SPP signaled it could be on the verge of further expanding its RTO footprint with an announcement Thursday that several Western utilities are committed to evaluating membership in its regional electricity market.
Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska (MEAN), Tri-State Generation and Transmission Association and the Western Area Power Administration would become the first SPP members to have facilities in the Western Interconnection under the RTO’s Tariff.
WAPA’s membership would include participation of its Upper Great Plains-West (UGP-West) region and Loveland Area Projects, the RTO said.
The utilities, some already members of SPP in the Eastern Interconnection, have all sent letters expressing their interest in placing their Western facilities under the RTO’s Tariff. The letters indicate they will work with SPP to evaluate the terms, costs and benefits of doing so, the grid operator said.
Tri-State staked out a leadership position within the group, devoting part of a Thursday press conference with Colorado Gov. Jared Polis to extoll the benefits of RTO membership. The virtual event was to highlight Tri-State’s electric resource plan, to be filed with the Colorado Public Utilities Commission next month, that will “dramatically” increase its renewable resources and reduce emissions. Under Polis, Colorado has established a goal of 100% renewable energy by 2040.
Tri-State CEO Duane Highley said connecting the West’s solar capacity with the East’s abundant wind capacity — Kansas and Oklahoma both produce more wind energy than they can use — will efficiently facilitate the transfer of additional generating resources across the regions and offer an opportunity for greater solar resource development.
“The next step for us is to help develop an RTO in the West,” Highley said. “In order to [meet our emission-reduction targets], we know we have to coordinate regionally. We want to do everything we can to accelerate this transition to a regional grid. This doesn’t eliminate any of the other options. … We know we have to improve transmission access.”
SPP’s RTO footprint should it expand into the West | SPP
Noting SPP has seen renewable energy account for nearly 80% of its fuel mix at times, Highley said “we’re going to need that same coordination as we build and integrate renewables into a broad region.”
“Enhancing regional markets will lead to additional efficiencies, reliability and more cost savings,” Polis said, echoing Highley. “[RTOs] are really important to support the integrity of a higher level of renewables across a broader geographic area.”
“We’ve enhanced electric reliability while integrating more renewable generation than many in our industry ever thought possible; modernized the grid; built and operated a dependable and economic market; and equitably allocated the costs and revenues associated with these and other services,” SPP CEO Barbara Sugg said in a statement. “What’s more, we’ve done it all while staying true to our collaborative and member-driven business model, and now we’re excited for the opportunity to bring the value of RTO membership to new customers in the West.”
‘Substantial Benefits’
SPP said a Brattle Group study conducted for the RTO found the move would be mutually beneficial and produce $49 million in annual savings for current and new members. Western utilities would receive $25 million a year in adjusted production cost savings and revenue from off-system sales. Members in the Eastern Interconnection would benefit from $24 million in savings because of the market’s expansion, transmission network and generation fleet.
An SPP spokesman said the report would be shared publicly once it has been reviewed by the membership in December.
“We anticipate the benefits of these entities joining our RTO to exceed those quantified in the study,” SPP’s Derek Wingfield said. The study’s scope was limited only to adjusted production cost savings and the value of off-system sales.
“But there are numerous other, substantial benefits of RTO membership as we’ve demonstrated for years in the Eastern Interconnection,” he said. “We at SPP hope the evaluation of full RTO membership leads to even more chances to help Western stakeholders lower energy costs, integrate more renewable energy and modernize the grid.”
The utilities and Deseret are also customers of at least one of SPP’s contract-based Western Energy Services, which includes reliability coordination and its Western Energy Imbalance Service real-time market scheduled to launch in February 2021. SPP’s Western RC service will celebrate its one-year anniversary in December.
Tri-State was part of the Mountain West Transmission Group, a coalition of 10 Western utilities that briefly pursued SPP membership in 2017 and 2018. The effort fell apart when Xcel Energy left the group and later committed to join CAISO’s Energy Imbalance Market. (See Xcel Leaving Mountain West; SPP Integration at Risk.)
Tri-State spokesman Mark Stutz said Mountain West’s failure did not end the utility’s “long-term interest in and goal to ultimately participate in a regional transmission organization for our region.”
“Tri-State’s participation in a Western Interconnect RTO is essential to advance our members’ reliability, affordability and clean energy goals,” Stutz said. “While the issues are complex, we remain optimistic that together we are on a path that can capture the full benefits of an organized market in the West.”
SPP’s expansion would add Colorado and Wyoming to the RTO footprint, which would then encompass all or part of 15 states.
Rolling blackouts, massive wildfires and extreme heat produced a “surreal summer” in the Western Interconnection that panelists examined during the National Association of Regulatory Utility Commissioners’ annual meeting Wednesday.
The blackouts ordered by CAISO on Aug. 14-15 were not the only extraordinary measures taken to deal with a heat wave that outstripped even normal August highs and sent the temperature in Death Valley to 130 degrees Fahrenheit on Aug. 16.
“This wasn’t just a California event,” said Washington Utilities and Transportation Commissioner Ann Rendahl, who moderated the online panel entitled “Lights Out! Lessons from the West’s Surreal Summer Season.”
Washington UTC Commissioner Ann Rendahl moderated a NARUC panel on the West’s ‘surreal summer.’ | NARUC
“The excessive heat across the Western United States resulted in stress for many balancing authorities due to the high air conditioning demand,” Rendahl said. “WECC identified 18 emergency alerts from balancing authorities across the West between Aug. 14 and Aug. 19. A similar event could have occurred in several areas in the West.”
The summer wildfires that blanketed the West in smoke and shut down power in parts of California and Oregon added to the stress on residents and the grid, she said.
Learning from the summer’s events to avoid future blackouts is vital, Rendahl said.
Other panelists were former FERC Commissioner Cheryl LaFleur, a member of the ISO-NE Board of Directors; Ahmad Faruqui, an energy economist and principal with the Brattle Group; David Geier, COO of San Diego Gas & Electric; and Mark Rothleder, COO of CAISO.
Geier spoke about his utility’s lauded efforts to prevent fires in the past decade, such as grid hardening, weather monitoring and public safety power shutoffs (PSPS) to keep utility equipment from sparking blazes.
Rothleder walked through the findings of a preliminary report on the causes of the August blackouts, including day-ahead forecasting failures, untimely exports and limited transmission to import energy from neighboring states. (See CAISO Says Constrained Tx Contributed to Blackouts.)
Faruqui said the summer’s blackouts and PSPS events reminded him unpleasantly of the Western energy crisis and rolling blackouts of 2000/01. This time, his family had battery backup in their home, but hundreds of thousands of customers lost power and air conditioning amid triple-digit temperatures and thick smoke from wildfires.
“We felt we were living at the edge of darkness,” Faruqui said.
Talking with colleagues around the world, he said, he realized “everyone was watching what was happening in California.”
Spur to Regionalization?
LaFleur said that to prevent future outages, California and other Western states pursuing aggressive decarbonization must work harder to ensure they have adequate resources. Arizona, California, Nevada, New Mexico and Washington have ambitious clean energy goals, with other states expected to follow suit.
Renewable resources are not the problem, LaFleur said. The extreme weather conditions and fires of August argue for more carbon-free energy to stem climate change, she said.
But states switching to large amounts of wind and solar need dispatchable resources for the times when wind and solar drop offline, she said.
“I think part of the issue in California, systemically, has been not enough dispatchable resources at the right time to balance the solar and wind,” LaFleur said. “California has been very decisive about what resources it doesn’t want, but it’s suffered from a pattern of closing resources before the ones that were supposed to replace them were online. That included losing 10,000 MW of gas in recent years, [while] planning on new resources, including large-scale storage that’s not online yet.”
Studies have shown states can substantially decarbonize the grid while retaining gas plants that are infrequently used but available when needed, she said.
The other big issue is who’s in charge of resource adequacy, she said. RA planning can only work with “clear lines of authority and clear handoffs to make sure that whoever has their hand on the switch running the grid has enough energy when they need it.”
California has a “particularly tangled and complex set of responsibilities for making sure there’s enough resources available to keep the lights on,” LaFleur said. The state Energy Commission forecasts long-term demand; the Public Utilities Commission orders yearly procurement; the ISO runs the grid on the resources it is given, with limited backstop purchasing authority; and the legislature dictates what type of resources are acceptable for load-serving entities to buy, she noted.
The agencies and the ISO need to work together better and with FERC to make sure there are adequate resources going forward, she said.
Western regionalization could also help California and other states ensure there’s sufficient energy while pursuing decarbonization, she said. In past years, California lawmakers have considered efforts to change CAISO’s governance structure to allow it to lead a Western RTO, but without success. Other Western states have also resisted the idea. (See Western RTO Proponents Vow to Keep Trying.)
“I hope that this summer’s events are a spur to think about that one again,” LaFleur said.
ITC Holdings is used to severe weather, with a 16,000-mile transmission network that faces harsh winters in Minnesota and tornadoes in Oklahoma.
Darrel Yohnk, ITC Holdings | NERC
But the derecho that hit ITC’s operations in Iowa on Aug. 10 was a new kind of challenge, forcing the company to seek mutual aid for the first time in its nearly two-decade history, Director of Real-Time Operations Darrel Yohnk told NERC’s eighth annual Monitoring and Situational Awareness Technical Conference on Tuesday.
A derecho packs wind speeds equal to a Level 2 hurricane, but the winds blow in straight lines rather than circling. They can occur in a band of rapidly moving thunderstorms when rain-cooled downbursts reach Earth’s surface and spread horizontally.
“A lot of thunderstorms have [downbursts],” Yohnk explained. “What makes a downburst a derecho is the fact that these downbursts can be self-propagating, and they suck more dry air into the storm, making the winds even stronger.”
The National Weather Service defines a derecho as wind gusts of at least 58 mph that cause a swath of damage of at least 240 miles, “which is just huge,” Yohnk said.
The National Oceanic and Atmospheric Administration said the August storm was the most costly thunderstorm disaster in U.S. history, causing four deaths and an estimated $7.5 billion in damages over a 700-mile path from Iowa to Indiana.
Time lapse images show the derecho’s path through Iowa, Illinois and Indiana. | National Weather Service
The storm, which carried wind gusts exceeding 100 mph, knocked out more than 1,200 miles of transmission on 144 lines, nearly 20% of ITC’s Midwest network. Almost 800 workers were brought in from other companies to help replace more than 1,000 wooden and steel poles.
The nuclear-fueled Duane Arnold Energy Center near Cedar Rapids, Iowa, lost off-site power for almost a day. The plant got its emergency on-site power running just 11 minutes before losing off-site power, after the loss of four 161-kV, one 115-kV and two 69-kV lines, Yohnk said.
The system “got weak enough that when the [345-kV] Duane Arnold-Hazleton line tripped, the impedance changes on the system were massive. We experienced a power swing event, with the Duane Arnold area swinging against the rest of the [Eastern] Interconnection.”
ITC outages resulting from the Aug. 10 derecho | ITC Holdings
During the swing, zone 1 relay settings caused the tripping of a 161-kV and two 69-kV lines which created an electrical island of the nuclear plant and some load out of Hiawatha, Iowa. “A few seconds later, the island breaks up further and the remaining [345-kV] Duane Arnold-Hiawatha line tripped and that isolated the plant by itself,” Yohnk said.
The 161-kV Duane Arnold-Hiawatha line exceeded its system operating limit, with flows 9.5% above the short-term emergency rating for 1.4 minutes. “Of course, we were implementing our operating plan to address that. The plant was ramping down as fast as it could, but this storm activity was impacting us faster than … we could get the unit ramped down,” Yohnk said.
ITC, a unit of Fortis, lost more than 900 MW load, with 500,000 customers — 30% of its Iowa customer base — losing power.
The last customers were energized at midday Aug. 18 after eight days, “which was a phenomenal feat for us,” Yohnk said.
Operating During Pandemic
Yohnk and officials from American Electric Power and Florida Power & Light also shared with the conference their experiences in running their grid operations during the coronavirus pandemic.
ITC’s operations control room (OCR) is located in Novi, Mich., 30 miles from Detroit, which in March was one of three COVID-19 hotspots in the U.S., along with New York City and New Orleans.
Workers repair a broken transmission pole following the Aug. 10 derecho in Iowa. | ITC Holdings
ITC had a “fairly generic” pandemic plan, Yohnk said. The plan had been “pretty much theoretical because we really haven’t had opportunities to implement it, fortunately, over the years, unlike our transmission system response plan,” which was activated during the derecho.
ITC removed its operations planning and relay performance engineers from the control room and issued a work-from-home order March 16 while soliciting volunteers for sequestration.
It created three “waves” of staffers to provide day/night coverage for the OCR and two groups for the physical security command center, with one group sequestered on-site and the others sequestered at home. ITC contracted for all three floors of a hotel adjacent to its headquarters to house the workers.
The OCR staff worked 14 consecutive 12-hour day or night shifts before being replaced. Operators tried to avoid using the same consoles in consecutive shifts.
Other staff provided “daily life assistance” to the sequestered workers, such as delivering groceries and medical supplies, and caring for pets.
The company also sanitized its backup control center — a facility 35 miles from its primary control center that is normally used for training — in case it was needed.
Phil Hoffer, AEP | NERC
Being sequestered increased the camaraderie of the groups, Yohnk said. “A lot of times in their normal day to day … they get focused on their own work activities and they don’t interact as much on a personal level. The sequestration did give them the opportunity to do that on a much more frequent basis.”
Phil Hoffer, the manager of emergency management system applications at AEP Transmission, said the company did not implement sequestration but that 13,000 of its 17,000 employees began working from home and will probably do so until at least summer 2021.
Hoffer said workers used levity — sharing favorite pandemic songs and goofy high school pictures of themselves — to keep their spirits up. “I think that really helped our employees and supervisors with the stress they were experiencing as a result of all the changes,” he said.
Rob Adams, FPL | NERC
“For the most part, we’ve actually been more productive out of the office than we were in the office” because of fewer interruptions, Hoffer said. “Now, my group’s a little different because only one of the people on our team has school-age kids at home. I think your ability to get things done would change dramatically if you had three or four or five school-age kids at home.”
Hoffer said the company uses video of all its attendees for its remote meetings. “I think it’s easier to pay attention if you’re on camera,” he said. “We’re trying to find ways to make it more like we’re in a meeting, where you kind of have to pay attention.”
Rob Adams, FPL’s senior director of grid control systems for power delivery, briefed the conference on the tools the utility deployed to stay connected, including Microsoft Teams to facilitate remote communication and collaboration.
FPL also used Klaxoon, an app that helps managers keep staff engaged during remote meetings by allowing them to answer questions via their cellphones. “They enjoyed the idea of reacting to the presentations,” he said.
MISO is down to two options to curb generation developers’ ability to change their proposed projects’ fuel type in the interconnection queue.
Ryan Westphal, MISO manager of resource utilization, said the RTO may use either a combination of a new selection on its interconnection application that temporarily leaves the door open to the fuel change, or a hard deadline on when interconnection customers can make that change.
Leeward Renewable Energy Development has a wind project currently in the DPP. The developer wants to convert the project to solar energy while also retaining its position in the queue. MISO has expressed concerns that allowing fuel-type changes in the DPP could delay studies and allow developers to submit speculative or ill conceived projects.
Staff may introduce a check box on interconnection requests where the customer could preserve its option to switch fuel types. That would have the RTO studying the interconnection request at 100% dispatch of the most conservative fuel type until the customer can confirm its fuel type.
Speaking at an Interconnection Process Working Group teleconference Tuesday, Westphal said MISO might also create a fixed deadline for interconnection customers to name any fuel changes. He cautioned that proof-of-site control is predicated on fuel type. For instance, a wind farm usually requires more acreage than a solar array or storage facility. He said flexibility in fuel types “would create difficulty in processing site-control documentation.”
Customers in MISO’s interconnection queue must demonstrate 100% site control 90 days before their proposed projects enter the DPP.
| MISO
Westphal said MISO would most likely disallow fuel-type changes after the queue’s second decision point, which occurs roughly 220 days after the DPP begins. He said staff would make an exception for interconnection customers who want to apply to use surplus interconnection service after the second decision point. He said it’s MISO’s preference to not allow fuel type changes while engineers are conducting studies.
The two surviving options are down from four that MISO initially offered.
A previous MISO suggestion to study every interconnection request at a 100% output proved unpopular among stakeholders because it would have created unnecessary transmission upgrades.
“This option is out the door. We’re not even looking at it anymore,” Westphal said.
Stakeholders also said they didn’t want MISO to place a blanket ban on fuel-type changes in the DPP.
Westphal said stakeholders seem most interested in fuel changes that involve adding storage to existing projects.
“It feels like the feedback we’re getting focuses on the option to add storage to an existing interconnection request,” he said. “Because of that, we did try to mold our proposal around that.”
Entergy’s Yarrow Etheredge asked whether MISO considered that a late storage addition to a generation project could be classified as a technological advancement instead of a material modification.
Westphal said too many storage additions to existing project proposals would still burden the study team.
“If we’ve got 10 of these stacked up, do we delay the decision point while we study all of them?” he asked rhetorically.
Etheredge said it’s incumbent on the interconnection customer to have already completed a study to make sure that the technological advancement wouldn’t have an adverse impact on other generation projects in the queue.
Nevertheless, Westphal said that storage additions in the DPP would introduce new dispatch assumptions that have not been studied until that point.
Westphal said MISO would consider some changes to its proposal. He promised he would return in January with a more final proposal that could be filed at FERC as soon as June.
Evergy has pushed back against a media report that it recently rebuffed a $15 billion acquisition offer from NextEra Energy, issuing a statement Tuesday that “there is currently no offer or bid from any third party for a potential transaction.”
Reuters on Monday quoted anonymous sources in saying that Evergy, which serves 1.6 million customers in Kansas and Missouri, turned down the offer. (See Report: Evergy Rebuffs NextEra Energy Bid.)
“Since announcing the STP, there has been no change in circumstance that alters the basis for this decision,” Evergy said in its statement.
The plan follows a “comprehensive, independent review” that began earlier this year as part of an agreement with activist investor Elliott Management. The STP calls for $8.9 billion of capital investments in facility upgrades, grid modernization technologies and clean energy initiatives through 2024 in the company’s Kansas and Missouri service territory.
Evergy’s service territory spreads across Kansas and Missouri. | Evergy
“We remain confident that the STP, which Elliott publicly endorsed when it was announced, is the best risk-adjusted path forward and that all appropriate steps are being and have been taken to maximize shareholder value. We will continue to act accordingly,” the company said.
Kansas and Missouri regulators have both opened dockets on the STP. Evergy said during its quarterly earnings call Nov. 5 that it expects to shortly file a jointly developed procedural schedule with the Kansas Corporation Commission that extends into 2021.
Missouri Public Service Commission staff face a Jan. 29 deadline to file a report on the STP.
“We don’t expect the commissions to take specific action regarding STP in either of those dockets,” Evergy CEO Terry Bassham said during the call. “The main purpose is to gather other information on and review our STP and ensure our continued resolve in meeting previous merger commitments while providing a forum and repository for stakeholder feedback.”
Evergy CEO Terry Bassham | Evergy
NextEra, armed with a three-figure stock price in recent years, has been on the hunt for regulated utilities. It has come up short in bids for Hawaiian Electric, Texas’ Oncor and national powerhouse Duke Energy. The company did pick up Gulf Power and Florida City Gas in a $6.4 billion deal in 2018 with Southern Co. and shelled out $660 million for independent transmission company GridLiance in September. (See NextEra Buying GridLiance for $660M.)
The company’s share price opened at $76.56 on Tuesday. NextEra’s common stock went through a four-to-one split in October to make its ownership “more accessible.”
MISO stakeholders sounded alarm bells this week, saying another round of prohibitively expensive system upgrades would render the RTO’s West planning region a “dead zone” for new generation.
MISO West — which includes Minnesota, Iowa, parts of the Dakotas and western Wisconsin — is again facing high system upgrade costs for interconnection hopefuls, this time from SPP studies of generator interconnections, or affected-system studies, along the seams.
SPP’s draft studies of a 2017 cycle of generation projects in MISO West recommend about $500 million of upgrades for 250 MW of projects.
“There are still a lot of coordination issues remaining with SPP,” EDF Renewables’ Anton Ptak said in raising the issue during the Interconnection Process Working Group’s (IPWG) teleconference Tuesday.
Several stakeholders agreed, saying that few projects will proceed in the west at this rate and characterizing the issue as a process failure. They said part of the problem lies in SPP using the stricter network resource interconnection service (NRIS) standard to model all service requests, making upgrades costlier and unnecessary in some cases. MISO uses the more relaxed energy resource interconnection service (ERIS) standard in its affected-system modeling.
“It is a bigger issue. Everyone should be concerned about this,” Savion’s Chad Craven said. “It’s basically going to roadblock everything in the west.”
MISO planning regions | MISO
Craven said the problem should alarm all stakeholders, not just interconnection customers and transmission owners. “The west is essentially going to be a dead zone,” he warned.
“We’re aware of the report and the costs that came from that report. … We understand the difficulties,” said Ryan Westphal, MISO’s manager of resource utilization. Staff said that if stakeholders have an issue with SPP criteria, they should follow the issue in that RTO’s interconnection stakeholder groups.
“MISO should significantly care about this. Without MISO trying to do something about it, it’s going to become a big problem and stalemate things in the west and then in the south,” Craven said. “If nothing else, MISO should be educating stakeholders on why this is happening.”
MISO Senior Corporate Counsel Christopher Supino said there are limits to what the RTO can do about SPP’s study process. He said FERC recently decreed that RTOs are free to choose between NRIS or ERIS modeling standards.
Stakeholders said MISO should make the effort to have meaningful conversations about the problem with them.
“It is extremely concerning. This is going to kill MISO West generation projects,” IPWG Vice Chair Angela Maiko said, adding that the August 2017 batch of projects will probably also be imperiled by high upgrade costs. She said the region runs the risk of never welcoming new generation unless it’s for replacement or surplus interconnection service.
Maiko said MISO may want to consider waiving its project withdrawal fees if SPP’s affected-system studies continue revealing high upgrade costs.
“In my opinion, this is a MISO issue. Even if SPP doesn’t return huge costs for [the] August 2017 [cycle], upgrades are going to cascade. You can see where the problem is going to persist. It’s a fundamentally huge issue,” Craven said, calling the situation “toxic.”
The Clean Grid Alliance, Solar Energy Industries Association and the American Wind Energy Association said recent upgrade costs have been raising renewable projects’ costs by more than 60% on average in MISO West.
A Siemens system impact study prepared for MISO in March showed that a cluster of 60 western wind generation projects dating back to 2018 and totaling 9 GW would collectively require more than $1 billion in transmission upgrades before they could interconnect.
The estimate prompted MISO to examine ways it could coordinate its interconnection upgrade studies and planning studies under its annual Transmission Expansion Plan. Its hope is to approve more multifunctional transmission projects. (See MISO Processing Heftiest Interconnection Queue Ever.)
A former president of the California Public Utilities Commission said Tuesday that the state attorney general should look into the rolling blackouts of mid-August with an eye toward signs of market manipulation in CAISO’s grid.
Loretta Lynch, CPUC president from 2000 to 2002 and a commissioner through 2005, spoke during a webinar held by the Clean Coalition, a Santa Barbara, Calif., group that advocates for renewable energy and microgrids.
Loretta Lynch | University of California
“I think it’s time for the California attorney general to investigate what happened at the ISO and, more than that, the ISO’s market practices that can’t keep the lights on,” Lynch said.
California should have had ample supply to meet peak demand this summer, including Aug. 14-15, when CAISO ordered rolling blackouts, she said in her online presentation.
The state had ordered load-serving entities to procure nearly 53,000 MW for summer load, including a 15% reserve margin. Blackouts were ordered when demand was less than 46,000 MW on Aug. 14 and less than 45,000 MW on Aug. 15, she noted.
Lynch asked why CAISO had allowed large amounts of energy to be exported on those days despite knowing that a Western heat wave would stretch supply and limit imports.
“On Aug. 14, as Californians are being begged to conserve power, the ISO allowed over 4,000 MW of electricity to be exported out in the middle of an extreme heat wave despite the carefully constructed and planned-for demand forecast,” she said.
As a public benefit corporation, CAISO is primarily responsible for ensuring in-state reliability, and the attorney general has additional authority to investigate it, she said.
Like other critics, Lynch questioned the role that convergence bidding, a purely financial hedge, may have played in exacerbating the August shortages. CAISO maintained convergence bidding during the blackouts but stopped it in the days afterward, explaining that the practice was clouding its picture of physical supply.
CAISO spokeswoman Anne Gonzales said the ISO has been open and forthright in its take on what happened, including regarding exports.
Among its findings, the preliminary root cause report said that on Aug. 14 and 15, “under-scheduling of load [by LSEs’ scheduling coordinators] and convergence bidding clearing net supply signaled that more exports were supportable.”
That report “has been shared publicly and presented in a public hearing to the California State Assembly shortly after its release,” Gonzales said in an email. “The ISO, CEC and CPUC stand behind the preliminary findings and will continue to work on a final report, which will be completed by the end of the year.
“There has been no factual basis to suspect that market manipulation played a role in the August outages,” she said.
David Olsen, who until last month served as chair of the CAISO Board of Governors, plans to retire Nov. 30, the ISO said Wednesday.
A clean energy leader and former head of outdoor-gear maker Patagonia, Olsen joined the board more than eight years ago and served as its chair from February 2018 to Oct. 1. He led the ISO during a time of great change, as California moved to phase out carbon-emitting resources and adopt renewable energy and storage.
He was also instrumental in the creation of the Western Energy Imbalance Market (EIM), which by 2022 is scheduled to include 22 participants in states across the West.
“I’ll be 75 years old soon, and have been on the CAISO board for almost nine years. That’s long enough on both fronts,” Olsen said in an email, explaining his decision to retire more than a year before the end of his term.
“Dave Olsen has been a pioneer in the development of the renewable energy industry,” CAISO CEO Elliot Mainzer said in a statement. His knowledge, vision and operating experience with highly reliable, low-carbon microgrids helped CAISO embrace the broader opportunities offered by new resources. His life’s work in the fields of clean energy and corporate sustainability initiatives is reflected in thousands of megawatts of clean energy projects and progressive policies adopted across the country.
“All of us at the ISO thank him for his service and wish him the very best,” Mainzer said.
The search for Olsen’s replacement has begun, the ISO said.
California Gov. Jerry Brown appointed Olsen to the board in 2012, and Gov. Gavin Newsom reappointed him in January 2019 to a term that expires at the end of 2021.
Olsen served as managing director of Western Grid Group from 2003 to 2013, leading an organization of former Western state energy officials who advocated for grid modernization, a transition to a clean energy economy and the creation of the EIM, according to his CAISO biography.
In the business world, Olsen led development of wind, solar, hydroelectric and geothermal power projects in more than 20 countries as president of Clipper Windpower (2001-2003), founder and president of Peak Power (1988-1995), vice president of Magma Power (1993-1995) and CEO of Northern Power Systems (1984-1988), the ISO said.
From 1996 to 1999 he served as president and CEO of Patagonia, leading the company’s carbon-reduction efforts and making it the first U.S. corporation to get its electricity from wind and solar power.
“I’m extremely grateful to Dave for his commitment to the ISO and California’s decarbonization goals,” said Angelina Galiteva, who took over as board chair last month. “He is a thoughtful, innovative and collaborative leader and leaves a legacy of championing the transition to 100% renewable energy while safeguarding the health and wellbeing of all Californians. His dedication, deep knowledge and tireless enthusiasm for building the grid of the future will be difficult to replicate.”
Olsen said in the statement he was privileged to have worked with such “excellent board colleagues and outstanding management and staff.”
“Together, we’ve steadily improved the organization’s capabilities and made it an internationally recognized leader in the transition to a low-carbon future,” he said. “I’m leaving CAISO in very good hands.”
SERC Reliability held a two-day Operations & Planning (O&P) Compliance Webinar Nov. 10-11, with discussions on operations under the coronavirus pandemic, recent enforcement trends and 2021’s enforcement priorities. Below are the highlights of what we heard.
‘Focusing on the Why’
SERC and its stakeholders have taken advantage of the shutdown of in-person meetings this year to improve their ability to address small reliability issues as well as reconsidering whether their practices are in line with their strategic goals, CEO Jason Blake told 175 people who turned out Tuesday for the beginning of the annual meeting.
SERC CEO Jason Blake | SERC
“It’s been impressive the way our industry has been able to navigate these unusual times,” Blake said. “We have the pandemic, a record-breaking hurricane season, social unrest and then the traditional things that challenge us, such as the evolving nature of the grid itself and increased cyber activity.”
Challenges bring opportunities by forcing people to rethink their routine ways of working, Blake said.
“Taking this approach allows you to unleash all types of potential and creativity,” he said. “The point is the criticality of focusing on the why. Why are we here? Why do I have this program in place back at my shop? Why is this standard a standard? What is its purpose?”
Blake said the shutdown has shown SERC the value of self-logging and remote audits, which, “if deployed properly,” can be a great tool for the organization even without a pandemic.
“The thing I’m very proud of is how our productivity has remained so high,” Blake said. “We’re taking this opportunity to improve our programs, understanding that the way we focus ourselves has a ripple effect across industry … and unresolved issues create a bottleneck. We have been working very hard to drive even further enhancements … make sure we have robust mitigation in place, as well as to properly resolve noncompliance based around risk.”
For the first time in years, SERC staff are regularly resolving issues faster than they come in the door.
Blake touted SERC’s 2020 Reliability Risk Report issued in September, which was drafted by the Reliability Risk Working Group.
The top 10 reliability risks for 2020 as identified by the SERC technical committees | SERC
The report identifies the top risks to focus on and prioritizes them, which “really demonstrates our commitment to be a data-driven, risk-based organization,” Blake said.
2021 Enforcement Priorities
The COVID-19 pandemic has affected compliance monitoring mainly by forcing it off-site, a precaution that will now extend through the first quarter of 2021, said Todd Curl, SERC senior manager of compliance monitoring.
Having replaced the former SPP and FRCC regional entities, SERC’s footprint now has about 264 registered entities. | SERC
Having replaced the former SPP and Florida Reliability Coordinating Council regional entities in 2018 and 2019, respectively, SERC now has about 264 registered entities in its footprint, Curl said.
“We have on the schedule a total of 62 CIP [critical infrastructure protection] and O&P audits for 2021, and also four spot checks scheduled in addition to those audits, so that gives you an idea of what we’re looking at for next year,” Curl said.
While no audits will be done on-site through the first quarter, some activities need to be done on-site, especially around some aspects of NERC reliability standards CIP-014 and FAC-008, the latter relating to facilities, design, connections and maintenance, he said.
Curl also gave a presentation on the ERO’s 2021 Compliance Monitoring and Enforcement Program (CMEP) Implementation Plan, which is focused on:
remote connectivity and supply chain (CIP-005-6, CIP-007-6, CIP-010-3 and CIP-013-1);
poor quality models impacting planning and operations (MOD-026-1, MOD-027-1 and MOD-033-1);
loss of major transmission equipment with extended lead times (TPL-001-4);
inadequate real-time analysis during tool and data outages (IRO-008-2 and TOP-001-4);
determination and prevention of misoperations (PRC-004-5 and PRC-027-2); and
gaps in program execution (CIP-010-2, FAC-003-4, FAC-008-3 and PRC-005-6).
The plan “looks at ERO-wide risk,” Curl said. “Each region beyond that needs to focus on region-specific risks.”
Todd Curl, SERC | SERC
As a result, Curl said, SERC auditors will continue their focus on CIP-002, although it is no longer among the ERO’s priorities.
“As the [plan] was being discussed by NERC and the regions and we were talking about what needs to stay in, what needs to come out, what needs to go in for the first time … it was SERC and one other region who still seem to see CIP-002 as high risk. All the other regions feel like it was a much lower risk than in the past,” Curl said. “We’re going to continue for at least another year in 2021 to focus on CIP-002.”
SERC’s 2020 Reliability Risk Report cited the standard as an example of gaps in program execution. The standard is designed to ensure entities maintain complex programs that handle large amounts of data, such as accurate inventories of equipment, following asset transfers and the addition of new equipment.
FAC-008 Enforcement Trends
SERC legal counsel Dulce Plaza gave a briefing on enforcement trends regarding standard FAC-008.
Dulce Plaza, SERC | SERC
FAC-008-3 became effective on Jan. 1, 2013, when FAC-008-1 and FAC-009-1 were retired. FAC-008-3 R6, which is very similar to FAC-009-1 R1, requires each transmission owner and generator owner to have facility ratings consistent with their ratings methodology.
Facility ratings were a NERC “area of focus” in the 2019 and 2020 ERO Enterprise CMEP Implementation Plans because of compliance engagements and self-report findings that identified potential reliability gaps. The 2020 SERC Reliability Risk Report by the RE’s Engineering Risk Committee identified FAC-008 as a major risk.
Plaza said FAC-009-1 and FAC-008-3 remain two of the most frequently violated O&P standards, representing 13% of SERC’s current O&P violation inventory.
Between Jan. 1, 2013, and Aug. 31, 2020, the region identified 33 violations of FAC-009-1 R1 and 24 violations of FAC-008-3 R6, most of them from self-reports. More than 50% were considered “minimal” risk and less than 10% considered “serious” risks.
Most discrepancies in facility ratings were the result of ineffective asset identification or change management controls, Plaza said.
She said some entities failed to correctly identify all their equipment in the field at the beginning of the enforceable period for FAC-008-3 and had not completed a “walk-down” of their facilities to verify if the equipment in the field was what was included on the one-line diagrams and facility ratings database. Thus, some noncompliance start dates for issues initially identified as FAC-008-3 violations extend back to 2007 and were processed under FAC-009-1.
Plaza also cited entities that consolidated equipment in the database rather than listing equipment individually, resulting in a single rating for different pieces of equipment. Entities also failed to remove retired devices from their database and diagrams in some instances.
“I would say based on the data, we are seeing improvements” in compliance, Plaza said. “An uptick in violations doesn’t mean that we’re doing worse. It just means that we’re finding things that we didn’t find before, especially during audits.”
Mike Kuhl, SERC | SERC
Mike Kuhl, SERC’s manager of O&P monitoring, said common errors are one-line diagrams that fail to include all switches and jumpers. “The transformer ratings — your large pieces of equipment — usually they’re good. But a lot of times, there’s a component that can be easily overlooked and catch you.”
Kuhl said that although the standard requires entities to consider all equipment rather than just the most limiting, “we’re not expecting absolute compliance from an auditing perspective.”
“If there’s one or two [violations, and] an auditor exercising professional discretion [determines] that there is reasonable assurance of compliance overall, we’re not going to call that out,” he said.
Curl said FAC-008 is one standard for which off-site monitoring is a handicap. “We’re auditing FAC-008 off-site as best we can to have reasonable assurance, but there may be some time after COVID is over [that] we may do a follow-up spot check,” he said.
Data to Include in Self Reports and Mitigation Plans
Jimmy Cline, SERC managing counsel, and Todd Beam, SERC manager of risk assessment and mitigation, gave a presentation on data that should be included in self-reports and mitigation plans.
Beam said self-reports should be as detailed as possible at the time of submission. “Let us know how the issue was identified: What was occurring that led to the discovery. Identify any internal controls … associated with the identification of the violation. Did it help identify [the violation or] did an internal control fail? Detail that out for us.”
He said self-reports also should identify what share of the total population in the program was affected. “Was it one out of 10,000, or 900 out of 1,000? That helps us understand the magnitude of the issue.”
Identification of the causes of noncompliance also should be detailed, Beam said.
“You can’t say, ‘The procedure was deficient,’ or perhaps, ‘An individual required training,’” he said. “We’re going to have to understand what was specifically deficient in the procedure. What needed to be added that wasn’t there? What was possibly misinterpreted or misapplied? Same with training: Why was the training not already provided? What was the deficiency? Identify the aspects of training that require improvement: the frequency of training; the training topics. Help us understand that.”
SERC expects self-reports within 90 days of discovery. “If there’s a delay, anticipate some questions, because we’re going to want to know why,” Beam continued. “If you as an entity are having difficulty in meeting that 90-day criteria, things to ask yourself: Are your internal business processes or review cycles too complex? … Do you have the proper staffing levels? … Are the necessary skill sets available?”
Winter Weather Plan
Tim Hattaway, energy service manager for PowerSouth Energy Cooperative, presented a winter weather plan for its service territory providing wholesale power to 20 distribution members in Alabama and northwest Florida.
PowerSouth owns and operates 1,680 MW of generation, mostly natural gas-fired but including the only compressed air energy storage facility in the country, a 110-MW facility in McIntosh, Ala., Hattaway said.
PowerSouth Energy Cooperative, which provides wholesale power to 20 distribution members in Alabama and northwest Florida, rarely experiences singe-digit winter temperatures. | PowerSouth
The cooperative, a registered balancing authority, is much better versed in hurricane preparedness than in cold-weather operations, “because we really got hammered with hurricanes, this year especially,” he said. “We don’t have a lot of cold, freezing weather, but we do deal with weather in the Gulf of Mexico.”
The cooperative is a winter-peaking system, with approximately 85% residential load, and generally sees fewer than 30 hours per year of temperatures below 25 degrees Fahrenheit. But after that figure climbed over 110 hours in the polar vortex of 2014, it hired an outside engineering firm to help.
“They performed a detailed analysis on all of our generators, even our small hydro facilities that are 1-MW units … and they highlighted our heat tracing, our insulation, things like that,” Hattaway said.
Tim Hattaway, PowerSouth | SERC
One finding was that generation unit operators tended to face cold weather by adding more heat tracing — electric cables to heat a pipe — rather than by trying to understand how to winterize units properly. For example, the study taught them that wet insulation causes pipes to freeze approximately two times faster than with dry insulation, and that even a small amount of moisture in instrumentation lines can cause false readings and unit trips.
It took the company over a year to go over the 800-page report and implement all its recommendations, he said.
One questioner asked whether the co-op ever experienced units that would not start, and if so, how long it took to fix the issue.
“One reason we like the day-ahead start-up is because if we have an issue with a unit starting, and … if we stuck to our economic dispatch plan, we might call on that unit at 3 in the morning, but if it doesn’t start at 3, we’ve only got about an hour to resolve the problem,” Hattaway said.
Typically, the company has been able to get the units online in time for when needed the following morning, and unit operators much prefer a good lead time on getting started, he said.
“We also have a 20-day or 25-day start-up procedure where we start units just to make sure they’re in running order,” Hattaway said.
Registered Entity Forum Election
Ballots are due Nov. 13 in the vote to fill four open positions on SERC’s Registered Entity Forum Steering Committee for two-year terms. The committee requires at least one representative with a CIP background.
The committee, which meets quarterly, provides a conduit to SERC staff and an opportunity for discussion among registered entities regarding reliability and compliance issues, including sharing lessons learned and best practices. Registered entities that want to ask SERC questions without subjecting themselves to scrutiny can approach a committee member, who can ask the question while maintaining the RE’s anonymity.
Ballots were sent to primary compliance contacts Nov. 5. Those elected will be notified the week of Nov. 23 and announced in the SERC Transmission newsletter in December.
RC West praised its members for collaborating to manage the Western “heat storm” in mid-August that prompted CAISO to initiate California’s first rolling blackouts since the energy crisis of 2000/01 and pushed utilities elsewhere to the brink of calling for outages.
“The first point I want to make is the only place that firm load-shed did occur was in California,” Tim Beach, director of reliability coordination for RC West and CAISO, told the RC West Oversight Committee on Tuesday.
While other balancing authority areas “within the RC West area didn’t have firm load shedding … they were a contingency away, perhaps. Many times, it was imminent, and that’s why they were in” a Level 3 energy emergency alert (EEA 3), Beach said.
To give a sense of the scope of the event, Beach noted that RC West BAs have called 52 EEAs since the reliability coordinator commenced operations in 2019. Out of those 52 EEAs, 35 occurred during the Aug. 14-18 heat wave.
“So, it was a very large-impact heat storm that was stalled across the region,” he said.
This chart shows how many energy emergency alerts have been called in RC West since it began operations in July 2019 and how many of those occurred during the mid-August heat wave event. | CAISO
The heat wave produced the all-time record peak demand in RC West’s short history: 127.6 GW on Aug. 17. WECC, which is performing an event analysis for NERC and stakeholders, estimates that demand across the entire Western Interconnection peaked at just over 162 GW on Aug. 18. (See WECC Examining August Heat Wave Through West-wide Lens.)
Beach noted that RC West is still responding to data requests for WECC’s analysis. “We expect to get some lessons learned out of that [report] as well.”
He shared some of the lessons RC West already gleaned based on firsthand experience with the event.
The first lesson was the benefit of “proactive communication” across the interconnection. Beach said RC staff initiated “ad hoc” daily conference calls with BAs and transmission operators (TOPs) throughout the event. Calls started as early as 3 a.m., with RC “canvassing” BAs and TOPs in the Southwest and Pacific Northwest about any potential capacity issues they might expect that day.
“We used those calls to sort of cue [RC staff] to follow up with other individual companies as the day progressed,” Beach said.
He offered a “hats off” to BA and TOP operators for “doing an excellent job” of joining conference calls during the day and communicating the status of the system.
“It was in some respects a good event that everybody sort of linked their arms together and we marched through the heat storm and were able to manage it pretty well,” Beach said.
RC West’s second key lesson was recognizing the need for bringing in relief, as it added shift staff to assist with peak hours.
“Normally we have three RCs [operating staff] on shift — a lead and two regular RCs,” Beach said. “We brought a fourth RC that usually started around noonish and then actually worked well through peak up until 10 at night to help with the RCs on staff.”
He said the first objective of EEAs is to help BAs navigate capacity emergencies. The second — “which is probably equal to the first” — is to protect the wider interconnection from a BA “that’s in trouble.”
Beach wants to ensure that staff provide a “proper sounding board” for BAs as they escalate to emergency procedures. He said at times he thought RC West’s approval of EEAs during the event was “more like a rubber-stamp.”
“I would’ve liked to have a little more rigor around that, so we’re going to look at that going forward,” he said.
Beach said RC West this year began performing capacity drills with individual BAs to walk through EEA steps, explore scenarios of reserves deficiency or sufficiency, and examine ways to work through capacity emergencies.
“Then we can exercise some muscle memory going into next year,” he said.
Controlled Control Room
CAISO has reactivated a third control room in order to protect staff against potential COVID-19 infections as cold and flu season looms.
“If we do have somebody that has a sick child at home, for example, we don’t have to quarantine them at home. We can put them in a controlled environment, and they can still operate from that control room,” Beach said, adding that the room is “physically cordoned off” from the rest of the ISO population.
Beach assured the Oversight Committee that CAISO staff remain healthy and have not registered a single COVID case, despite some direct contacts with infected people. “But we have a process for making sure we quarantine those people in those instances,” he said.
