FOLSOM, Calif. – Members of CAISO’s Market Surveillance Committee and stakeholders wrangled over systemwide market power and ways to limit it during an occasionally testy two-hour exchange Monday.
In March, ISO staff issued an analysis of market power in response to a similar report by the ISO’s Department of Market Monitoring, an independent body within the ISO. The staff analysis found its balancing area was uncompetitive during a limited number of hours in 2018 — primarily during times of peak demand when natural gas generators came online. Hot summer days, especially, allow some suppliers to game the system, staff said.
“If we were to design a systemwide market power mitigation process, how would it look?” Perry Servedio, lead market policy design developer at CAISO, summed up the process.
The DMM’s report had used somewhat different criteria but arrived at similar results and recommended the ISO take action to reduce the conditions in which market power might exist.
To address the findings, the ISO and the Market Surveillance Committee have convened a series of monthly stakeholder meetings with the goal of generating an opinion by October. They’re expected to present their findings on the potential costs and benefits of market-power mitigation to the ISO’s Board of Governors in November.
Among the topics being discussed are how to screen for market power and, if found, how and when to take steps to mitigate it. For instance, should the ISO screen only in the real-time market or also in the day-ahead market? And is it appropriate to mitigate voluntary supply?
Not everyone agrees with the ISO’s market-power assessment.
In a presentation at Monday’s meeting, Market Surveillance Committee member Scott Harvey said the ISO’s test for market power is “very conservative.” Failing to pass it doesn’t show the market is structurally non-competitive, he said.
“The test is designed to err toward over-identifying the potential for the exercise of material market power because it is not possible to apply a more sophisticated test in the time frame of the day-ahead market or real-time,” said Harvey, of FTI Consulting.
Others said the process now underway is moving too quickly toward issuing a November opinion. Instead of the usual straw proposal that’s part of a lengthy stakeholder process, ISO staff are planning to go to the board with a committee opinion, which they jokingly call a “straw dog proposal.”
Michele Kito, a regulatory analyst with the California Public Utilities Commission, told the committee the process seemed rushed.
“My concern is we’re going to go to the board with a (plan) that’s prematurely designed, and they’re going to say, ‘don’t do any further action,’ and I think that is a mistake,” Kito said. She noted many stakeholder initiatives take years to develop and said a measure dealing with market power deserves more consideration.
“I think to prematurely sort of cut the legs out of this, which I kind of anticipate … is a shame,” she said.
Public Citizen asked FERC Monday to rehear its ruling dismissing complaints over MISO’s 2015/16 capacity auction, saying the commission failed to justify its finding that there was no market manipulation.
The public interest group said FERC’s conclusion that Dynegy did not manipulate the market and that the ensuing $150/MW-day clearing price in Southern Illinois’ Zone 4 was reasonable was wrong on both counts (EL15-70).
The Zone 4 clearing price was a nine-fold price increase compared with just $16.75/MW-day a year earlier. MISO’s other nine local resource zones cleared below $3.50/MW-day that year. Public Citizen, the Illinois Attorney General and Southwestern Electric Cooperative had questioned Dynegy’s market behavior because the company controlled a significant portion of the capacity available in Zone 4.
2015/16 MISO PRA results | MISO
In mid-July, FERC wrapped up a three-year-old investigation into MISO’s 2015/16 Planning Resource Auction by finding no market manipulation on Dynegy’s part. The commission also found Zone 4’s $150/MW-day clearing price just and reasonable, declining to set up an evidentiary hearing to possibly recalibrate the auction results. (See FERC Clears MISO 2015/16 Auction Results.) FERC said a clearing price isn’t unjust simply because it’s higher than expected.
“The commission did not include the evidence from the nonpublic investigation in the record, did not allow the parties to address it and did not say in even the most general terms what, in its view, that evidence showed. Nor did the commission address the arguments advanced by the parties as to whether manipulation had occurred,” Public Citizen said. “The commission offered no account of what, in its view, Dynegy had in fact done or of why that conduct did not amount to manipulation.”
FERC ruled that although Dynegy had pivotal supplier status and that substantial price separation occurred between Zone 4 and the rest of MISO, the RTO had conducted the auction in accordance with its Tariff and market power mitigation rules.
Public Citizen said it didn’t appear that FERC examined whether MISO’s circa-2015 market power provisions were effective. The omission was “striking,” Public Citizen said, because just eight months after the auction, FERC ruled that MISO’s rules for the 2016/17 auction were not just and reasonable. FERC said MISO didn’t accurately gauge power exports and its $155.79/MW-day maximum bid should be set closer to $25. (See FERC Orders MISO to Change Auction Rules.)
Commissioners Cheryl LaFleur and Richard Glick expressed displeasure last month that they were not consulted before Chairman Neil Chatterjee closed the investigation. In a dissent, Glick called July’s order a “wholly unsatisfactory response to the allegations of market manipulation,” saying FERC didn’t provide “even the scantiest reasoning to support its finding that the nearly 1,000% year-over-year increase in the MISO Zone 4 capacity price had nothing to do with market manipulation.”
Tyson Slocum, director of Public Citizen’s Energy Program, acknowledged the group’s chances of prevailing in the rehearing request were slim.
“We’re in this for the long haul,” he said in an interview. “The request for rehearing is not necessarily to change the commission’s vote but to get this before a federal court.”
QUEBEC CITY, Quebec — NERC’s Board of Trustees on Thursday approved the Electric Reliability Organization’s 2020 budgets and a data request on supply chain issues before saying goodbye to retiring General Counsel Charles “Charlie” Berardesco. Officials also announced two executive appointments and the successor to Chair Roy Thilly during their two-day quarterly meetings in Quebec.
The board approved the 2020 ERO Enterprise business plan and budgets, which will be submitted for FERC approval later this month.
NERC and the REs are increasing spending by 3.9% to $207 million, with total assessments projected to increase by 2.9%.
NERC’s $83.4 million budget is a 4.5% increase over 2019 and will be mostly funded by $72 million in assessments, also up 4.5%. Canada (+7.3% to $0.013/MWh) and Mexico (+6.0% to $0.016/MWh) face bigger assessment increases than the U.S. (+4.3% to $0.016/MWh).
NERC’s budget includes $500,000 for modifications to its Atlanta headquarters to provide more meeting space. “We expect to save $150,000 a year” in meeting costs after the renovations, Controller Andy Sharp said.
NERC is projecting an additional 5.6% increase in assessments for 2021 and 5.9% for 2022, but those amounts could be reduced by releases from its assessment stabilization reserve.
The increases are being driven by the five-year expansion plan for the Electricity Information Sharing and Analysis Center (E-ISAC), which added nine full-time equivalent employees this year and plans to add seven in 2020 and 14 through 2022.
Excluding the 13.3% increase for the E-ISAC, ERO spending will increase by 2.2%.
Thilly acknowledged the ISAC budget increase “is significant and will continue to be,” thanking stakeholders for their “strong support” for the spending boost.
The Canadian Electricity Association and Ontario’s Independent Electricity System Operator had questioned the increase in the E-ISAC, with the CEA expressing skepticism over the ISAC’s “value proposition” to Canada. (See ERO Budget Nears OK Despite Canada’s Concerns.)
At the board meeting, CEA CEO Francis Bradley commended NERC for “working to be more aligned with the fiscal and regulatory realities faced by electric utilities” but expressed concern that spending is projected to exceed inflation for the next several years.
“The magnitude of the ISAC budget increases are substantial, and, as such, it is essential there is corresponding value for all the stakeholders.” Bradley said.
In its comments on the budget, the CEA said the E-ISAC should take advantage of capabilities already available from other agencies, including the Canadian Cyber Centre, to avoid unnecessary duplication and spending.
“We see ourselves as never having enough expertise to do it on our own,” Chief Security Officer and E-ISAC Director Bill Lawrence told the Technology and Security Committee meeting on Wednesday. “Efficiency in an area like this is very hard … because if something happens, you never spent enough and never did enough.”
NERC CEO Jim Robb noted the memorandum of understanding the E-ISAC signed with IESO this summer. “We’re very optimistic about benefits to come from that. We’re going to focus on that with great vigor in the coming year.”
Robb said although the E-ISAC has had success in hiring good talent and increasing its capabilities, it remains limited by the data flowing into it from industry.
“How do we get more information flowing voluntarily into the E-ISAC? … That’s going to be one of our big pushes this year in outreach,” he said.
Supply Chain Data Request
The board approved a datarequest on the “the nature and number” of low impact bulk electric system (BES) cyber systems. The data request was a recommendation of the staff supply chain report approved by the board in May. (See “Supply Chain Report Recommends Expanding Standards” in NERC StandardsNews Briefs: May 8-9, 2019.)
NERC said the information will help it understand the risks associated with low impact systems with external routable connectivity and determine whether to modify the supply chain standards to include them.
“We’re not looking for an exact count of low impact BES assets. Instead, it’s a count of locations,” Director of Engineering and Standards Howard Gugel told the Member Representatives Committee (MRC) Wednesday.
The request is expected to be issued this week, with responses due in early October. NERC will schedule a webinar to address questions from recipients of the request. A summary of the responses will be presented to the board at its November meeting.
Gugel said NERC received 35 sets of comments on the request. Some commenters thought the request should be expanded to include vendors.
Gugel said although NERC does not consider the results confidential, it will only share results in the aggregate; no individual entities will be identified.
New Format for Q4 Meeting
Thilly said the board will experiment with an abbreviated open meeting immediately after the MRC meeting on Nov. 5 in Atlanta rather than the normal schedule of a half-day meeting the day after the MRC.
The open board meeting will be limited to action items, with committee meetings done in advance as conference calls.
The board will also meet with the regional entity boards and hold a closed strategic session. The MRC meeting schedule will not change.
Thilly said the new schedule will be a trial that may be used for future fourth quarter meetings, which he said “seem to have least essential things” on the agenda.
“As long as I can remember, we’ve had an internal debate about whether we should continue with four meetings a year or three meetings,” Thilly explained during the MRC meeting Wednesday. “On the one hand, you can see [from] all the people here how important these meetings are … On the other hand, sometimes we feel like the day after this meeting, staff [are] spending a lot of time preparing for the next meeting, and that has an opportunity cost associated with it.”
“That’s what we intend to try in November. We’ll see how it works and what feedback we get,” he said.
Robb announced the appointment of Deputy General Counsel Sonia Mendonca as interim general counsel and corporate secretary, replacing Berardesco, who is retiring at the end of this month.
In addition, the Board of Trustees promoted Sharp to vice president. Sharp will also continue as the interim chief financial officer, a role he has served since the May departure of former CFO Scott Jones, who also served as chief administrative officer.
“Since Scott Jones left NERC after Memorial Day, Andy Sharp has effectively been our top financial executive,” Robb said. “I really appreciate him stepping in and stabilizing this organization.”
NERC last month hired an executive search firm to find permanent replacements for general counsel and chief administrative officer. (See NERC Leadership Search Announced.)
Stakeholders gave Berardesco a standing ovation for his seven years as general counsel and his nearly seven-month stint as acting CEO after the resignation of Gerry Cauley.
“He has been extremely dedicated to this organization,” Thilly said. “As everyone knows, he stepped into the breach in November [2017] as acting CEO. [He] really held everything together in a way that was quite seamless. No gaps. We will be forever grateful.”
Robb read a proclamation praising Berardesco, and SERC Reliability CEO Jason Blake thanked him for his mentorship.
“Charlie has meant a lot to me personally through his wise counsel,” Blake said. “One of the things he shared with me one time that really stuck with me was to do things with intention in all that you do. What is the purpose? That’s something that resonated with me. Something that I will take with me.”
Berardesco said it was an “overwhelming honor … to be able to spend this last part of my active career working on the other side” after almost 10 years at Constellation Energy.
He thanked the board members and his NERC colleagues and his “marvelous” deputy, Mendonca.
The board also announced Ken DeFontes will become chairman when Thilly’s term ends in February 2021. Thilly will remain on the board.
NERC also will be seeking a replacement for Janice Case, who will end her final term in February 2020. (The board increased to 12 members with the election in February of Colleen Sidford, representing Canada. It will drop back to 11 in February 2020 following the departure of Case and Frederick W. Gorbet.)
Nominating Committee Chair George Hawkins said the committee will meet in September to narrow the candidates to a short list to be interviewed in person.
At the board meeting Thursday, Robb asked ERO Insider to note he was wearing Boston Red Sox cufflinks and a New England Patriots tie in honor of departing FERC Commissioner Cheryl LaFleur. “We didn’t always agree on everything but always had a great opportunity for exchange,” he said.
Former NERC Chief Security Officer Mike Assante died July 4. | Sans Institute
Robb also noted the passing of Mike Assante, the head of SANS Institute’s industrial control system and SCADA security operations, who died July 5 of cancer. A former naval officer, he was NERC’s first chief security officer.
“We probably wouldn’t have the E-ISAC without Michael Assante,” Robb said.
He “left some big shoes to fill,” said Bill Lawrence, the E-ISAC director and current chief security officer.
Other Actions
The board also approved:
BAL-002-WECC-3 (Contingency Reserve): Replaces the Western Electricity Coordinating Council’s BAL-002-WECC-2a, Requirement R2, which became redundant with the implementation of BAL-003-1.1, Requirement R1 on April 1, 2016. WECC conducted a field test that concluded the retirement of the old requirement would not harm reliability.
Amendments to ReliabilityFirst’s bylaws to incorporate NERC’s Consolidated Hearing Process (Section 403.15 of NERC’s Rules of Procedure) and replace RF’s regional hearing process.
An update to the Compliance and Certification Committee’s (CCC) program for monitoring adherence to NERC’s Rules of Procedure for compliance monitoring and enforcement, which was last revised in 2015.
An update to the CCC’s procedure for qualifying for eligibility to submit implementation guidance to the ERO, last revised in 2016.
The federal judge overseeing Pacific Gas and Electric’s bankruptcy ruled Friday against bondholders and insurers that wanted to offer their own reorganization plans for the embattled utility, but he allowed fire victims to proceed with a lawsuit blaming it for one of the most destructive blazes in state history.
Judge Dennis Montali, of the U.S. Bankruptcy Court for the Northern District of California in San Francisco, said it wouldn’t be in the interest of fire victims to let competing Chapter 11 plans confuse the proceedings. He gave PG&E until Sept. 26 to offer its own plan without interference, in keeping with a so-called exclusivity period he had earlier granted the utility.
PG&E’s unsecured bondholders had offered it an injection of $30 billion, including $18.4 billion for fire victims, in exchange for guaranteed payment of more than $10 billion in notes, which otherwise could go unpaid in bankruptcy. PG&E’s lawyers argued the deal would give the bondholders — a group of banks, mutual funds and other investors — control of the company at a heavily discounted price and could lead to chaos in the Chapter 11 proceedings. (See Judge Weighs Competing PG&E Bankruptcy Plans.)
Montali agreed the plans would likely lead to unnecessary confusion and delay.
“Competing plans are tempting, and no doubt produce a feast for lawyers, accountants, investment bankers and others, not to mention the intellectual challenges to the court,” Montali wrote in his decision. “But the inescapable fact is that the fire victims and their insurers should not need to wait for conclusion of expensive, lengthy and uncertain disputes that only indirectly concern them.”
PG&E has said it will file its own plan by Sept. 9. A recent outline says the utility will pay its debts and compensate fire victims by raising money through stock offerings. In documents filed with the U.S. Securities and Exchange Commission earlier this month, two hedge funds — Abrams Capital Management and Knighthead Capital Management — pledged to backstop PG&E’s plan with $15 billion in equity financing to provide “a foundation upon which a more fully developed capital plan and plan of reorganization can be built.”
PG&E has “placed before all a proposal that, if coaxed and guided to maturity, should result in a proper outcome for all creditors without needing to deal with all of these other issues,” the judge wrote.
Judge Dennis Montali | Commercial Law League of America
Continuing his focus on fire victims, Montali decided that two cases could move forward in state court that allege PG&E caused the Tubbs Fire, which ravaged California wine country in October 2017 and burned down part of the city of Santa Rosa.
Investigators with the California Department of Forestry and Fire Protection determined a private landowner’s faulty wiring started the Tubbs Fire, but plaintiffs’ lawyers hope to convince a jury otherwise. The massive blaze killed 22 people and destroyed more than 5,600 structures in Sonoma, Napa and Lake counties. (See related story, Lawyers Argue over PG&E Wildfire Liability.)
Montali cited the plaintiffs’ estimates that the Tubbs Fire could account for two-thirds of PG&E’s liability for the 2017 and 2018 fires in Northern California that led to it declaring bankruptcy in January. Those fires include the Camp Fire, the deadliest in state history, which leveled much of the town of Paradise and killed 85 people.
Resolving liability for the Tubbs Fire will help the bankruptcy court determine PG&E’s estimated liability for those fires so that victims can be compensated appropriately, he said. Montali said that, despite PG&E’s objections, he didn’t think the lawsuits would interfere with the bankruptcy proceedings.
“The state court trial may proceed on a parallel track to the proceedings in this court,” the judge wrote in a separate ruling Friday.
ERCOT on Friday said it has approved NRG Energy’s plans to return its Gregory Power Partners cogeneration plant to mothballs in October. The plant, which returned to service in June for the first time since 2016, will be operated annually from June 1 through Sept. 30.
The Texas grid operator said it conducted a reliability analysis that determined the plant’s combined cycle units are not required to support system reliability during the portion of the year when they are mothballed.
The Sherwin Alumina plant, Gregory Power Partners’ cogeneration partner, shut down in 2016. | Sherwin Alumina
Gregory Power Partners, a three-unit, 365-MW facility located outside Corpus Christi, was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. The plant was built in 2002.
NRG said in May it was returning the plant before the summer months to provide “additional reliability to our customers.” (See NRG to Bring Back Gas Plant for Summer 2019.)
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.”
