CARMEL, Ind. — MISO doesn’t expect any challenges meeting demand this fall, announcing last week that its supply should outpace its relatively tame peak forecast by about 36 GW.
The RTO estimates it will have 148 GW in total available capacity for the season, plenty to cover an expected 112-GW fall peak.
“That 112 GW is 3 GW lower than what we experienced in September 2017,” Jeanna Furnish, MISO manager of outage coordination, said at Thursday’s Market Subcommittee meeting.
But in keeping with the past several seasonal assessments, the RTO was careful to say that high-load, high-outage scenarios could trigger emergency procedures.
To generate its load forecasts, MISO partly relies on data from the National Oceanic and Atmospheric Administration, which has predicted higher-than-normal temperatures for the southern and eastern portions of the RTO’s footprint.
Furnish began the seasonal outlook by polling stakeholders on a family dispute. “When does fall start? The astronomical definition of Sept. 23 at 3:50 a.m. [EDT], or the meteorological definition of Sept. 1?”
Those at MISO’s headquarters overwhelmingly favored the astronomical approach.
MISO’s fall, however, is effective throughout September, where the risk of emergency procedures is most pronounced in the face of high load. During the month, the RTO could dip into its load-modifying resources and operating reserves in a 117-GW, high-load scenario even when outages aren’t considered a problem.
Furnish said a high-load, high-outage scenario paints a “bleaker picture” in which MISO might use the top end of its 13.7 GW in reserves. However, the RTO expects an average 111.3 GW of probable load during September. In October and November, MISO load is not expected to exceed 96 GW, and probable load will likely hover around 90 GW.
Furnish ended by joking she wouldn’t be doing her MISO duty if she didn’t urge members to submit outages as early as possible.
“Please make sure your company’s outages are in, for not only this fall, but also next spring. … It’s never too early to think about spring,” she said.
CARMEL, Ind. — After experiencing a surge in new projects, MISO is hoping bring solar generation under the umbrella of its dispatchable intermittent registration for market participation, the RTO signaled last week.
MISO’s proposal, issued Thursday, seeks to put solar generation on par with wind generation in the dispatch process. The method to be used provides a bit of déjà vu for some seasoned stakeholders.
Kun Zhu, MISO manager of resource retirement, said the proposal was precipitated by the flood of solar projects lining up for interconnection. “Quick story: Based on what’s coming in the queue, we’re set to have a big surge in solar,” he said in opening the Market Subcommittee meeting Thursday. “Now we expect the same challenge we saw 10 years ago,” referring to the wind generation boom that took hold about a decade ago.
Zhu said MISO’s plan is to require future commercial solar generation to register as dispatchable intermittent resources (DIRs), as it does for wind resources. Currently, solar generators can choose to be DIRs or simply remain intermittent resources, which are price-takers in the market and ineligible for dispatch. DIRs can submit price-sensitive offers and be dispatched by the market.
While MISO currently has just 243 MW of solar under the DIR registration, it reports that more than 9 GW worth of solar projects have executed generation interconnection agreements or are close to doing so. Beyond that, about 52 GW of solar are in the early stages of the interconnection study process.
“The time is now to expect the challenge and mitigate it,” Zhu said, adding that MISO can avert the growing pains it experienced in 2008 and 2009 when operators had to initially manually curtail wind generation over the phone. “It was cumbersome and not optimal and not ideal, and it caused big challenges in the control room.”
MISO won FERC approval in 2011 to create the DIR category for wind.
“We’re bringing solar to the same playground as wind,” Zhu said, pointing out that FERC recently accepted a similar change to solar treatment in SPP.
Just as in the original DIR filing for wind, MISO is proposing a two-year transition period to register solar resources. Solar projects with interconnection agreements before the time of the filing have two years to convert from intermittent resources to DIRs. Solar projects with no interconnection agreement in place before the effective date of the new tariff rule must register as DIRs immediately with no grace period.
MISO
Customized Energy Solutions’ David Sapper asked how the proposal would treat hybrid solar and storage projects.
Zhu said the hybrid angle is outside the scope of the proposal — for now. MISO is holding a special workshop in early October to discuss the rules and implications around hybrid projects. (See MISO to Host Hybrid Projects Workshop.)
“Hybrid is a new topic. What we’re discussing now is 100% pure solar generation, limited by the weather,” Zhu said.
MISO hopes to make a Tariff filing sometime in December.
FERC last week rejected Louisville Gas & Electric and Kentucky Utilities’ proposed transition for exiting from market power mitigation measures the commission had imposed to address the companies’ 1998 merger and withdrawal from MISO in 2006 (ER19-2396, ER19-2397).
The rate de-pancaking mitigation provisions were imposed to resolve horizontal market power concerns. In March, the commission agreed the provisions could be removed because loads located in the LG&E/KU market would have access to enough competitive suppliers after the mitigation is removed. It conditioned the removal on a transition mechanism to protect customers that had relied on transmission service on the MISO system.
FERC said that “although it determined that there would continue to be a sufficient number of competitive suppliers in the LG&E/KU market if the de-pancaking mitigation was terminated, termination will affect the relative economics of competing suppliers in different markets by making the cost of purchases from resources located in MISO more expensive.”
Eligible for the transition were contracts by the Kentucky Municipal Power Agency to supply KU requirements customers that went into effect on May 1; a requirements contract between the city of Benham and American Municipal Power; a requirements contract between the city of Berea and AMP that went into effect on May 1; and a contract between the city of Owensboro and Big Rivers Electric Cooperative.
The commission said the proposed transition mechanism filed by the companies in July was overly narrow and spelled out changes the companies must make regarding which customers and power purchase agreements should be covered and the definition of “covered” transmission service requests. It also ordered changes regarding which MISO schedules are eligible for reimbursement, reimbursement adjustments and the handling of exports.
In an accompanying ruling rejecting rehearing of its March order, the commission also identified three additional customers as eligible for the transition: KYMEA and member cities Paducah and Princeton (EC98-2-002, ER18-2162-001).
LG&E serves 411,000 electric customers in Louisville and 16 surrounding counties. KU serves 553,000 customers in 77 Kentucky counties and five counties in Virginia. The two companies, which are now PJM members, are owned by Allentown, Pa.-based PPL.
The NYISO Business Issues Committee on Wednesday approved revisions to Manual 4 (Installed Capacity) for external capacity suppliers, with a focus on imports from Ontario’s Independent Electricity System Operator and ISO-NE.
Section 4.9.1 was amended to add detail to the requirements for qualifying as an external capacity supplier. It requires a demonstration of deliverability to the New York Control Area border and execution of a letter certifying the supplier’s control of the resource if it does not own it.
Because the yellow ISO-NE capacity zone was identified as “import-constrained,” ISO-NE transmission is not able to accommodate the generator delivering to the New York border. Without an export delist bid, the generator would not be eligible to sell capacity in NYISO auctions. | NYISO
Section 4.9.3 was changed to add delivery requirements for imports from Ontario and New England. Suppliers from Ontario must provide written proof that IESO has approved their exports of power. Suppliers in New England must provide proof that they have an approved export delist bid in the ISO-NE Forward Capacity Market, or that it is not located in a capacity zone that does not permit exports.
FERC Updates
Presenting the Broader Regional Markets report, Robb Pike, director of market design and product management, provided updates on two recent FERC rulings, including one on external capacity.
On July 30, the commission accepted the ISO’s proposal to implement new requirements for external installed capacity suppliers responding to a supplemental resource evaluation (SRE), effective Aug. 12. Any external resource that fails to meet delivery criteria will be subject to a penalty of 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours to which a supplier fails to respond (ER19-2104).
On Aug. 28, FERC accepted revisions to the NYISO-PJM Joint Operating Agreement, effective on Sept. 26, to address a previous waiver approved by FERC regarding coordination of certain types of flowgates.
NYISO and PJM asked FERC to waive the JOA to permit the grid operators to add the East Towanda-Hillside Tie Line as a market-to-market flowgate. The requested waivers enable PJM to conduct redispatch operations to control flows to the more restrictive rating on the NYISO side of the tie line without violating the PJM Tariff for a limited period of time while NYISO and PJM develop a permanent solution.
Other Manual Changes
The BIC also approved changes to Manual 14 (Accounting and Billing) that replaces the terms “meter service provider” and “meter service data provider” with “meter authority.” It also revises Section 4.3.3 to clarify the methodology for certain calculations.
The committee also approved changes to Manual 27 (Revenue Metering Requirements) to add definitions of “member systems” (the eight transmission owners that comprise the New York Power Pool) and “meter services entity” (an entity registered with the ISO and authorized to provide metering and meter data services to an aggregator, responsible interface party or curtailment service provider).
LBMPs Decline 16% in August
NYISO locational-based marginal prices averaged $27.83/MWh in August, down approximately 16% from July and nearly 35% from the same month a year ago, Pike said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $34.96/MWh, a 25% decrease from a year ago.
Day-ahead and real-time load-weighted LBMPs came in lower compared to July. Average daily sendout was 487 GWh/day in August, lower than 539 GWh/day in July and 537 GWh/day in the same month a year ago.
Transco Z6 hub natural gas prices averaged $1.85/MMBtu for the month, down over 15% from July and 38.3% from a year ago.
Distillate prices were down 15.1% year over year and down slightly from the previous month, with Jet Kerosene Gulf Coast averaging $13.32/MMBtu, compared to $14.18/MMBtu in July, while Ultra-low Sulfur No. 2 Diesel NY Harbor dropped to $13.02/MMBtu from $13.71/MMBtu in July.
August uplift decreased to -20 cents/MWh from -6 cents/MWh in July, while total uplift costs, including the ISO’s cost of operations, came in lower than those of the previous month.
The ISO’s 25-cents/MWh local reliability share in August was down from 44 cents/MWh the previous month, while the statewide share climbed to -45 cents/MWh from -50 cents/MWh in March.
FERC is asking RTOs for information on aggregated distributed energy resource portfolios in their wholesale markets — the first significant movement in a possible rulemaking on DER in more than a year.
On Sept. 5, FERC’s Office of Energy Policy and Innovation sent identical letters to all the RTOs and ISOs seeking data on their existing aggregated DER interconnections (RM18-9).
“Commission staff is interested in further exploring the interconnection of distribution-connected DERs, in particular those that participate or will participate in DER aggregations for the purpose of providing wholesale service in markets operated by [RTOs/ISOs],” FERC said.
The commission asked for responses by Oct. 7, which will be followed by a 30-day comment period.
The 11-question list asks RTOs to provide data or estimates on the number of DERs in each footprint that directly participate in wholesale markets versus the DERs that don’t participate. FERC also inquired about RTOs’ coordination with state and local leadership about DER interconnection processes.
More detailed questions delve into each RTO’s “step-by-step” interconnection process for DERs and whether the process differs if DERs are eligible qualifying facilities or are behind a retail customer meter. FERC also asked how an aggregation of DERs located at multiple points of interconnection are studied, whether RTOs have interconnection studies for bidirectional service and how an RTO would handle a study for individual, already-interconnected DERs that wish to aggregate from separate points on the grid. Finally, the commission asked how the RTOs manage DERs aggregating from both FERC-jurisdictional and non-jurisdictional distribution facilities and requested the number of distribution facilities subject to an open access transmission tariff.
RTOs and ISOs this week said they were working to prepare data submittals.
Spokesperson Meghan Sever said SPP is working to provide FERC with “as much of the requested detailed DER data as possible” by the early October deadline.
MISO said it is working with the Organization of MISO States — which has developed its own DER estimates — and its stakeholder community to understand DER interconnection across the transmission and distribution interface.
“MISO has assembled a team of its subject matter experts who are reviewing the specific data requests and developing information to provide the requested information,” spokesperson Allison Bermudez said in an email to RTO Insider. “We will continue to coordinate with OMS and other stakeholders as we evaluate our responses.”
ISO-NE also said it was working to comply with the request. NYISO said it wouldn’t comment on preparations beyond its “official response to FERC.”
AEE Welcomes Movement
Leadership at Advanced Energy Economy, a D.C.-based trade association with members who develop and use DERs, took the data requests as a good omen. “We think it’s a good sign that the commission continues to dig into the issue and put some focus on it,” said AEE Managing Director and General Counsel Jeff Dennis, who leads the group’s wholesale markets advocacy.
But Dennis warned that the newest action in the DER docket now leaves any new rule waiting at least until November, and probably longer. With a draft DER rule still in a holding pattern, AEE released a whitepaper Sept. 5 outlining five case studies where DERs can be beneficial in wholesale markets. Dennis said the paper illustrates how DERs can provide service in wholesale markets to the benefit of consumers and the grid.
“As we await a final rule from FERC, there is a lot of discussion of the challenges to [DER participation] in wholesale markets. We wanted to focus on the benefits and the fact that this is already happening,” AEE Director Caitlin Marquis said of the five scenarios, which include managing demand or load with solar generation, battery storage, electric vehicle fleets and microgrids.
The case studies include a microgrid that can participate in wholesale energy and demand response markets to bolster vulnerable points on the grid or help during extreme weather; aggregated battery storage installations used for demand charge management; and electric vehicle fleets that are responsive to demand. The paper also highlights commercial solar generation and storage installations used to meet corporate sustainability goals and reduce wholesale market load and aggregated residential solar/storage facilities that have cleared ISO-NE’s forward capacity auction.
“This is what we could have more of if there were rules in place,” Marquis said, noting that some of the case studies are based on actual DER setups from AEE’s member companies.
Dennis also said there’s no harm in RTOs doing more work now to prepare for a DER rule.
“What we really want to see is additional efforts by RTOs and their stakeholders to look at how DERs will contribute to the wholesale markets in the future. Many RTOs are starting to do this now, and we hope others will follow suit,” Dennis said. “What’s really going to be needed beyond that though is RTOs taking a full look at their markets and the services that DERs can provide in those markets … and then ensuring that there are market participation pathways for them to do that.”
Dennis said AEE staff is also meeting with some RTOs to emphasize the benefits of aggregated DERs and discuss operational characteristics and implications for long-term system planning.
“Their experience so far is with large, central station power plants,” Dennis said of the RTOs. “We want to help them shift their thinking and approaches to prepare for the grid of the future, which will include many more distributed resources.”
SPP staff told the Seams Steering Committee on Wednesday that they are evaluating internal procedures and improving situational awareness for its operators following a level 1 energy emergency alert in early August, the RTO’s first since it became a consolidated balancing authority in 2014.
The grid operator called the EEA on Aug. 6 when capacity losses, a “significant” load-forecast error and low wind production led to tight operating conditions. The final straw came at 1:30 p.m., when a 290-MW generator tripped offline.
Load came in 1,500 MW over forecast as temperatures were higher than expected. The system also lost 2,500 MW of capacity in unplanned outages.
Aug. 6 load, generation and imports | SPP
The RTO was able to escape the situation by calling on 478 MW of grid-switchable resources in ERCOT and curtailing up to 127 MW of non-firm export capacity.
Operations engineer Ricky Finkbeiner noted SPP was able to avoid making emergency energy transactions, as MISO did in January 2018. (See Louisiana Regulators Question MISO South Max Gen Event.) The RTO had secured long-lead resource commitments ahead of time as part of its “uncertainty process.”
“The [reliability coordinators] were talking well before the afternoon it occurred,” Finkbeiner said.
Real-time prices spiked to nearly $1,500/MWh before non-firm exports were curtailed.
SPP, which had been operating under conservative operations since 9 a.m., issued the EEA 1 at 2:45 p.m. Load peaked at 49,389 MW at 4:24 p.m., with wind and solar energy making minimal contributions (1,553 MW and 140 MW, respectively). Wind production during the EEA was about 7% of its installed capacity.
The emergency event ended at 7 p.m.
The RTO has operated under conservative operations seven times during the summer because of generation outages, higher loads and subpar wind production.
Committee Questions Latest Joint Study with MISO
Following a third unsuccessful attempt by SPP and MISO to agree on joint transmission projects, committee members asked staff why a congested flowgate responsible for almost half of the market-to-market (M2M) settlements between the RTOs wasn’t more of a factor in the studies.
The Neosho-Riverton 161-kV flowgate in eastern Kansas has accumulated more than $29.3 million in M2M settlements to SPP since the RTOs began the process in March 2015. That is four times the next nearest flowgate and 45.6% of the overall M2M total.
Staff said the grid operators looked at 25 projects in the area but were unable to find enough benefits to justify a solution. Their latest attempt to determine joint projects ended this summer without success. (See MISO, SPP Empty-handed After 3rd Project Study.)
“It seems a lot of needs are showing, but you’re not finding projects,” said committee Chair Jim Jacoby, of American Electric Power. “Is it that there just isn’t enough [adjusted production costs] to justify? Are the calculations skewed?”
“The benefits just weren’t there,” Interregional Coordinator Adam Bell said. “SPP showed some good benefits, but MISO didn’t.”
Bell, who will soon leave his position for another in the organization, said modeling differences and how futures are weighed are the “likely culprits” for the inability to find joint projects. He said MISO uses four futures and three model years in its studies, while SPP uses two of each.
He also pointed out that M2M payments and APC are two different metrics. M2M payments capture the effect of market flows compared to firm flow entitlements, while APC captures the impact of pool-wide dispatch.
A recent upgrade to the Neosho-Riverton flowgate expanded its capacity by 20 MW, resulting in “considerably less” congestion this year, staff said.
“We would be remiss not to at least examine the issue,” the Missouri Public Service Commission’s Adam McKinnie said, suggesting it would be worthwhile to use avoided M2M payments as a benefit, as MISO does for targeted market efficiency projects.
“On the MISO-PJM seam, this project type looks at less expensive projects, requires payback over a short time period and has [been] shown to get results,” McKinnie said.
Bell said a final report on the RTOs’ 2019 Coordinated System Plan study will be included in the background materials for October’s Markets and Operations Policy Committee meeting. An advance copy will be shared with the SSC, he said.
July M2M Settlements Nearly Even Out
July resulted in the lowest M2M settlement between SPP and MISO since the RTOs began the process in March 2015, with the latter incurring $35,455 in M2M charges.
Permanent flowgates were binding for 227 hours and resulted in $753,755 in SPP’s favor. Temporary flowgates were binding for 323 hours, accounting for $718,300 in MISO’s favor.
July’s market-to-market report | SPP
SPP has accumulated more than $64.3 million in M2M settlements since 2015. The RTO has seen positive settlements in 39 of 53 months through July.
Members nominated Jacoby to serve a second two-year term as the SSC chair. The term, which begins in January and expires December 2021, will be Jacoby’s second full term since succeeding Nebraska Public Power District’s Paul Malone in January 2017.
Jacoby’s nomination will now go before the Corporate Governance Committee for final approval.
The committee elected GridLiance’s Bary Warren to remain its vice chair. Both votes were unanimous.
Members also made their first change to the committee’s scope since 2016, adding that it will “seek opportunities to coordinate with neighboring stakeholder groups to address issues of common interest, such as market-to-market.” The CGC will have the final say on the scope change as well.
SEATTLE — All systems are go as the Western Electricity Coordinating Council enters the final stretch of a yearlong sprint to ensure its dozens of balancing authorities safely integrate into new reliability coordinators ahead of Peak Reliability’s dissolution in early December, the group’s board heard Wednesday.
The Western Interconnection’s transition from two RCs to four is on schedule and proceeding smoothly, according to Branden Sudduth, WECC vice president of reliability planning and performance analysis.
“I am amazed at the amount of effort that people across the interconnection have put into this transition, making it successful, and I’m pleased to report that as of today, we are on schedule to attain all the objectives that we set out to attain,” Sudduth told board members at their quarterly meeting, held in conjunction with WECC’s broader annual gathering.
After Peak announced in July 2018 that it would wind down operations by the end of this year, CAISO and SPP scrambled to pick up its RC customers throughout the West.
CAISO’s RC West — which went live as California’s RC in July — will ultimately take on nearly three-quarters of the West’s load, followed by SPP at about 14%. (See CAISO Finalizes 32 RC Agreements.) BC Hydro began serving as its own RC on Sept. 2, Sudduth noted.
Alberta Electric System Operator has traditionally functioned as its own RC and will continue to do so.
Sudduth said that Gridforce Energy Management — a fifth prospective RC — will delay its certification and instead contract with RC West to serve its generation-only balancing areas for 17 months. As recently as May, Gridforce said it was still targeting a Dec. 3 go-live date, while acknowledging being in “catchup mode.” (See New RCs Tell WECC Transition on Schedule.)
WECC’s certification team for RC West’s future footprint outside California conducted a site visit at CAISO in late July. RC West began shadow operations with Peak for that expanded area on Sept. 4. WECC’s SPP team visited that RC in mid-August and has scheduled a follow-up visit for Oct. 9. SPP RC staff will shadow Peak in October and November and take over its new inland West territories on Dec. 3.
“A lot has happened on the certification and shadow operations front over the last couple of months, and there’s still a lot left to do, but everything is on schedule,” Sudduth said.
Among the tasks still left to wrap up: the completion of efforts to satisfy NERC reliability standard IRO-006-2, which requires a “common interconnection-wide modeling and monitoring methodology” for use in operational planning and real-time assessments, including facility ratings, thermal limits and steady-state voltage limits. NERC approved the standard to ensure uniformity among RCs across the West in the wake of Peak’s closure. (See “Trustees OK WECC Variance; Questions on Gen-only RC, Calif.-Ariz. Seam,” NERC Standards News Briefs: May 8-9, 2019.)
Also, 22 out of 60 WECC entities have still yet to sign on to the Western Interconnection Data Sharing Agreement (WIDSA), which was finalized in July, Sudduth said. The WIDSA will replace the Peak-administered Universal Data Sharing Agreement (UDSA), which provides a “consent-based” platform for sharing reliability-related information in the region.
On a related front, WECC is leading the transition from the Peak EHV Data Sharing Pool — the system used to share grid reliability data under the UDSA — to the Western Data Sharing Pool.
“I don’t know all the technical details of what this means, but essentially what we’re doing is going from an organization like Peak being the central repository of information to developing a new way for the RCs to communicate with each other and directly with their entities — and we’re hoping to transfer to this by Oct. 1,” Sudduth said.
WECC is also guiding the hand-off of Peak’s WECC Interchange Tool (which facilitates interchange between BAs) and Enhanced Curtailment Calculator (used for congestion management), Sudduth said.
He noted that WECC has rolled out a new RC messaging system. “I’ve been getting tons of emails from the new RCs, so it’s good to see that happening,” he said.
‘Reliability is Still Our Mission’
Making an impromptu appearance before the board, Peak CEO Marie Jordan assured WECC stakeholders that the organization’s impending shutdown won’t hold any surprises.
“We can still measure operations, which I think is really important with the magnitude of what we do … that we have this ability to measure it every day to ensure that we don’t have hiccups — because I think that would be very difficult in this transition period,” Jordan said.
She said Peak is focused on ensuring that staff use the shadow operations periods to transfer knowledge to the new RCs “because reliability still is our mission, and it’s been our first foot forward in all our conversations with our employees and how we’ve worked through the transition.”
As for Peak’s financial condition?
“I’ll say that’s actually in good shape,” Jordan said. She said learning how to close a not-for-profit has “been an interesting journey.”
“But the good news is we’ve done very well on the financial front, and we intend to finish and close that way.”
Jordan said Peak has not experienced any “unplanned attrition” in the past three months and that it plans to release its remaining staff on Dec. 13, just 10 days after handing off oversight to SPP. The company will then move to a model in which a board-appointed trustee will handle closing activities in 2020 as well as manage Peak’s data — and data requests — for the next five years.
“We’ve worked with all our vendors on the contracts … making sure that Peak is released from the liability and all the pieces of the contract with OATI — and all those other types of contracts, making sure there’s a clean start with the new entity,” Jordan said.
NERC will begin testing the newest version of its situational awareness tool in mid-November, which will add the ability to integrate transmission feeds with other sources such as real-time weather station data and radar.
Situational Awareness for FERC, NERC and the Regional Entities (SAFNR v.3) was piloted in 2017 during GridEx IV. It is being developed by ResilientGrid, an Austin, Texas, firm headed by Michael Legatt, who holds doctorates in both energy systems engineering and clinical health psychology/neuropsychology.
That unusual pairing of disciplines helps explain the idea behind SAFNR v.3, he told NERC’s Operating Reliability Subcommittee on Sept. 4.
“At a high level, the philosophy that drives the work we do and the tools we build are that the most important components on the grid are now — and will always be — human beings in the control room and the field,” he said.
Image from ResilientGrid Operating System showing Hurricane Michael in 2018 | ResilientGrid
“Under high-stress situations, when people collaborate — especially from adjacent infrastructures or different control rooms — if they’re looking at different pictures, the likelihood of human error goes up pretty significantly, especially under the times of the most profound stress. So, this tool is part of a larger platform and our vision to support shared situational awareness and collaboration throughout the industry.
“Situational awareness requires two things that the human brain cannot do at the same time: scanning and focusing. Often you have loss of situational awareness when people are focused on one thing and tend to … miss either a threat or opportunity” while attempting to also scan, Legatt said.
“Things that you’ll often find in control rooms — from the NERC and [Information Sharing and Analysis Center] level to the [reliability coordinators] down to the [transmission operators] and [distribution service providers] — all of these entities tend to have lots of different screens and monitors, and operators will look back and forth. But when you integrate [the sources] together, you start to see the impacts of these relationships. … By building a common integrated view, we’re able to significantly increase the effectiveness and speed of collaboration and reduce some risks of human error.”
The system was piloted with FERC, NERC and the Electricity Information Sharing and Analysis Center (E-ISAC) and used by E-ISAC and NERC Bulk Power System Awareness operators to track the progress of GridEx IV in 2017.
Exercising what he called “continuous improvement,” Legatt said his company plans to upgrade the system regularly. “The most important thing we build is really the relationship with the industry,” he said.
For example, he said GridEx led NERC and the E-ISAC to streamline their data entry for electric emergency incident and disturbance reports (Form OE-417) and EOP-004 event reporting forms.
James Merlo, NERC’s director of reliability risk management, said SAFNR v.2 replaced the original “rudimentary” tool in 2010. “It’s nine- or 10-year-old technology. It’s time to be re-platformed,” he said.
Merlo said the system will be based on raw Inter-Control Center Communications Protocol power flow data from RCs. That data can be overlaid with other data sources such as fires and weather.
“You can actually look at forest fires, transpose that with which way the wind is blowing and then … be a little more predictive to say: that fire is threatening that transmission line. It allows us to see all that without having to call individual entities.
“All of that data was available. You could turn this map on, and you could turn [that] map on, so you had to look at them all individually. This is now a holistic platform that allows you to create those layers so you can clutter or declutter as necessary to create situational awareness.”
VALLEY FORGE, Pa. — PJM anticipates filing a GreenHat Energy settlement on Oct. 9 that staff says will avoid costly legal proceedings, signaling a possible end to months of uncertainty and confusion for stakeholders in the wake of the company’s massive default on 890 million MWh of financial transmission rights.
Jen Tribulski, PJM’s associate general counsel, told the Market Implementation Committee on Wednesday a meeting is planned for mid-October for stakeholders unable to participate in negotiations to have a chance to discuss the settlement terms before filing comments with FERC. (See FERC Denies Shell, ODEC Seat at GreenHat Settlement Table.)
“Based on all the feedback we’ve gotten so far, we think the settlement will be unopposed by all parties,” she said. “We think the settlement will help avoid litigation and the unintended costs and uncertainties that would extend from litigation.”
In June, FERC gave PJM stakeholders just 90 days to settle all disputes about how to best liquidate FTRs left over from the default before kicking off a paper hearing on the RTO’s request to clarify a previous ruling related to the debacle (ER18-2068). (See FERC: PJM Settle Disputes Before GreenHat Hearing.) On Monday, PJM confirmed a settlement in principle had been reached but declined to give further details.
It’s unclear how much the agreement will cost members, though PJM spokesperson Susan Buehler previously told RTO Insider that estimates had now dropped below $200 million — a far cry from the anticipated $430 million expense stakeholders would have faced if forced to unwind five months of GreenHat settlements as initially ordered in FERC’s waiver denial in January. (See FERC Orders PJMto Unwind GreenHat Settlements.)
Grid operators and generators need more granular, real-time data to respond to grid oscillation events, engineers on a NERC panel said last week.
Tim Fritch, Tennessee Valley Authority manager of reliability analysis, last week gave the Operating Reliability Subcommittee (ORS) new details on the Jan. 11 oscillation event, when a “misbehaving” steam unit in Florida sent the Eastern Interconnection rocking like an unbalanced washing machine for 18 minutes. The presentation was an update of one that Fritch, vice chair of the Synchronized Measurements Subcommittee (SMS), gave to the ORS in the spring. (See Panel: Action Needed in Response to Oscillation Event.)
It was at least the sixth such event since 1996, according to a NERC reliability assessment published in July.
SCADA data show the flow on a 500-kV tie line with Southern Co. fluctuating by 200 MW during the Jan. 11 oscillation event, which was caused by a malfunctioning generator in Florida. | NERC
In the January event, Fritch said, the plant operators knew their unit was malfunctioning but “didn’t know they were moving the grid.”
One of the voltage signals used for the power load imbalance controller was compromised and 30% below what it should have been, Fritch said. “So, the controller was opening and closing the inverter valve on the unit. And this was causing a local area oscillation at about 0.25 Hz. This excited a natural mode that we had identified in previous studies that was around 0.23 to 0.24 Hz. So, since the unit was oscillating at 0.25, it was exciting this natural mode that was in turn causing this resonance phenomenon.”
The resonance was felt from Florida to the Midwest and New England, with power swings of 200 MW around Florida and 50 MW around ISO-NE.
Fritch said the event highlighted the need for better diagnostic tools and training in what not to do in such events.
“If you take some units offline for these types of events, we know it could get worse,” Fritch said. “Units act as a shock absorber on the system to absorb some of the energy from these big grid oscillations. So, taking some units down could make it worse.”
Fortunately, the only unit taken offline was the Florida unit that caused it. But other utilities considered taking their units down or shutting off automatic generation control (AGC), Fritch said.
Need for Better Tools
Fritch said TVA and other utilities with oscillation detection tools can only see their own footprint. “This happened for a lot of utilities on the Jan. 11 event: We knew it was big because all of our oscillation tools went into alarm. It showed our PMUs [phasor measurement units] were seeing this oscillation. But we couldn’t see outside of our footprint,” he said.
“We’re pretty good at identifying when we have a local oscillation based off our oscillation tools. But when you have these big grid oscillations where you excite these natural modes, you need more visibility.”
TVA was one of the two utilities that took its generators off AGC. “We thought our units were misbehaving. It’s hard to tell sometimes whether you’re the leader or the follower of these events.”
Of 11 utilities that responded to a NERC survey about the event, seven agreed there is a need to develop both a PMU data-sharing requirement for reliability coordinators and a real-time regional oscillation and source detection tool. The same number agreed the SMS should identify and address gaps in existing reliability standards on RC-to-RC coordination.
Fritch noted Professor Yilu Liu, of the University of Tennessee at Knoxville, helped create a video visualizing the oscillation using FNET/GridEye, a GPS-synchronized, wide-area power system frequency measurement network that uses data from more than 200 frequency disturbance recorders — essentially PMUs — around the world.
The University of Tennessee at Knoxville operates 180 frequency disturbance recorders in the U.S. through its FNET/GridEye network. | University of Tennessee at Knoxville
“Maybe there’s an opportunity to make that a real-time application instead of a post-op,” Fritch said, adding the industry may need to increase the number of recorders. “In my mind, there’s not enough to give you great granularity down to the unit,” he said.
“That’s why the industry, with like the [Department of Energy’s] ESAMS [Eastern Interconnection Situational Awareness Monitoring System] program, has been looking at bringing all of the PMU data into some type of tool because it has much greater coverage than the frequency disturbance recorders that FNET uses.”
Thousands of PMUs were installed across North America in the last decade. ESAMS is using their data “and looking for these types of events to see how [they’re] affecting the grid and help identify the cause of the forced oscillation that’s exciting these natural modes.”
Training Needs
Chris Wakefield, of reliability coordinator Southern Company Services, said some plant operators in his company’s footprint thought their control systems were malfunctioning during the oscillation. “They were [ready to take] action — taking their units off AGC or doing something more drastic, like a nuclear plant may go into some type of protective mode,” he said. “How do you communicate to generator operators that that’s not probably what you want them to do?”
Fritch said there’s no “cookie cutter answer” but training would help.
“Maybe it’s coming up with better communication between generation owners and RCs for these types of events,” he said. “That’s something we need help with from the ORS and from the industry.”
Next Steps
NERC will hold a webinar 2-3:30 p.m. ET on Friday to discuss the Jan. 11 event and the recently published Interconnection Oscillation Analysis report on the oscillatory behavior of the Western, Texas and Eastern Interconnections.
“I feel like we’re headed in the right direction. It seems like … the consensus is that NERC believes there needs to be some type of tool or application and guidance on how to handle these in the future,” Fritch said. “I know what we experienced was bad, but it could have been worse if those forced oscillations, instead of being 0.25, were around 0.23 or 0.24, or the unit was bigger. This was a 25-MVA unit. What if it were a 1,000-MVA nuke plant that was doing this?”
