DES MOINES, Iowa — Respect is the key to tempering landowner and community pushback on energy infrastructure projects, six industry experts told the Mid-America Regulatory Conference (MARC) last week.
The Aug. 13 panel agreed that in-person communication and avoiding a dismissive tone are needed to gain more traction in communities where contested projects are proposed.
“Land issues are just so critical. We talk about RTOs, FERC and seams, but this is really where it happens,” ITC Midwest Director of Public Affairs Tom Petersen said.
“Some of it has happened very easily, and some of it is quite painful,” moderator and North Dakota Public Service Commissioner Julie Fedorchak said of her state’s permitting of billions of dollars in projects.
Apex Clean Energy Vice President of Public Affairs Dahvi Wilson said it’s no longer simply a matter of getting landowners to sign off on projects. Now, Wilson said, utilities need to secure public support.
“We’re increasingly before state [and] local governments, and we’re facing opponents that are very sincerely concerned about what’s coming to their communities but also misguided,” Wilson said.
Utilities are increasingly facing the deliberate spread of misinformation online about proposed projects, she said. “We’re in a lot of debate right now over what’s true.”
Wilson said regulators must now ascertain whether data are scientifically rigorous or simply pulled from a questionable webpage.
North Dakota Indian Affairs Commissioner Scott Davis, a member of the Standing Rock Sioux tribe, led negotiations with the Dakota Access Pipeline over a two-year period. He described how he was constantly afraid of a protester’s death and listening to helicopters conducting crowd control near his home.
“Don’t underestimate the power of my people. You can tell them not to do it, and they’re going to do it,” Davis said. “Quite honestly, government hasn’t treated us very well in the decades of our existence.”
Davis said “old-fashioned” face-to-face discussions with tribal or community leaders is the best approach to introducing projects with communities, native or not. Davis also warned that treaties protect tribal land.
“[For] a lot of you that have tribes in your states, treaties are the law of the land. They’re in the Constitution. … Understanding tribes, where they’re coming from, is so important,” Davis said. “I think in this world of progress, progress, progress, what drives us — what pushes the gas pedal of progress — is trust. If you’re just rubber-stamping [energy infrastructure projects], you will have an issue.”
Wilson said the wind industry, which previously tended to submit projects quietly, hoping for little public notice, is now more transparent. She also agreed that it’s imperative for utilities to spend face-to-face time in a community.
“If the people that are fighting our projects are much more liked in the community, the community is going to believe them over us,” Wilson advised.
However, she said, it’s still a “hard sell” to convince many utilities to spend money to embed company representatives in a community to foster trust.
Considering Alternatives
Environmental Law & Policy Center Senior Attorney Brad Klein said it’s generally good practice for a utility to perform a full environmental impact analysis early in the process and thoroughly investigate alternatives to a large energy infrastructure project.
“I don’t think alternatives are appropriate in all cases, but they should be fully considered up front,” Klein said. Decisions should be made based on “full and fair information,” he said, which should contemplate new technologies, battery storage and collections of distributed resources.
Kevala Analytics CEO Aram Shumavon urged those thinking about project alternatives “to think about the amount of change we have been through in the prior 10 years versus the century before that.”
Klein also acknowledged that there will be environmental trade-offs with any large infrastructure project. But utilities and regulators shouldn’t insult groups of concerned citizens, he said.
“Don’t dismiss local communities as NIMBYs [‘not in my backyard’]. That’s insulting,” Klein said. “When we lose the public’s trust, you lose the larger fight.”
Petersen said he was in “violent agreement” that utilities shouldn’t reduce protesters to NIMBYs.
“Before you even propose a project, spend two months in the community. … You’ll decide whether that project is appropriate for that area. … And you’ll have a whole lot more respect,” Petersen said.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Consent Agenda (9:10-9:15)
The MRC will be asked to endorse proposed revisions to:
B. PJM Manual 10: Pre-Scheduling Operations, regarding generator outage reporting. The changes include clarifications for outage ticket end dates for deactivations and outage ticket requirements for black start service.
D. Manual 13: Emergency Operations and Manual 14D: Generator Operational Requirements, as part of the clarifications to the non-retail behind-the-meter generation business rules. The changes will clarify the reporting, netting and operational requirements of NRBTMG and PJM’s responsibilities, processes and procedures. (See “BTM Generation Clarifications,” PJM OC Briefs: Aug. 6, 2019.)
E. Manual 18B: Energy Efficiency Measurement & Verification, resulting from a periodic review.
1. PJM Manual 14B Amendments (9:15-10:15)
After eight months of discussion, PJM will present “compromise” revisions to Manual 14B that expand upon how the RTO prioritizes projects in the Regional Transmission Expansion Plan. The RTO said that it “commits to implement” the manual changes if they are approved by the MRC.
In its presentation, PJM said the language doesn’t address all of the concerns raised by LS Power and other stakeholders at the special Planning Committee meetings held since January about how and when supplemental projects move in and out of the RTEP.
The revisions are intended “to ensure that the manual faithfully documents its existing planning processes, integrates new processes or procedures consistent with recent regulatory orders/compliance directives, and provides a platform for the future that incorporates stakeholder desires, duties and future direction,” according to PJM’s presentation, posted online last week.
LS Power will also review its original main motion that’s been the center of PC discussions. The company intends to accept language presented at the special Planning Committee session Wednesday as a friendly amendment.
American Municipal Power will also propose friendly amendments to the Wednesday proposal.
Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), will review OA revisions proposed by the D.C. OPC concerning updates to the RTEP.
The language would prevent PJM from unilaterally shelving endorsed rule changes without any recourse for disgruntled members, as it did in January with stakeholder-endorsed transparency language that PJM found inconsistent with FERC rulings. (See Tensions Boil over on PJM’s Supplemental Projects.)
The committee may be asked to endorse the proposed changes.
PORTLAND, Ore. — Utility equipment ignited eight of the 20 most destructive wildfires in California history and six of the eight occurred in just the last three years, according to the California Department of Forestry and Fire Protection (Cal Fire).
Those sobering statistics set the context for a “wildfire dialogue” convened by West Coast utility regulators at the Oregon Convention Center on Friday, bringing together four panels of utility and fire science experts to discuss ways to reduce a danger expected to grow with climate change.
“It’s clear that wildfires are larger, more intense,” Koko Tomassian, of the California Public Utilities Commission’s Safety and Enforcement Division, said when presenting the Cal Fire figures at the conference. “The question is: Are we as a community doing everything we can to save lives? Are utilities in compliance with standing general orders and regulations? Are we as regulatory agencies enforcing those regulations in a manner that promotes compliance?”
Brian D’Agostino, director of fire science and climate adaptation with San Diego Gas and Electric, recounted his utility’s history with wildfires. The first big San Diego fire flared up in late September 1970 and burned about 100,000 acres. At the time, it was one of the largest fires in state history. The next didn’t come until 2003, consuming 286,000 acres in just over a day-and-half and ranking as the state’s second biggest fire.
“Everyone said, ‘This won’t happen again; this is a once in lifetime event,’” D’Agostino recalled. “And it was four years later that … 13% of our service territory burned in a matter of days” in the 2007 Witch complex of fires, which authorities blamed on SDG&E.
“That’s really where it became apparent that something very different is happening here in Southern California,” he said. “This is not consistent with how our climate has behaved for the decades and century before.”
Eight of the 20 worst wildfires in California history (marked in red) were sparked by utility equipment, most of them in recent years. | Cal Fire, CPUC
Fire Concerns Go North
The wildfire worries that plagued dry Southern California for decades have moved rapidly northward, catching many off guard. Huge, deadly blazes devastated parts of rainier Northern California in 2015, 2017 and 2018.
In Portland, a thousand miles north of San Diego, the Bonneville Power Administration is now tackling the issue as well.
Until recent years, said Robin Furrer, vice president of transmission and field services at BPA, she had been accustomed to focusing on how to sustain the BPA system in the face of wildfires.
“So the notion of looking at our infrastructure in terms of, do we contribute to a fire, or are we even a source of ignition for a fire, was a new perspective with which to look at our system and how we operate, maintain and make decisions about it,” she said.
Some of the “minimums” BPA has observed to meet reliability standards — such as setbacks for transmission corridors — may not be adequate for protecting against wildfires, she said.
“We have a set standard, but that set standard assumes a non-changing environment. And as the utility industry, we have to look at what are those new risk factors that we might not have considered before,” Furrer said.
As in San Diego, the 2003 fire season “was particularly bad for British Columbia,” representing a pivotal time for the Canadian province’s major utility, said Mike Guite, BC Hydro’s manager of transmission sustainment planning.
“We had communities devastated, houses lost … and we had a major radial transmission line out, and so several communities feeding from that line were out of power for weeks on end,” Guite said.
After that fire season, a provincial commission produced a report that made recommendations changing how wildfire risk is managed in BC. It also resulted in the Wildfire Act, which bolstered obligations for land managers to lessen wildfire risk, he said.
“The commission also made a bunch of recommendations for communities and how the communities manage that wildfire risk in the [wildland-urban] interface zone around those communities,” he said.
Danger at the Interface
Oregon Public Utility Commissioner Letha Tawney pointed to the wildland-urban interface as a key factor in the West’s growing attention to fire danger.
“Wildfires have been an issue for some of us for years. It’s endemic in the West. What’s different? Why the focus now?” Tawney asked.
“One, we have more people living in the wildland-urban interface,” she continued, noting that residential housing in such areas has increased from 31 million units to 43 million units between 1990 and 2010. “To serve this growing population, the sector’s added thousands — even hundreds of thousands — of circuit lines of electric systems across” the Western Interconnection.
The way Western forests are managed is giving fires more fuel and increasing their intensity, she said.
Climate Change Impact
Climate change has exacerbated the risks, Tawney said.
“These patterns of economic development and forest management would have increased our risk of catastrophic wildfire just on their own, but they’ve run smack into the wall of a changing climate,” Tawney said.
Even though human-caused climate change can still be controversial in the West, “I believe we cannot keep customers safe or protect long-term affordability effectively if we ignore the data,” she said.
Crystal Raymond, a climate adaptation specialist with the University of Washington’s Climate Impacts Group, said human-caused climate change accounts for about 50% of the area burned in the West since the mid-1980s. The Pacific Northwest is seeing a rapid escalation in fire risk. It’s now experiencing, on average, 12 to 15 more days of high fire danger each year compared with historical averages, she said.
“We expect to see an increase in the area burned due to climate change,” Raymond warned, saying that by the 2040s, that area will increase 100 to 500% over the 2006 mean.
Referring to the “legendary” Tillamook Burn that destroyed 350,000 acres of old-growth forest in the relatively damp Coast Range of Western Oregon, Washington Utilities and Transportation Commission Chair David Danner asked Raymond: “Some will say that what we’re seeing now is a phase and will pass. Is that the case?”
“There’s definitely been variability in the past, and when you look back at this time period when we had large fires like the Tillamook Fire and the [1902] Yacolt Fire [in the Columbia River Gorge], they were drier and hotter than average periods in our climate. … The thing is, the projection of warmer-than-average isn’t going away,” Raymond said.
“We often hear [about] the Tillamook and Yacolt fires, [and] I just want to place that in context. Those were human-ignited fires under really awful conditions for fires out here,” said Chris Dunn, an Oregon State University research associate with a Ph.D. in forest resources. Although fire prevention programs have become “smarter” since the 1930s, conditions will continue to become warmer and drier, Dunn said.
“Remember that a lot of how fires are playing out is human interaction in drought, so we play a big part in that,” Dunn said. “Not just by our effects on climate change, but just how we interact with our wildlands.”
Fires in a Rugged Landscape
The sunny Southwest and rainy Northwest share mountainous terrain that makes limiting fire damage more difficult, panelists said.
The public safety power shutoffs first used in Southern California, and now being employed in Northern California, may also be used in Oregon and Washington.
But shutting off power to prevent fires has its own risks, especially to vulnerable residents of rural areas, some said. British Columbia will not de-energize lines during fires because the impacts on its communities “are so great,” BC Hydro’s Guite said.
The California PUC is trying to deal with the situation, said Anthony Noll, program manager with the Safety and Enforcement Division. The average shutoffs lasts 35 hours, endangering those who depend on medical devices that need power and cell phones that need charging, he said.
Moreover, he said, it can be difficult just to get the word out. Landlines, cell phones, websites and text messages both help and fragment the process. Utilities have primary responsibility for notifying residents they may lose power in high-threat fire conditions.
One problem, he said, is pre-emptively notifying people too much — “crying wolf” — and having them ignore future warnings.
David Lucas, vice president of transmission and distribution operations with Pacific Power, said his utility, a division of PacifiCorp that serves customers in Washington, Oregon and far Northern California, is on the front lines of fire risk that seems to be traveling up the West Coast.
But Pacific Power has been able to learn from what’s happening in California and apply those “best practices” in its Oregon and Washington territories. “We didn’t see the need to reinvent the wheel, if you will,” Lucas said.
CPUC Commissioner Clifford Rechtschaffen said his state had been forced to the vanguard of wildfire prevention. Its progress can inform efforts elsewhere in the West but remains a work in progress, he said.
“Every season we learn more,” Rechtschaffen said. “We have a lot of humility about what we’ve done. This is very much a continuous learning process.”
The certification process for SPP’s reliability coordination function in the Western Interconnection began last week with an on-site visit by nearly two dozen industry representatives.
SPP’s RTO, Western RC footprints | SPP
“They spent the better part of three days talking with our staff,” C.J. Brown, SPP’s director of systems operations, told the RTO’s Western Reliability Executive Committee on Friday. “Overall, I think it went very well.”
As is the case in certification visits, the team left behind issues to be resolved in three buckets: items that prove the RC is not ready; items to be addressed before going live; and suggestions or recommendations. SPP had no items in the first bucket, but several in the second, “none of which aren’t already in our project plan,” Brown said.
He said the team made numerous recommendations in the third bucket.
“That’s good, because that gives you a chance to look at best practices,” Brown said.
The 23-person certification team was led by the Western Electricity Coordinating Council and composed of staff from WECC, FERC, NERC, the Midwest Reliability Organization and other industry representatives.
“It’s a very diverse and subject matter-rich team,” WECC CEO Melanie Frye told the NERC Board of Trustees at its meeting in Quebec City on Thursday.
Frye also disclosed that Gridforce Energy Management, a Houston-based control center, has reached an agreement to use CAISO’s RC West services through at least April 2021. The company had intended to begin providing RC services to serve several small generation-only balancing authority areas in Arizona, Oregon and Washington in December.
Western Interconnection RC footprints expected December 2019 | WECC
“This is an interim step,” Frye said. “We see this as a very positive move to ensure a smooth transition to these new RCs. That will be part of the certification process as RC West goes through their Phase 2.”
Gridforce did not immediately respond to a request for comment on its change in plans.
SPP’s Schedule
SPP expects to receive a final certification report in mid-September. That will set the stage for shadow operations with WECC’s incumbent RC, Peak Reliability, in October. SPP is scheduled to go live with its RC services Dec. 3.
Peak said last year that it would wind down operations at the end of 2019. SPP and CAISO both jumped at the opportunity to provide RC services to Peak’s customers, with SPP signing up about 12% of the Western Interconnection’s load. (See CAISO RC Wins Most of the West.)
Key milestones for SPP to become a Western RC | SPP
SPP is also working with CAISO and Peak to gather the data necessary to coordinate reliability. Brown said staff have gathered about 30% of the necessary data points, using CAISO as its primary contact.
“Everywhere we can use the CAISO data, the better,” he said, noting the ISO is transitioning to a new energy management system. “As the system gets closer and closer to production for shadow operations, that’s when they’ll be able to transfer all the data. We’ve already done the pre-work. … Our systems will be able to accept [the data] immediately.”
Brown said SPP’s system model is “aligning well” with the Peak model, except for a lack of real-time data in the Northwest and from the Bonneville Power Administration.
In her briefing to the NERC board, Frye praised Peak CEO Marie Jordan and her staff for helping with an orderly transition.
“You can imagine what it’s like to work at Peak right now,” she said. “They have done a fantastic job of communicating with their members and the general public. … They’ve really demonstrated a desire to make sure this transition goes smoothly.”
Frye said Peak’s employee attrition is “as expected.” The last planned attrition date was in July following the go-live for RC West; the next planned reduction is in October. Some Peak employees have been offered jobs at the new RCs, and one is being hired by WECC.
“There’s tremendous talent there,” she said.
As for Jordan’s plans? “I think she’s going to be enjoying a beach [after Peak ceases operations], but I think she’ll consider what options are out there as well,” Frye said.
QUEBEC CITY, Quebec — NERC will delay the first release of its Align software project from September to 2020 to allow inclusion of security features originally planned for a later release.
NERC Chief Technology Officer Stan Hoptroff announced the change at a meeting of the Technology and Security Committee on Wednesday, saying the regional entities wanted to see security capabilities planned for Release 3 included in the initial rollout.
“The board was in full support of this delay,” committee Chair Suzanne Keenan said. “We’ve got to get it right, and we will.”
Hoptroff said the additional security features concern “evidence lockers” to hold data from enforcement cases. Release 1 is now expected in the first or second quarter of 2020.
The announcement came after it was disclosed at SERC’s quarterly open forum July 29 that only two REs, Midwest Reliability Organization and Texas Reliability Entity, would be involved in the initial rollout of Align Release 1. (See Align Rollout to be Staggered.)
Hoptroff said MRO and TRE will still be the first two REs brought online.
“I still like the idea of starting with Texas and the MRO because [TRE Chief Operating Officer] Jim Albright is our [Align] Steering Committee chairman and [MRO CEO] Sara Patrick is our executive sponsor,” he said in an interview after the meeting. “So, it’s only appropriate they go first. It would be inappropriate for them to ask another region to go [first]. They are also using the system [currently]. So, if we had to roll back, it would be easier than having to go back to two different separate systems.”
Hoptroff also said NERC management has resolved its concerns over the sale of the organization’s vendor, BWISE Information Security, to SAI Global, an Australia-based company whose investors include a private equity fund managed by a Hong Kong company. (See NERC Investigating Chinese Tie to Software Vendor.)
“I am confident” the ownership poses no security concerns, he said.
Hoptroff said the most recent survey on Align, which ended June 28, documented increasing awareness, with 63% indicating familiarity with the project, up from 47% during the baseline assessment in March. About 67% agreed or strongly agreed with the business need and value of Align, an increase from 58% in March.
Hoptroff emphasized training on Align will not be a “one-time” event. With 5,000 users expected to use Align, a 10% annual turnover would mean the need to train 500 new people per year, he said.
CORES Rollout
Ryan Stewart, senior manager registration and certification, gave the committee an update on the Centralized Organization Registration ERO System (CORES) project, which will become the single registration tool for the ERO Enterprise.
Data entered into CORES will be integrated with Align. “Everything starts with registration data,” Stewart said.
He likened the system to airport security, with the user name and login functioning like a passport and boarding pass. Once inside, “going from one application to another” will not require additional security, he explained. “You don’t need to log out. You don’t need to log back in.”
It will provide a “one-stop shop” for contact information and include filtering tools for generating customized reports, Stewart said.
CORES will be introduced over the next several months in a “managed rollout” that will include one- to five-minute “how to” videos. Twenty entities in the ReliabilityFirst region have begun validating their data in the system.
“This is a truly transformational way for us to manage our registration process and database,” NERC CEO Jim Robb said.
SAFNR
Hoptroff also briefed the committee on version three of the Situational Awareness for NERC, FERC and Regions (SAFNR) system, which is scheduled to launch in the third quarter.
SAFNR was initiated by NERC in 2009 in response to recommendations from the U.S.-Canada Power System Outage Task Force, which concluded that the 2003 blackout was caused by a lack of situational awareness.
The new version will provide more detailed data than the existing program, which is limited to systems 230 kV and above and generation units of 500 MW and higher. It will also include visual indicators to alert users of state changes and visualization features on weather and geography.
Displays will show hourly balancing authority loads, forecasted loads and net interchanges, and detailed outage data by geography or company.
“It’s not a single-use application,” Hoptroff said. “It’s a platform that can then be expanded.”
Attorneys are battling now over the matter at the heart of Pacific Gas and Electric’s bankruptcy — the billions of dollars it’s likely to owe victims of the massive blazes of 2017 and 2018 that wiped out a Northern California town and part of a midsized city.
In the U.S. Bankruptcy Court for the Northern District of California in San Francisco on Wednesday, lawyers representing the utility and fire victims argued over how to estimate the potential liability.
The estimation of liability is something Judge Dennis Montali must deal with as he oversees PG&E’s Chapter 11 reorganization. Estimation of potential claims is “a fairly unique process in the bankruptcy world,” Montali said in a hearing Wednesday.
The federal bankruptcy code requires judges to estimate contingent or unliquidated claims that could otherwise “unduly delay the administration of the case.”
Litigating wildfire claims in state court could cause long delays, when PG&E is under the gun to reorganize by next spring. A new state law, AB 1054, requires the company to exit bankruptcy by June 2020 if it wants to take advantage of the law’s $21 billion fund to pay wildfire damages. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
PG&E Corp. and its utility subsidiary, the debtors in the case, are pressing Montali to conduct an estimation proceeding and settle on a figure soon.
“There is no dispute by any stakeholder on the core issue presented by this motion: Estimation proceedings are required in these Chapter 11 cases absent a consensual resolution,” PG&E’s lawyers wrote in an Aug. 11 motion. “Equally inescapable is the conclusion that estimation has to begin now.”
The California Public Utilities Commission also must approve PG&E’s reorganization and needs a workable plan by January to meet the new law’s June deadline, PG&E attorneys told Montali in their brief.
“All parties acknowledge the importance of meeting that legislative deadline,” they wrote. “Failure to do so would materially reduce the value of the estate by precluding the reorganized debtors from participating in the newly created wildfire fund.”
Tort Lawyers Reject ‘Fixed Pool’
For many of the 2017-18 fires, state investigators have already determined PG&E’s equipment was at fault. As a consequence, the utility could be held responsible for all resulting damages under California’s strict liability law. That includes damages in November’s Camp Fire, which burned down most of the town of Paradise and killed 85 people. It was the deadliest and most destructive blaze in the state’s recorded history.
A major sticking point, however, is the Tubbs Fire, a blaze that tore through Northern California wine country in October 2017 and razed sections of Santa Rosa, a city with 175,000 residents in Sonoma County.
Investigators with the California Department of Forestry and Fire Protection determined a private landowners’ faulty wiring, not PG&E equipment, started the fire. (See PG&E Cleared in Fire that Burned Santa Rosa.) Plaintiffs’ lawyers still hope to convince a jury that PG&E was responsible for the blaze because of the huge amount of damages involved. The fire killed 22 residents and leveled more than 5,600 structures.
The Tubbs Fire swept into Santa Rosa, Calif., in October 2017, destroying a large swath of the city.
“The state court should make determinations as to debtors’ liability on the Tubbs Fire,” two law firms representing about 5,200 fire victims wrote in their brief. “Once the state court determines liability relating to the Tubbs Fire (or once the issues are settled), then the parties can get together and create estimations of all fire claims within an acceptable range.
“Estimation was not created for the purposes for which it is being used — i.e. to cap the funds available for all claimants regardless of individualized damages and with disregard to due process,” the lawyers wrote.
Other plaintiffs’ attorneys urged Montali to reject a fixed pool of money to pay fire victims.
“The debtors would like to cram down a plan that pays contract creditors in full, permits shareholders to retain their equity in the utility, channels tort claims to a trust that has a limited fund to pay tort claimants and discharges the debtors from liability on the claims,” lawyers representing the Official Committee of Tort Claimants victims wrote in a court filing.
“There can be no assurance the trust would have enough funding to pay the claimants in full when they liquidate their claims via settlements or jury trials. If the capitalization of the trust fund is insufficient to pay the tort claims in full, the result would be contract creditors and shareholders will have been paid in full and retain their interests, and the victims lose; the only question is by how much.”
The tort claimants committee has asked Montali to lift an automatic stay on lawsuits against PG&E, allowing a Tubbs Fire trial to proceed in state court on an expedited basis.
Montali said he would try to rule on the estimation issue and the lifting of the automatic stay by a hearing on Aug. 27.
Faced with an increase in demand and generation outages, ERCOT declared another energy emergency alert Thursday afternoon, its second in three days after five years without calling one.
The Texas grid operator issued the Level 1 EEA when power reserves dropped below their 2.3-GW threshold just after 3 p.m. System load was 69.7 GW at the time, below that of Monday and Tuesday’s record peak demands.
Prices again hit the $9,000/MWh maximum for several 15-minute intervals during the late afternoon.
ERCOT Senior Director of System Operations Dan Woodfin said reserves were “tighter than expected” because the grid operator was without 5.2 GW of capacity that was available earlier in the week. (See ERCOT Survives Another Day in the Roaster.)
“Almost all the generation in the system has been online every day this week,” he said. “We knew we were going to be tight, but I think we’re tighter than expected.”
The EEA allows ERCOT to “take advantage of certain resources that are used for just this type of situation,” Woodfin said. The grid operator called on all available resources, deployed operating reserves and its 30-minute emergency response service, and requested energy imports over its ties with neighboring RTOs.
Woodfin also said the system’s wind production was lower than seen in previous days, contributing to the tight conditions.
Earlier this week, ERCOT CEO Bill Magness said the grid operator sees a “trough” of wind generation in the early afternoon before the Gulf Coast wind facilities begin filling in the gap.
“You see higher levels of wind in the evening and into the morning,” he said. “So, often, even though we’re at peak load, some of our tightest conditions may show up earlier than you might expect, but we recover by the time we get over the peak.”
The ERCOT system at 3:34 p.m. Thursday | ERCOT
Both ERCOT and the Texas Public Utility Commission called on consumers to reduce their consumption through 7 p.m.
“The hot weather has continued throughout the month of August, and the Texas economy is strong, so two calls for conservation in the same week is not surprising,” PUC Chair DeAnn Walker said in a statement.
“Occasional calls for conservation are a natural part of running the most efficient electrical system in the world,” Commissioner Arthur D’Andrea said.
“Barring any other things that could happen, it doesn’t look like we’ll need a further [EEA] level today,” Woodfin said. “We don’t like to get into these conservation situations, but it’s something our operators train on.”
ERCOT declares a Level 2 EEA when operating reserves drop under 1.75 GW.
“This is a fluid situation, and can change at any time,” ERCOT spokesperson Leslie Sopko said during a media call.
Statewide temperatures were in the upper 90s on Thursday, but heat indexes were in triple figures.
ERCOT’s Board of Directors on Tuesday got its first look at the work being done to implement real-time co-optimization (RTC), which will add ancillary services to the real-time security-constrained economic dispatch engine.
ENGIE’s Bob Helton, who chairs the Technical Advisory Committee, and Matt Mereness, ERCOT’s compliance director and chair of the Real-Time Co-Optimization Task Force, briefed directors on the intricate design work and approval process during the board’s bimonthly meeting.
“We’re on our way,” Helton said. “We’ve got a long road to go. It’s a very tight schedule, but there are a lot of meetings to try and get this through.”
Mereness’ task force faces a February deadline to present a final package of RTC principles to the board for approval. Once consensus is reached on the design, the group will begin drafting the protocols, which will set the stage for the 2.5 to 3.5 years of implementation. ERCOT has estimated the project will take four or five years to complete.
“We’re not focused on the protocols yet,” Mereness said. “We’re determining the building blocks for real-time co-optimization.”
Helton was quick to say the RTC implementation would not follow the same course as ERCOT’s nodal market project, which was marred by cost overruns and blown timelines before going live in December 2010.
“Give me some comfort that we’re going to design the system, harden that and stop people from hanging their ornaments on the Christmas tree before we start building it,” said Director Clifton Karnei, general manager of Brazos Electric Power Cooperative and representative for the Cooperative market segment.
Claiming Karnei had stolen his words, Helton said, “What we’re trying to do is real-time co-optimization and not redesign the market. That nodal stuff was painful.”
Board Vice Chair Judy Walsh asked Mereness how the task force would respond when it gets stuck on an issue.
“We won’t be stuck silently,” Mereness responded. “If we get stuck, we’re going to let people know.”
IMM: Wind not Outpacing Coal — Yet
Responding to a recent spate of media articles noting that wind generation is outpacing coal generation in ERCOT, Independent Market Monitor Beth Garza tapped the brakes on what she said was a “zeitgeist” moment.
“There were a zillion articles over how wind has surpassed coal,” she said during her midyear market review. “That was absolutely true year-to-date through June. It’s no longer true through July.”
Garza said coal generation reasserted itself over wind generation in July. Coal now accounts for 21.1% of the fuel mix and wind 20.7% through July, she said.
“I do believe at one point, there will be more wind generation than coal generation in ERCOT, because we are very, very close now,” Garza said. She noted the switch is more about a decrease in coal generation, than an increase in wind.
Garza said ERCOT’s average energy prices are down through the first half of the year when compared with 2018 — $27.81/MWh versus $32.45/MWh — despite similar load conditions. She attributed the decrease to a 13% decrease in gas prices, which averaged $2.62/MMBtu through July, compared to $3.03/MMBtu in the first half of 2018.
Lange Approved as TAC Vice Chair
The board formally approved Clif Lange, South Texas Electric Cooperative’s manager of wholesale marketing, as TAC vice chair. Lange replaces Diana Coleman, who stepped down from the TAC when she accepted a position with San Antonio’s CPS Energy.
“We appreciate your willingness to serve,” board Chair Craven Crowell told Lange.
The directors also approved the Finance and Audit Committee’s recommendation to accept Maxwell, Locke & Ritter’s audit report of ERCOT’s 401(k) savings plan. The auditors said they were unable to obtain “sufficient appropriate audit evidence to provide … an audit opinion,” noting they were told not to audit, but did accept the plan’s investments and notes receivable. That information was certified by Fidelity Management Trust Co., the plan’s trustee.
Board OKs 14 Changes
The board approved a Nodal Protocol revision request (NPRR917) that replaces load zone energy pricing with nodal pricing for settlement-only distribution and transmission generators (SODGs and SOTGs). The NPRR allows SODGs and SOTGs to request ERCOT continue to provide them load zone pricing until they opt in for nodal pricing or until Jan. 1, 2030, whichever comes sooner.
The directors unanimously approved their consent agenda, which included nine other NPRRs, a change to the Nodal Operating Guide (NOGRR), an Other Binding Document (OBDRR) and two system change requests (SCRs):
NPRR823: Synchronizes the protocols’ “affiliate” definition with state law to allow exemptions for portfolio affiliates (two or more publicly traded companies in the same industry with common shareholders).
NPRR904: Revises the categories of ERCOT-directed actions that trigger the real-time online reliability deployment price adder (RTRDPA) pricing run to include DC tie-related actions to reflect current system conditions and corrects identified flaws with current RTRDPA design.
NPRR931: Modifies the hub average 345-kV price calculation to reflect the use of aggregated shift factors, as opposed to simple averaging of the component hubs’ prices.
NPRR932: Clarifies that new load added to an existing ERCOT system zone (including load from a non-ERCOT control area) can take effect immediately without board approval.
NPRR935: Requires ERCOT to post values for wind and solar forecasts and include an indication of which model is being used for each forecast. Also requires ERCOT to issue a market notice and sponsor an NPRR proposing requirements for any new future forecasts.
NPRR942: Clarifies in the protocols the timing of the posting of the final allocated transaction limit for the congestion revenue rights auction, also known as the second-round limit.
NPRR943: Adds Martin Luther King Jr. Day to the list of ERCOT-observed holidays.
NPRR944: Updates the day-ahead market’s energy bid curve criteria language to align with current validation.
NPRR949: Removes the use of standard voice telephone circuits as an option for the grid operator to retrieve ERCOT-polled settlement meter data, effective Jan. 1, 2023.
NOGRR187: Aligns the NOG with NPRR863’s revisions to ancillary services.
OBDRR009: Paired with NPRR904, the change revises the online and offline capacity reserves for out-of-market actions related to DC ties, preventing price reversal and price distortion whenever ERCOT makes out-of-market actions.
SCR801: Corrects the global process ID for Texas standard electronic transaction (Texas SET) 867_03 by applying the same data lifecycle cross-reference consistency for all 867-03 usage transactions.
SCR802: Improves system inertia communications by showing the real-time system inertia value under the Real-Time System Conditions display on the ERCOT website.
The Northeast Power Coordinating Council’s Regional Standards Committee last week held a forum on reliability issues related to distributed energy resources, featuring presentations by Hydro-Québec, Duke Energy, Ontario’s Independent Electricity System Operator and others. Here’s some of what we heard.
Duke Energy: Donuts and Data Sharing
Adam Guinn, lead system operations engineer for Duke Energy, gave a presentation on his work on modeling and processes to integrate DERs to support real-time monitoring and forecasting. Guinn said tighter coordination among transmission and distribution operators and planners is essential to managing the changes brought by DERs.
How does Duke do it?
“They [planners] buy me donuts,” Guinn joked.
Guinn said he has daily phone calls and in-person meetings at least quarterly with system planners, and also trades data with his counterpart who does solar studies for Duke’s planning group.
“Anything he sees he immediately sends to me, so we’re on the exactly same email chain in communication groups for any new solar, any new facility changes that may impact current solar dispatch. … We’re both tapped into the interconnection queue, and we do data analytics and tracking for growth and penetration so that we make sure that his longer-term stuff is keeping up with what we’re seeing in real time.
“We’re essentially coupled at the hip now, and that’s not just planning. It’s the same way with distribution. Distribution planners, transmission planners and operations … we’re essentially all transferring data and information and things that we’re seeing, lessons learned, back and forth in somewhat of a real-time fashion just because this stuff changes so fast.”
Guinn said having a common “knowledge base” is the key.
“What I’m finding is that all of these problems [would be] somewhat more manageable if people would stop talking past each other or stop working in silos and start transferring information,” he said. “So, if I were to wave a [magic] wand, I would get everyone on the same sheet music … and stop bringing people in who don’t have any operations experience to implement solar, to implement processes — or don’t have any planning experience.”
Task Force Guidelines for Interconnections
NextEra Energy’s Allen Schriver, chief operating officer of the North American Generator Forum (NAGF), discussed the work of NERC’s Inverter-Based Resource Performance Task Force, which is working with the Institute of Electrical and Electronics Engineers to develop the P2800 standard (Interconnection and Interoperability of Inverter-Based Resources Interconnecting with Associated Transmission Electric Power Systems).
Schriver said the task force is currently reviewing comments on its guidelines recommending improvements to interconnection agreements. The comment period closed July 24.
“What do you need to ask when you’re interconnecting inverter-based resources? … Essentially what you’re asking is: What do you want them to do? When do you want them to do it, and how fast?”
One recommendation is that DERs do not attempt to reconnect during black start events.
“If you come off during a black start, do not come back on until the [balancing authority] wants you to come back on. Do not automatically reconnect because … you may take the system back out,” Schriver said.
NERC, the NAGF and the Energy Systems Integration Group (ESIG) will hold a workshop Sept. 17-18 on storage, hybrid resources and frequency response. The workshop will be held at NERC’s D.C. office with a teleconference link to the organization’s Atlanta headquarters.
The workshop will include discussions on the capabilities of battery energy storage; motivations, drivers and challenges of hybrid projects; planning, interconnection and modeling; and ISO/RTO market rules.
Canada Adapts to DERs
The forum included presentations by several Canadian representatives.
Adnan Akhtar, supervising network management engineer for Hydro One, said his company is looking to change how it applies thermal limits on its system because more than 50% of its feeders in Ontario have less than 3 MW of generation capacity left.
“We’ve found that the non-exporting generation isn’t contributing to the thermal limit. We’re able to relax our thermal requirements to allow some more non-exporting generation to connect, at least at the feeder level,” he said, adding that the utility still must observe short circuit limits.
Akhtar said the company is implementing DER management systems to allow higher outputs. “We’ve always based our planning criteria on the worst case — minimum load, maximum generation — and that ends up leaving you underutilizing your assets for the majority of the year because your worst-case scenario probably happens maybe a few hours a year or maybe a few days a year.”
Mohab Elnashar, a senior engineer for performance validation and modeling for Ontario’s IESO, discussed the ISO’s 2019Operability Assessment, which looked at the impact of increased penetration of inverter-based DERs on the bulk power system, with a focus on light loading conditions.
DER management systems (DERMS) can allow higher outputs. | Siemens Industry
IESO has already seen instances of reduced power system responses after transmission faults. It also has identified a new single largest contingency (SLC), recognizing that under certain conditions, three-quarters of the province’s DERs could trip from a transmission fault, Elnashar said.
The loss of a single 878-MW unit at the Darlington nuclear plant has been Ontario’s SLC. “If the fault occurs at Darlington, a Darlington generator and DERs will trip, causing a new and very large SLC for Ontario,” Elnashar said.
The report found IESO has enough synchronous hydroelectric and nuclear generators to support system inertia and primary frequency response after a fault, but it recommended changing the voltage trip settings on inverter-based DERs. It is working with the Ontario Energy Board to adopt the new Canadian Standards Association rules on DER performance.
It’s also considering occasionally increasing operating reserves and seeking cost-effective transmission reinforcements that could reduce the DERs lost because of a single contingency.
“The only time we would need to increase the operating reserve is when we have light loading conditions [and] high penetration levels from the distributed energy resources,” he said. “During light loading conditions, we don’t have the gas units [to provide] voltage support in the load centers.”
Transmission planning engineer Nicolas Compas, of Hydro-Québec TransÉnergie, said that because his company’s generation is already 99% renewable, it has very few DERs and no decarbonization goals. Thus, it expects electric vehicles to be a bigger impact than solar PV generation. By 2030, it projects it may have 25% EV penetration but only 5% PV penetration.
Compas said the company tested the eight most popular inverter models to see how they react in low-voltage or low-frequency situations, how they manage ramping power, and how to change their settings. “None of them meets Hydro-Québec requirements,” he said.
“DER will grow in Hydro-Québec, that’s for sure. It will still be different from other utilities because of our weather, because of the [low] energy prices. … We have a slower adoption curve, so we can learn from many of the other utilities that already have a lot of DERs and can see issues coming up.”
SPIDER Working Group
Dan Kopin of Utility Services briefed the group on the work of NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group, which in June issued a draft reliability guideline with recommendations on developing underfrequency load shedding (UFLS) programs that can work with increasing DER penetration.
It is reviewing reliability standard MOD-032-1 to consider including DERs in interconnection-wide planning cases.
For insight on the impact on island-level system frequency as higher levels of load are served by DERs, the group has examined research by ISO-NE. It also found lessons in a September 2016 incident in which 850,000 customers in South Australia lost power after two tornadoes damaged three 275-kV transmission lines. According to a report by the Australian Energy Market Operator, the damage caused the lines to trip, resulting in six voltage dips over a two-minute period. The faults caused a drop in wind production and a surge in imported power that tripped an interconnector offline. The South Australia grid then islanded from the rest of the National Electricity Market.
“Without any substantial load shedding following the system separation, the remaining generation was much less than the connected load and unable to maintain the islanded system frequency. As a result, all supply to the [South Australia] region was lost,” the grid operator reported. It said the incident highlighted the need for more inertia to slow down the rate of change of frequency and allow automatic load shedding to stabilize the grid within a few seconds.
“The rate of change of frequency following separation (6.25 Hz/s) was too great for the UFLS scheme to operate effectively,” Kopin said.
He said he’s encouraged by the analysis that ISO-NE and others are doing on the growth of DERs. “I think it’s fair to say that all the planning coordinators involved with SPIDER are there because they get that this is a problem,” he said.
DES MOINES, Iowa — To mitigate cyberthreats to grid infrastructure, utilities must train their employees and become less wary of sharing information with other utilities, according to experts speaking at the Mid-America Regulatory Conference (MARC) on Monday.
Illinois Commerce Commissioner D. Ethan Kimbrel kicked off a panel on the subject with a reminder of last month’s ransomware attack on Johannesburg’s City Power, which encrypted the utility’s databases, applications and network, crippling its payment system.
Joe Randazzo, ITC Holdings’ director of networks and information security, said the most sophisticated “bear” (read: Russian) group of hackers can take as little as 18 minutes to gain access to a utility’s operational technology.
“A lot of times we’re fighting the ‘bears’ singlehandedly without the help of the federal government,” said Peter Grandgeorge, MidAmerican Energy program manager.
“Everybody in this room, whether you’re a vendor or a regulator, you’re a risk,” Grandgeorge said of the proliferation of phishing campaigns coming from compromised third-party emails.
“Most hackers are preying on the goodwill of people,” Randazzo agreed. “And hackers only need to be right once; employees have to be right 100% of the time. A person clicking on an email because they think they won a $50 Amazon gift card can have huge implications.”
Grandgeorge said when MidAmerican began conducting phishing tests among its employees a few years ago, the failure rate was at about 20%. He expects an upcoming test will yield just one or two failures out of the company’s approximately 3,750 employees.
“That sounds good, but we think it sounds terrible. Because it only takes one,” Grandgeorge said.
“I don’t want to say people are the weakest link, but if you can do phishing activities, you’ve plugged a big hole,” said Paul Hofman, vice president of IT at Central Iowa Power Cooperative.
Hofman said it’s preferable to provide cybersecurity training for an employee already well versed in utility operations than to a bring in a standard cybersecurity expert.
“You can’t just treat your operational technology like printers and PCs,” Hofman said, adding that one cybersecurity scan at his co-op set off several alarms to the exasperation of system operators.
Sam Ellis, SPP’s director of cybersecurity and controls, said finding talented people with cybersecurity experience is fast becoming a challenge as more positions open up.
Ellis also advocated for utility IT professionals to network among themselves to learn about different cybersecurity strategies. He said grid operators regularly share experiences at ISO/RTO Council meetings.
“There’s a saying that when you need a friend, it’s too late to make a friend,” Ellis said.
If SPP’s market system goes down, he said, “we feel confident that we can maintain reliability,” but the RTO has less confidence its system will continue to operate reliably if its energy management system is taken out. In that case, others — such as the transmission owners — still “have eyes on the system.”
Randazzo said cybersecurity intelligence is not regarded as the proprietary information it once was, and utilities are less “skittish” now about sharing threat possibilities with one another.
“This is a team effort,” he said. “We can share what we call IOCs: ‘indications of compromise.’”
Hofman said state utility commissions could help create a safe, secure space where utilities can confidentially share cybersecurity information without risking public exposure of sensitive materials.
Multiple panelists also urged utilities to submit cyberthreats to the Kansas City Regional Fusion Center, which can compare possible threats against its database of known ones.
Grandgeorge noted that cybersecurity can also require physical efforts, recounting that he’s taken FBI agents along on a wind tower climb to better understand how to regain control of hacked equipment. He said he didn’t consider the move an extraordinary measure after Chinese espionage agents were caught stealing seed corn in Iowa in 2016 in order to extract intellectual property from the genetically modified seeds.
