Andy Dodge, director of FERC’s Office of Electric Reliability, asked about the new plan’s reference to investigating “funding mechanisms” to support NERC’s mission.
The ERO Enterprise “Golden Circle” | NERC
Robb said that was a “placeholder” for potential programs that could be structured like the Cybersecurity Risk Information Sharing Program, which is funded by industry and the Department of Energy rather than the Federal Power Act Section 215 assessments that fund the ERO’s operations.
“A number of important issues that get identified in our various assessments … end up with a recommendation that says someone should do X and someone should do Y. And in many of those cases, we don’t really have any ability for establishing accountability as to who’s actually [going to] get it done,” Robb said.
“For example: new planning models … that would be necessary to address variability of resources on the system. … That’s not something we have the expertise to do in-house ourselves, but it’s something that’s very important to be developed,” Robb continued. “Maybe four or five entities would like to push that forward.
“That’s kind of the notion. It’s really not much more developed than that.”
Representatives from utilities, RTOs, technology vendors and researchers gathered at FERC headquarters in D.C. last week for a staff-led workshop to discuss the role of grid-enhancing technologies (GETs) in transmission planning and operations and explore how FERC can help the industry address challenges related to their deployment (AD19-19).
FERC Commissioner Richard Glick
GETs include power-flow control and transmission-switching equipment, storage, and advanced line rating technologies. Commissioner Richard Glick — the only commissioner in attendance — said he was struck by evidence that 20 to 50% of transmission capacity is going unused. He asked panelists the central question of the workshop: why “utilities haven’t adopted these tools, purchasing the hardware or software or deploying software, to improve power flow controls and manual configuration. Why haven’t we done more given the lack of use of the existing grid?”
It’s a “chicken and egg” problem that Washington State University professor Anjan Bose says FERC holds the power to fix, citing how the Department of Energy’s investment in phasor measurement units (PMUs) encouraged widespread use of the technology.
“FERC has to encourage some of these solutions” he said. “Some of the needs have to do with reliability and security and not just decreasing congestion at this one point. That’s something FERC can do. If it is needed for the reliability of the system, FERC has the ability to require it.”
“One of the challenges we have is getting detailed models because vendors don’t provide it because it’s proprietary,” said Robert Bradish, vice president of transmission planning and engineering for American Electric Power. He explained that equipment failures force the utility to send the unit back to the manufacturer for repairs, rather than completing them itself. He said FERC should give operators access to this information, “so we can get insight into the actual workings of technology.”
“Given our responsibility for keeping the lights on, we believe it’s prudent for us to have a conservative risk posture when deploying new technology,” he said. “Once you get a technology that’s out there; that’s proven; that’s got performance metrics around it; that’s got cost benefits around it, then you can get deep into analysis and consideration of it.”
Hudson Gilmer, LineVision
GETs — like transmission line monitoring — could help system operators keep track of damaged or aging infrastructure instead of relying on annual foot patrols, LineVision CEO Hudson Gilmer said.
“I want to touch on the safety benefits of these technologies and transmission line monitoring in particular,” he said. “I’m sure everyone is aware of recent events in the wildfires and the power shutoffs that we would argue largely occurred because of unmonitored power lines.” (See PG&E Stock Plummets amid Wildfires, Shutoffs.)
Gilmer said technologies like the kind his company manufactures gives operators the ability to continuously monitor transmission lines and detect anomalies caused by age, clearance violations, blowouts and icing, among others, and “ultimately improve the safety and reliability of the grid.”
The societal benefits of GETs tend to outweigh the financial benefits, Bose said.
“Most of the cost justifications that are being used today to put in these technologies are on the basis of transmission, the cost of market utilization and so on,” he said. “The major advantages mentioned — reliability, flexibility, security — there are no cost benefits of that to stakeholders. There’s a lot of cost benefit to society, which is why we want this.”
TO Incentives
Some panelists at the conference said sweetening the deal will ease transmission owners’ hesitance to adopt GETs.
“A large monopoly entity makes most of its money investing big dollar capital into projects,” said Rob Gramlich, founder and president of Grid Strategies. “If it’s between that and an alternative, they will always choose that.”
Rob Gramlich, Grid Strategies
Gramlich, on behalf of the Working for Advanced Transmission Technologies (WATT) Coalition, proposed a program that would allow utilities to reap 25% of the shared savings to load from GET projects valued at less than $25 million that “provide quantifiable congestion-reduction benefits.”
Unlike resilience, reliability or safety, Gramlich said congestion can be measured and monetized. He said deployment incentives worked to increase wind and solar penetration, so it can naturally extend to GETs too.
“I think we’ve heard pretty resoundingly from the RTOs and transmission owners … [that] the RTOs aren’t going to tell the transmission owners what technology to put on their wires at any time,” he said. “I think we’ve crossed out all of the alternatives except incentives.”
Bradish said his company could accept the framework of the coalition’s proposal, but he cautioned against “picking winners and losers” when it comes to chosen technologies.
“I think this incentives concept is beneficial to moving the ball forward,” he said. “There needs to be some criteria around that definition so you don’t lock out certain types of technology and innovation.”
Michael Kormos, Exelon’s senior vice president of wholesale markets and energy policy, argued that while the coalition’s proposal focuses on the right metrics, it would “fall apart very quickly” in PJM’s competitive model.
“We may yearn for the days of more collaborative planning, but that is not what we have created,” he said. “It’s winner-take-all. It’s not just a matter of it’s OK if [the proposal] doesn’t hurt me — I don’t want my competitor to have it at all.”
Former FERC Chair Jon Wellinghoff, CEO of GridPolicy Consulting, proposed a program that allowed participants to vie for shared savings worth up to 50% of the congestion benefit realized. He said this approach moves utilities toward a more market-based solution.
“If we structure it as a competitive process, I think that takes it out of the realm of the TOs deciding,” he said. “It can be decided ultimately by the RTO or planning entity, and ultimately, anyone can come in with the best solution.”
Except, not all TOs like the specificity of either proposal.
“I get nervous when I hear very proscriptive things,” said Robert McKee, director of strategic projects at American Transmission Co. and representative of MISO’s TO sector. “‘It’s got to be under $25 million. It’s got to be this [grid-enhancing] technology.’ By proscribing that, you may be obviating a solution. Rather than proscribing what these projects should be, allow the entity to come in and propose something.”
Steve Leovy, Transmission Access Policy Study Group
Steve Leovy, of the Transmission Access Policy Study Group, disagreed that the WATT proposal “is the right solution” or that TO incentives will improve deployment at all.
“It doesn’t sound to me that the lack of incentives is the reason this technology isn’t being adopted,” he said. “I’ve heard a lot more about needing more confidence in new technologies. … Utilities didn’t need special incentive to get rid of copper conductors and start installing aluminum conductors. Technology changes and expectations and best practices should change along with technology. Putting incentives into this mix risks rewarding late adopters.”
Cost-sharing a Nonstarter?
Joe Bowring, president of Monitoring Analytics, PJM’s Independent Market Monitor, said transmission incentives such as cost-sharing programs are inherently flawed and “counterfactual.”
Joe Bowring, Monitoring Analytics
“The idea that you can provide an adequate incentive to a transmission owner to build a project that is 1/1000 the cost of a big transmission line is a nonstarter,” he said. “You cannot overcome that basic return on investment by offering TOs incentives for building cheaper alternatives.”
Bowring said using congestion as a metric fails to recognize that reducing it “is not always better.” Further, the variability of the bulk power system will lead to unreliable forecasting.
“You cannot forecast benefits,” he said. “The numbers are ultimately made up and the results are a variety of subjective assumptions. Cost-benefit analysis might be a good screening tool … but the idea that it’s an appropriate way to incent new technology is not correct.”
David Patton, Potomac Economics
David Patton — president of Potomac Economics, the IMM for MISO, ERCOT, NYISO and ISO-NE — agreed, saying that “the problem runs so deep with transmission owners that proposing some marginal incentive for GETs in some cases may work and, in many cases, won’t.”
“My biggest problem with it is, for the most economic GETs, it way under-incents the investments in those technologies,” he said. “You’re not going to be able to correct the incentive problem with the TOs.”
Even if RTOs and ISOs moved forward with the coalition’s proposal and provided the cost-benefit analysis for these GET projects, none of them believed the data would provide enough reliable information on which to base rates.
“The long-term responsibility for that being a valid number for a very specific forecast with a very specific set of outcomes … we would have trouble defending that ourselves as a credible value,” said Neil Millar, CAISO’s executive director of infrastructure development.
“Natural gas prices and transmissions outages are the main drivers of congestion,” said Yachi Lin, NYISO’s senior manager of transmission planning. “Neither of those can be forecasted with absolute certainty.”
FERC shouldn’t approve any additional processes for RTOs and ISOs to manage either, said Craig Glazer, PJM’s vice president of federal government policy.
“The WATT proposal is very thoughtful, but it calls for a whole new process … outside of the existing [Regional Transmission Expansion Plan] planning process,” he said. “One thing we don’t need is another process outside of that.”
Instead, Glazer asked the commission to consider a nationwide solution to deploying GETs, given the complexities of seams relations.
“If there is any topic that cuts across the RTO and non-RTO boundary, it’s this topic,” he said. “Whatever you do, apply it across the country.”
Glazer also asked FERC to “go on the record” and state its desire for system operators to consider deployment of GETs and create a record of possible strategies. He also wanted the commission’s guidance on how to get pilot programs operational. Finally, he asked FERC to reconcile some its existing policies related to Order 1000 and transmission incentives.
PJM and other RTOs could serve as a testbed for these new devices, Glazer said, and create a record of their own that details proven technologies that “add value but offer implementation challenges.”
Millar questioned the idea of a nationwide approach. “I’m not sure a one-size-fits-all solution is what’s needed,” he said. “We worry it risks a duplicative process of what we are already doing.”
Renewables Integration
Kicking off a discussion that explored how GETs can be incorporated into the transmission-planning process, Jeff Webb, MISO’s senior director of transmission planning and competitive development, said improving existing grid investments “is an important element in developing the most cost-effective transmission grid in both the near- and long-term planning horizons.”
Jeff Webb, MISO
Webb said advances in generation technologies and other drivers are increasing renewable integration “at a dramatic pace.” He pointed to “unprecedented” levels of wind and solar resources seeking interconnection.
“As the fuel mix of the fleet continues this evolution from carbon-based to renewable sources, these new inverter-based technologies put enormous stress on the transmission grid and bring new challenges to maintaining adequate and stable performance,” Webb said.
MISO’s regional planning process “can accommodate an all-of-the above approach to developing transmission solutions to meet needs, with input from the diverse stakeholder community,” he said. “At the present time, given the transformation in generation resources evident in MISO, enabling a substantial jump in bulk delivery capability is the much more pressing need.”
Drew Clarke, lead integrated planning coordinator for Duke Energy, said the company took a different approach to future planning in 2016, when it created an integrated system and operations planning strategy. Recognizing the “significant transformations underway,” he said Duke moved toward “a more holistic view of infrastructure investment, with the goal of modeling and evaluating options never contemplated before or [using] existing technologies in new ways.”
Energy storage is one technology gaining tremendous momentum, he said.
“One of the challenges is the uncertainty of how non-traditional solutions, such as energy storage, will be classified by regulatory bodies,” Clarke said. If energy storage is classified as a generator, “then the resource would need to go through the interconnection queue along with other generators. From a timing perspective, this could limit the feasibility of this alternative as a transmission or distribution solution, since traditional wires solutions would not be subject to this additional delay.”
“It’s important to recognize [that] different technologies and solutions might be more effective in different solutions. Give us the flexibility,” he said.
Exelon Senior Vice President of Transmission and Compliance Mike Kormos said most “nonconventional transmission technologies” are not at a scale to drive down costs.
“They’re getting better, but they’re not quite there,” he said. “[They] are difficult to compare to more conventional transmission alternatives. Some of these challenges may diminish with time as the costs of these new nonconventional technologies fall.”
Kormos said most of the GETs listed in FERC’s notice for the workshop would be ineffective in meeting reliability needs. Referring to dynamic line ratings (DLR) and some power-flow control technologies, he said they might help “alleviate congestion in some instances, but system planners may not be able to depend on them to meet reliability needs under current assumptions used in transmission planning.”
“System planners must plan for the worst-case scenario when these technologies may be ineffective, given outages on other transmission facilities or adverse ambient conditions,” Kormos said.
The competitive environment and the RTO/ISO transmission planning processes both present challenges to deploying GETs, he said, noting there is no easy answer.
“A utility must attempt to minimize costs and risks, even if that means forgoing opportunities to gain experience with technologies that, over time, will become more cost effective,” Kormos said. At that point, grid operators ultimately select the more cost-effective solution. “Here, the benefits and risks are not necessarily aligned,” he said. “The responsibility to make this determination is a responsibility that an RTO/ISO may not desire to assume.”
Babak Enayati, manager of technology deployment for National Grid, said that by integrating renewable energy, new technologies deliver low-carbon resources, reduce the cost to serve customers, improve asset management, reduce operation and maintenance expenses, and improve resilience.
He focused his comments on dynamic transformer ratings (DTR), substation automation and storage. Enayati said National Grid installed DTR technologies on two transformers in July, estimating more accurate megavolt-ampere power ratings. The company has also increased the deployment of digital substation technologies that lead to quicker and lower-cost substation construction with a smaller environmental footprint.
Thanks to a 6-MW, 48-MWh battery on Nantucket Island and other installations, National Grid has concluded that “energy storage can offer a variety of benefits and challenges,” Enayati said.
When paired with flow-controller devices, he said, battery storage “may be the least-cost solution to address case-specific reliability issues on the transmission network” and can provide voltage and frequency services.
However, some storage inverters are manufactured outside the U.S, creating cybersecurity issues, Enayati said, “and some RTO/ISO regional planning processes do not consider energy storage as a potential solution to identified reliability needs.”
Who Benefits?
Unused transmission capacity is a challenge that can be met with technology, said Swaraj Jammalamadaka, vice president of transmission at Apex Clean Energy.
“You have, just in PJM [alone], over 1,200 transmission facilities that are loaded less than 20%, so from a generation developer’s perspective, when we get hit with congestion in the market, it’s a little concerning to us that there are lines next to ours not loaded anywhere close to their capability but we still experience congestion in the market,” Jammalamadaka said.
There’s “definitely a lot of value” for equipment that can control or redirect power flow while increasing transmission adequacy and enhancing system reliability, he said.
(Left to right) Jack McCall, Lindsey Manufacturing; Swaraj Jammalamadaka, Apex Clean Energy; Pablo Ruiz, NewGrid; and Jeff Dagle, PNNL.
A GET most often works similar to transmission in terms of delivering benefits, so the company enabling the technology might not be the financial beneficiary, Jammalamadaka said.
Jeff Dagle of the Pacific Northwest National Laboratory said that while the cost of GETs has been coming down, historically there has been a cost barrier to implementing things like phase-shifting transformers that can redirect power flow on the network.
“A lot of times, the grid assets … are based on a post-contingency analysis,” Dagle said. “So during normal day-to-day operations, if you just look at the asset utilization, you might see relatively low numbers, but yet those resources are really designed and justified based on post-contingency situations.”
Other Perspectives
Jack McCall, executive vice president of California-based Lindsey Manufacturing, which provides DLR systems, said he favored DLR over ambient-adjusted ratings (AAR), which he thinks should not even be considered as GET.
“We recognize the familiarity, assumed simplicity of implementation and perceived low cost of AAR. However, AARs do not truly provide situational awareness — merely a perception of awareness,” McCall said.
Pablo Ruiz, NewGrid
Pablo Ruiz, CEO of NewGrid, a utilities software developer in Boston, touted the benefits of topology-optimization technology, which automatically reconfigures power flow on the grid around congested elements.
“In terms of grid resilience and security impact, in several historical cases with overloads during extreme weather events, including heat waves [and] wildfires, we have found [the technology provides] in some cases complete relief,” Ruiz said. He pointed to his firm’s success in working with National Grid to improve system capability across a broad area of the U.K.
Monitor Patton questioned the advantage of treating topology different from other forms of optimization.
“When I listened to Pablo’s topology optimization, I don’t see how it’s different from other optimization improvements,” Patton said. “In fact, if [RTOs/ISOs] were to implement it, I think it would have to be implemented in their current set of models and tools because, for example, MISO and New York both run models every 15 minutes to optimally continue gas turbines, often for congestion relief.”
Ruiz responded that topology optimization “enables visibility on operational options, of the options that are not visible by and large today to the operators. In the end, software is certainly optimization. It has to be integrated in a different process, some processes require less integration, those are the days ahead and months ahead.”
MISO’s Webb said the question of who determines what qualifies as a GET can be a complicated. He counseled caution before RTOs adopt a particular technology.
“Maybe it depends if we’re talking about whether it needs to be isolated in definition from other types of transmission for other types of treatment, and I’m not sure we’ve resolved or addressed that,” Webb said. “Once you have an established technology that is mature, then the RTO can put that in its tool bag, if you will, with the collaborative planning process.”
CARMEL, Ind. — MISO’s staff, stakeholders and Monitor have identified several market improvements they want to see implemented in 2020, according to recently released Integrated Roadmap rankings.
The six projects that secured high-priority status next year include:
creating short-term reserves;
working on a speedier interconnection queue process;
using dynamic or predictive transmission line ratings;
changing the process for deploying demand response resources during capacity emergencies;
requiring the full installed capacity of resources to be deliverable; and
implementing automatic generation control (AGC) for fast-ramping resources.
Roadmap space was also reserved for MISO’s ongoing resource availability and need initiative.
MISO melded its own preferences with those of its stakeholders and Independent Market Monitor to produce the results, which were revealed at a special Integrated Roadmap workshop Thursday.
Many of the roadmap items have already received attention in 2019.
MISO control room | MISO
MISO is nearing a MISO Zeroes in on Queue Overhaul Filing.) Likewise, the RTO expects to implement AGC for fast-ramping resources by the end of the year for its approximately 400 MW of fast-ramping resources.
The RTO also filed early last month to revise its Tariff to include a short-term reserve product definition, though it doesn’t plan to introduce the reserves until 2021. (See “MISO Preps Tariff for Short-term Reserves,” MISO Market Subcommittee Briefs: Oct. 10, 2019.)
MISO said it could implement all seven projects — save for dynamic line ratings (DLR) — on its existing server-based market platform instead of waiting on the new cloud-based platform, still under construction. MISO President Clair Moeller said DLR are difficult for the RTO to model in planning, citing varying instrumentation on lines and no standardized limits on exactly how much a conductor can be opened season to season.
“There are a lot of complicated things that go into that,” Moeller explained during a Board of Directors planning meeting in September.
Monitor staffer Michael Chiasson said Potomac Economics has estimated that MISO stands to save more than $150 million annually if it implements ambient-adjusted temperature line ratings. He said transmission owners remain reluctant to adopt DLR because it involves investment in equipment and manpower with little return for them at this point.
Meanwhile, the Organization of MISO States is drafting a filing in support of FERC encouraging the use of DLR.
“It’s an opportunity to get more out of existing lines; it could defer or offset the need for new lines,” new OMS President and Minnesota Public Utilities Commissioner Matt Schuerger said at the organization’s annual meeting in October. However, regulators from Indiana and Wisconsin said FERC should not mandate DLR, as the technology involved is still new and expensive.
Other Roadmap Items Checked off
MISO also reported that it expects to complete another handful of Integrated Roadmap-related items by the end of the year. The list includes stricter outage scheduling rules, more requirements around load-modifying resource availability, a more limited tolerance for uninstructed deviations from dispatch instructions, external capacity counting toward local clearing requirements in the capacity auction and a FERC-imposed doubled energy offer cap.
CARMEL, Ind. — MISO officials last week said they agree with almost all the recommendations outlined by the Independent Market Monitor in this year’s State of the Market report.
However, RTO staff will need to perform further analysis before committing to solutions for three of the six recommendations, officials said.
Monitor David Patton produced six new recommendations in June as part of his 2018 report, among them clarifying the criteria for calling emergencies, procuring operating reserves on the Midwest-to South regional transfer limit and lowering the generator shift factor (GSF) cutoff for transmission constraints with limited relief. (See MISO Monitor Poses 6 New Market Recommendations.)
“After talking and interacting over the summer, we agree with most problem statements,” MISO Executive Director of Market Strategy and Design Scott Wright told stakeholders during Thursday’s Market Subcommittee meeting, where he presented the RTO’s official response to the Monitor’s report. MISO’s Tariff requires it to provide a formal response to the Monitor’s recommendations within 120 days.
Wright said a decision to procure operating reserves on the regional dispatch transfer limit doesn’t come down to MISO alone: The RTO must approach the joint parties to the transmission use agreement to discuss their willingness to create reserves.
“We just can’t say, ‘We’re going to do that,’” Wright said.
MISO also must proceed carefully and conduct more analysis if it’s to create lower GSF cutoffs for transmission constraints with limited relief, he said. “We think we need to think more about the solution.”
The Monitor’s report had also criticized MISO’s default emergency price floors as being unreasonable. “The default floors are set by a supplier’s offer, which has resulted in them often being inefficiently low and can result in them being inefficiently high,” it said.
MISO said it agreed with the Monitor on that item and would work on emergency and scarcity pricing improvements in 2020. It also agreed that it should clear up the criteria and improve the logging for declaring emergencies and taking emergency actions.
MISO in Sync with RA Recommendations
Director of Resource Adequacy Coordination Matt Ellis said MISO agreed with the Monitor’s two recommendations related to resource adequacy and that both are being covered in ongoing discussions over the RTO’s resource availability and need projects.
The Monitor had asked for MISO’s planning assumptions to include a more realistic volume of unforced outages and derates during peak-load conditions. It also wants the RTO to account for capacity resources’ behind-the-meter process load and devise a method for validating suppliers’ submitted data. MISO’s current capacity accreditation rules only account for forced outage rates.
Ellis said that while MISO agrees with both recommendations, accounting for unforced and unreported outages and derates in capacity accreditation will require more evaluation.
One Recommendation down
MISO said that by the beginning of next year, it will address one of the Monitor’s previous criticisms that capacity auctions allow for participation by resources that plan to be on outage for the entire planning year. The RTO last month filed a provisional solution that disqualifies capacity resources from auction participation if they plan to be unavailable for 90 of the first 120 days of the planning year. It expects a MISO Eases New Rules on Extended Outages.)
OGE Energy reported third-quarter earnings on Thursday, beating analysts’ expectations with a net income of about $251 million ($1.25/share). That compared favorably with the year prior, when the company reported earnings of $205 million ($1.02/share).
Thomson Reuters had projected earnings of $1.11/share.
The Oklahoma City company said it benefited from more favorable weather, rate recovery and 9,000 new customers. OGE executives said they see “upward momentum” in the company’s historical load growth of 1%.
OG&E service trucks | OGE Energy
“There’s a lot of modeling that goes into forecasting load growth,” CEO Sean Trauschke told financial analysts. “To the extent we continue to see growth and we’re able to continue to attract customers and new businesses and have sales growth, that gives you the opportunity to spread costs over a larger base and minimize customer impact.”
Trauschke said OGE’s partnership in Enable Midstream Partners is in “good shape.” The midstream gas business contributed $37 million during the quarter to OGE, marking $1 billion in total distributions since the partnership with CenterPoint Energy was formed in 2013. Trauschke said the revenues are used to support dividend growth and invest in its Oklahoma Gas & Electric utility. (See related story, Hot Summer Yields Positive Earnings for CenterPoint.)
Natural gas midstream operations (Enable) | OGE Energy
The company revised its year-end earnings guidance to $2.24 to $2.30/share, up from $2.05 to $2.20/share.
CenterPoint Energy’s third-quarter earnings surged more than 57% thanks to record electricity usage this summer, the company reported Thursday. Profits were $241 million ($0.47/share) for the quarter, compared with $153 million ($0.35/share) a year earlier.
CenterPoint’s performance exceeded Zacks Investment Research’s projection of 43 cents/share.
The company’s Houston transmission and distribution utility reported operating income of $269 million for the quarter, up from $227 million in 2018’s third quarter.
“Our utilities delivered another strong performance this quarter, driven by solid customer growth, disciplined cost management and favorable weather,” CEO Scott Prochazka said.
CenterPoint Energy headquarters in Houston
The company also reported a $77 million distribution from Enable Midstream Partners, its gas gathering and processing partnership with OGE Energy. Enable is forecasting a distribution of $385 million to $445 million in 2020, bringing CenterPoint’s cash distribution since 2013 to $1.8 billion. (See related story, OGE Earnings Surge, Beat Expectations.)
Tempering the company’s positive news was a recent Texas administrative law judge’s proposed decision that a requested Houston electric rate increase of $154.6 million be reduced to $2.6 million, or 0.11% of its present rate base. The docket is on the Texas Public Utility Commission’s agenda for its meeting this Thursday (49421).
Prochazka told financial analysts during the earnings call that the decision was “clearly not a good outcome.”
“We’ve assumed we would at least be recovering the additional investment, the billion dollars plus that we have already put in service that are not yet in rates. If we recover just that piece, it would be an increase in rates,” he said. “The process isn’t over, and the commissioners haven’t yet opined on this. We hope the commissioners will have a different view of it.”
ATLANTA — NERC’s Board of Trustees last week accepted the EMP Task Force’s Strategic Recommendations report but pointedly did not endorse the panel’s suggestions, saying it will consider them after reviewing stakeholders’ comments.
The issue of electromagnetic pulses is a polarizing one, and at least some of the task force’s recommendations — notably calling for guaranteed cost recovery for investments to protect the grid — are hot potatoes for NERC. The draft Strategic Recommendations report, which was released for comment Aug. 30, also urged more access to classified information.
The report made 15 recommendations in four areas — research needs; vulnerability assessments; mitigation guidelines; and response and recovery — and suggested lead and support organizations for each, including NERC, the Department of Homeland Security and the Federal Emergency Management Agency. (See EMP Task Force Calls for Federal Funding.)
The trustees praised the task force for its research but gasped at the potential implications of its recommendations.
“Reading through that document — it puts things into context that are extraordinarily complex in a way such that you can begin to see how we might actually tackle this initiative,” Trustee Rob Manning said. “But the complexity is what scares me. The breadth of recommendations, the scope of those recommendations — it’s truly scary. So many people have to be involved. So much action has to be taken by so many different parties.”
Trustee Jan Schori said it was “very helpful” that the report suggests potential lead and support agencies for the recommendations — all 15 of which list NERC as lead or co-lead.
“I would be interested in input from those that comment on what role NERC should play going forward,” Schori said, noting “some of [the roles] are … not areas where we … have taken the lead.”
Schori also said she “can understand why the industry participants would be very concerned about … the question of cost recovery for work that is done” in response to any standard or guideline adopted by NERC.
“Traditionally, NERC is the technical resource. We don’t usually get into opining on cost recovery matters. And so … I’m very cautious about those parts of the report.”
A number of the industry comments pushed this theme, arguing that the task force’s recommendations gave NERC too prominent a role and often relegated more qualified bodies to a supporting function. For example, Ruida Shu, manager of reliability standards at the Northeast Power Coordinating Council, suggested that the Department of Energy should take the lead on providing educational materials relating to EMP preparedness, as “NERC is not equipped to engage in mass public educational endeavors.” In the same vein, representatives from Exelon and the Edison Electric Institute recommended that DHS replace NERC as the lead on coordination across utility sectors.
Taking questions about the task force’s perspective a step further, Robin Yee, adviser on U.S. affairs and grid security at the Canadian Electricity Association, objected to the U.S.-centric framing of the report and its lack of attention to the legal and regulatory requirements of other jurisdictions. Yee requested that “NERC develop a framework for ongoing consultation and dialogue between governments,” so that policies affecting the North American grid would take note of all relevant perspectives.
Kim Thomas of Duke Energy said the task force had failed to make use of “the full body of work already performed in the industry for this topic” and recommended NERC “acknowledge and utilize work-in-progress or completed for this topic [in order] to avoid duplication of work and to provide additional depth and understanding.”
No Confusion
“We don’t want any confusion on accepting the report as [representing] final approval of the recommendations,” said board Chair Roy Thilly, who promised the board would issue its recommendations on EMPs in February.
Thilly said the board will solicit additional comment from NERC management and others on the recommendations and what it should prioritize. “I suspect there are budget impacts and other resource impacts. So, we need to understand we can’t just approve the recommendations without knowing those factors. We do have work to do to get to February.”
The task force’s work was informed by a report released by the Electric Power Research Institute in April that concluded a high-altitude EMP caused by a nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers fear. The report prompted a harsh critique by the Electromagnetic Defense Task Force. The group, which has ties to Maxwell Air Force Base, contends EPRI underestimated the risks and that relying on it would not address “remaining vulnerabilities impacting large power transformers, generating equipment, communication systems, data systems and microgrids designed for emergency backup power.” (See Critics: EPRI EMP Report Understates Risks.)
Next Steps
NERC Manager of Standards Development Soo Jin Kim, who presented the recommendations to the board, said the task force would like to begin Phase 2 of its work — more detailed analysis that would be forwarded to the newly created the Reliability and Security Technical Committee (RSTC). The RTSC would “develop detailed mitigation guidance and policy and procedures for how to update certain response and recovery plans,” Kim said.
“Only after the detailed work is done at the RSTC level — if it identified that there are enhancements or gaps in the standards, there [would] be an initiative for the EMP Task Force to kick off a standards development effort,” she said. “But that would only be if necessary, after the technical committee has first done its homework.”
In response to a question from Manning about proposed next steps, Kim said the task force identified as a “threshold question … that there needs to be progress in determining what’s an acceptable level of [bulk power system] performance during an EMP attack.”
She also noted that EPRI and several utilities are planning field trials of potential mitigation measures.
“Hopefully those field trials will be able to shed some light on certain mitigations and how available that technology will be to industry generally,” Kim said. “There’s also several research efforts going on right now with the National Labs. We have been reaching out to DOE and DHS also to try to share more information and to get more accurate information so industry can make those vulnerability assessments and accurately look at their systems.”
NERC’s EMP Task Force proposed 15 recommendations on research needs; vulnerability assessments; mitigation guidelines; and response and recovery. | NERC EMP Task Force
While some of the recommendations are outside the ERO’s authority, some are actionable by NERC and “will largely flow right into the RSTC next year as part of Phase 2,” she said. “We hope these recommendations will flow into the development of next steps for the industry to move forward in addressing EMP events.”
Not all industry participants were as positive about the momentum of the task force’s work: while Mark Gray, senior manager of transmission operations at EEI, described the report as a “good first step,” he said more research was needed to develop an effective response. Gray also recommended the removal from the report of language related to local distribution providers and other systems outside of NERC’s statutorily designated role.
Andy Dodge, director of FERC’s Office of Electric Reliability, asked whether the other agencies suggested as having roles have “bought into” the recommendations.
Kim said the task force followed President Trump’s March executive order in “highlighting some of the agencies that could be on point” and noted that the task force — formed in April — had a “very aggressive schedule” with the directive to provide recommendations to the board by November.
“Several of the entities that we did reach out to, and some of our contacts, stated that we probably would not be able to get some type of endorsement,” she said. “There has not been an official stance from any of the government agencies. Quite frankly, in that amount of time, I don’t think we could have received an official statement … that they would be willing to take on some of those recommendations.”
“Is NERC leadership going to follow up with these entities?” Dodge asked.
ATLANTA — The NERC Board of Trustees last week approved the merging of the Planning, Operating and Critical Infrastructure Protection committees and named Greg Ford as chairman of the panel that will replace them.
Ford, CEO of Georgia System Operations, is completing a term as chair of the Member Representatives Committee (MRC). MISO’s David Zwergel will be vice chair of the new panel, which is named — for now — the Reliability and Security Technical Committee (RSTC). Both will serve two-year terms.
Board Chair Roy Thilly said the new committee was welcome to change the name, noting concerns that the RSTC could be confused with the RISC — the Reliability Issues Steering Committee. “We do live in acronym hell,” Thilly joked.
“We talked about that on the board, and rather than having an extensive debate at this moment, we decided … to kick the can down the pike and … empower the new committee to propose a new name if they so choose,” he said.
Thilly called the approval of the merger and the RSTC Charter “a major step, with a lot of work in front of it.”
He said he appreciated “all the comments that came in, because it really made it better.” As a result of stakeholder feedback, the number of sector representatives was doubled and the sectors, rather than the board, will select them. (See Revised NERC Committee Merger Plan Released.)
While the three retiring committees totaled almost 120 members, the RSTC will have 34 voting members: two each from sectors 1-10 and 12, 10 at-large members, a chair and a vice chair. Terms for the new committee members will expire in June of alternating years. The initial membership will be split between two- and three-year terms, after which terms will run for two years.
Any unfilled sector seats will be filled by an at-large member until the term expires.
There will be five nonvoting members: the NERC secretary, two for the U.S. federal government, and one each for the Canadian federal and provincial governments.
The merger plan was developed by the Stakeholder Engagement Team (SET), led by Co-Chairs Jennifer Sterling, of Exelon, and Mark Lauby, of NERC.
“The SET is planning to live by example and wind down now that we have our deliverable,” said Sterling, who is succeeding Ford as MRC chair next year. “Any [additional changes to the transition] will be handled in the detailed implementation plan that the new committee will develop.”
One of the RSTC’s first work products will be reviewing the subcommittees, working groups and task forces under the three retiring committees and “eliminate or combine any of those that don’t really have recurring responsibilities or a defined deliverable,” Sterling said.
Three-week Sector Nominating Period
The transition will begin with the nomination of sector nominees, which will open this Tuesday and end Dec. 6. Sterling and sector leaders agreed to delay the opening of nominations by a week — they were originally scheduled to begin Wednesday — at the request of Bill Gallagher, a representative of the Transmission-Dependent Utility sector.
Gallagher said the delay would give sectors time to seek consensus on their two representatives. “We think it’s important to be able to do that because it gives us an opportunity to work behind the scenes to be sure that we get the right people to be running for these elections,” he said. “We think it would be a little bit smoother.”
“Is your concern that during that first week that somebody will nominate themselves without being vetted by your sector?” Sterling asked.
“Yes,” Gallagher replied. “If you look at the TDU sector, today we have six people that are serving on these three committees that are now going to be reduced to two people. We’d like to have an opportunity to influence the right people to make those transitions.”
None of the other sectors voiced opposition to reducing the nominating period when asked by Sterling.
“The voting would take care of [Gallagher’s concern], but it’s probably better not to get into that situation,” said Sylvain Clermont, a representative of the Federal/Provincial Utility sector.
The new Reliability and Security Technical Committee (RSTC) will replace the Operating, Planning and Critical Infrastructure Protection committees. | NERC
Transition Schedule
The transition to the RTSC will take about eight months:
Dec. 6: Sector nomination period ends. NERC staff to conduct sector elections, if necessary, by Dec. 20.
Dec. 9 to Jan. 3, 2020: Open at-large nomination period. NERC staff/SET analyze sector representatives’ expertise and regional mix for gaps to be filled by at-large members. The goal is to have at least one representative from each interconnection and regional entity footprint, and a mix of subject matter expertise (planning, operating and security), organization type (cooperatives, investor-owned utilities, public power, power marketing agencies, etc.) and geography (Canada, Mexico and U.S.).
Jan. 6-15: Nominating Subcommittee to develop slate of at-large nominees for presentation to the board.
Feb. 6: Board appoints RSTC members (sector and at-large).
Feb. 7 to May 29: RSTC develops transition plan and work plans for itself and subcommittees.
March 3-4: OC, PC and CIPC meet as scheduled.
March 4: RSTC holds its inaugural meeting.
June 2020: OC, PC and CIPC meet for final work plan approvals and to complete any other approvals. RSTC holds initial regular meeting with subcommittee reports and other agenda items.
change the Board Executive Committee into a full hybrid board, including stakeholder and independent directors;
add at least three independent directors to the Board of Directors;
formalize SERC’s membership body to include a representative from each member company by transitioning the existing full board into a members group that will meet at least annually to advise the board on the business plan and budget, elect independent directors and approve bylaw changes, as needed;
change the Board Compliance Committee into the Board Risk Committee; and
add a Human Resources and Compensation Committee, a Nominating and Governance Committee, and a Finance and Audit Committee.
It “changes almost everything,” SERC General Counsel Holly Hawkins said of the revised bylaws, which were approved unanimously by the regional entity’s board last month.
SERC CEO Jason Blake called the new rules “transformational.”
NERC Chair Roy Thilly called it a “very positive development,” noting that all REs will now have hybrid boards.
“This moves SERC to the front of the pack in terms of good governance,” Trustee Fred Gorbet said.
ReliabilityFirst Bylaw Changes Approved
The board approved changes to ReliabilityFirst’s governance and oversight guidelines to:
modify the CEO and independent director compensation approval process;
appoint a lead independent director to serve with an appointed stakeholder chair and vice chair;
implement term limits for directors, consisting of four consecutive three-year terms;
appoint the CEO as a non-voting, ex officio member of the Board of Directors; and
require board approval for directors serving on more than five outside boards.
The board approved the following committee members:
Personnel Certification Governance Committee: Cory Danson, Western Area Power Administration, as chair for a term of two years. Current Chair Michael Anderson, American Electric Power, did not seek reappointment because his position changed at AEP. Margaret Quispe, SPP, will continue as vice chair.
Standards Committee: Amy Casuscelli, Xcel Energy, as chair, and Todd Bennett, Associated Electric Cooperative Inc., as vice chair for two-year terms.
Critical Infrastructure Protection Committee: Marc Child, Great River Energy, chair; and David Grubbs, city of Garland, Texas, and David Revill, Georgia Systems Operations, co-vice chairs, for terms beginning Jan. 1. The remaining positions on the Executive Committee will be filled at the December meeting.
Compliance and Certification Committee: three-year terms for Justin MacDonald, Midwest Energy, Cooperative Utility sector; Ashley Stringer, Oklahoma Municipal Power Authority, Transmission-Dependent Utility sector.
Approvals
The board approved:
The 2020-2022 Reliability Standards Development Plan and authorized NERC staff to file it with applicable regulatory authorities. The three-year plan for reliability standards development addresses FERC directives, emerging risks and the Standards Efficiency Review.
Reliability standard BAL-003-2 (Frequency Response and Frequency Bias Setting) and authorized its filing with FERC and other regulatory authorities. Howard Gugel, vice president of engineering and standards, said the revisions address inconsistencies identified in the Frequency Response Annual Analysis.
PRC-006-NPCC2 (Automatic Underfrequency Load Shedding), which removes redundancies with PRC-006-1, PRC-006-2, PRC-024-1 and PRC-024-2.
The board approved the ERO Reliability Risk Priorities Report, prepared by the Reliability Issues Steering Committee (RISC), which reflects the committee’s efforts to define and prioritize risks and recommend what NERC and industry representatives should do to manage them. The report adds a 10th risk — critical infrastructure interdependencies — to the nine previously identified. (See ‘Interdependencies’ Joins RISC’s List.)
RISC Chair Nelson Peeler said the report also was modified to make it “simpler [and] cleaner.” It also incorporates survey results, which “will allow us to better track and trend as we go year to year.”
“I think we have had much better alignment than in prior years,” he added.
2020-2022 Reliability Standards Development Plan Approved
The board approved the 2020-2022 Reliability Standards Development Plan (RSDP) and authorized NERC staff to file it with applicable regulatory authorities. The plan seeks to address FERC directives, emerging risks and the Standards Efficiency Review.
