CAISO will temporarily increase its daily procurement of operating reserves in response to findings that the erroneous tripping of solar generation caused the loss of 1,200 MW of output as the Blue Cut fire burned in Southern California last August.
SolarStar Utility Scale Solar Project | BHE Renewables
Beginning June 14, the ISO will procure more operating reserves in response to last week’s NERC report showing that solar inverters — which convert photovoltaic DC output to utility frequency AC — are susceptible to erroneous tripping during transients caused by faults on the power system. The ISO did not say how long it will keep the measure in place.
A NERC/Western Electricity Coordinating Council task force said the loss of inverter power injection was caused by a perceived low-frequency condition and low-voltage blocking of inverters. The inverter manufacturer recommended changes to inverter settings to prevent the erroneous tripping, and CAISO and Southern California Edison are working to develop a corrective plan.
The inverters tripped on Aug. 16 as the Blue Cut fire raged in the Cajon Pass and quickly moved toward an electric transmission corridor containing lines owned by SCE and the Los Angeles Department of Water and Power. There were 13 faults on 500-kV lines and two 287-kV faults that took down 1,200 MW of solar. The facilities did not de-energize, but they ceased output because of the system faults, with the most significant losses occurring around 11:45 am. Four of the faults (see chart) caused losses of PV generation.
Utility-scale solar PV output in SCE footprint on Aug. 16, 2016. Four of 15 faults that day caused losses of PV generation. | NERC
CAISO said it will increase its reserves “to minimize the potential impact due to loss of inverter power injection during a single transmission contingency event.” More reserves will be procured during solar operating hours, and the total target reserve amount will be up to 25% of forecast solar production.
The task force recommended a minimum delay for frequency tripping to ensure an accurate system frequency measurement and that inverters be equipped to quickly return to operation if they cease supplying power during voltage excursions.
It also said generation owners and operators should receive an alert to ensure they are aware of recommended changes to inverter settings.
“With the proliferation of solar development in all interconnections across North America, the results of this disturbance analysis need to be widely communicated to the industry highlighting the present potential for widespread solar resource loss during transmission faults on the [bulk power system],” NERC said.
The growing use of inverter-based technologies that operate in microseconds is rapidly changing the characteristics of the power grid and presents some new challenges, NERC Vice President of Reliability Risk Management James Merlo said in a statement. The loss of generation was a “previously unknown risk to reliability,” and NERC is taking steps to mitigate the risk, he said.
Two cybersecurity firms on Monday disclosed what may be the most dangerous cyber threat yet to U.S. power systems: malware that can take control of circuit breakers without any manual involvement.
Maryland-based Dragos and ESET, a Slovakian anti-virus software provider, said the malware — which the former is calling CrashOverride and the latter Industroyer — was likely the cause of a disruption last December that cut about one-fifth of Kiev’s power consumption for about an hour.
| Dragos, ESET
Unlike the December 2015 hack of the Ukraine system — caused by the BlackEnergy program that took advantage of vulnerabilities in Microsoft Office and required manual intervention to control circuit breakers — the new threat takes advantage of the simplicity of supervisory control and data acquisition (SCADA).
Dragos said CrashOverride is the first malware framework designed specifically to attack electric grids and the fourth ever piece of malware tailored for industrial control systems. It follows BlackEnergy 2, Havex and Stuxnet, the last of which was believed deployed by the U.S. to hack centrifuges used in Iran’s nuclear weapons program.
Dragos founder Robert M. Lee told Reuters that the malware could be used to attack power systems across Europe as is and in the U.S. “with small modifications.” It could cause outages of up to a few days in portions of a nation’s grid, he said.
The program can be detected if utilities monitor their networks for abnormal traffic, such as indications that it is searching for the location of substations or sending messages to breakers, according to Dragos.
The program’s “dangerousness lies in the fact that it uses protocols in the way they were designed to be used,” wrote Anton Cherepanov, senior malware researcher for ESET. “The problem is that these protocols were designed decades ago, and back then industrial systems were meant to be isolated from the outside world. Thus, their communication protocols were not designed with security in mind. That means that the attackers didn’t need to be looking for protocol vulnerabilities; all they needed was to teach the malware ‘to speak’ those protocols.”
Cherepanov said the program can remain undetected and eliminate traces of itself after its work is complete.
“For example, the communication with the [command and control] servers hidden in Tor can be limited to non-working hours. Also, it employs an additional backdoor — masquerading as the Notepad application — designed to regain access to the targeted network in case the main backdoor is detected and/or disabled,” Cherepanov wrote.
Part of the “dark web,” the Tor network allows users to access the Internet through “virtual tunnels” rather than making a direct connection, allowing them protect the privacy of their communications. It has been used to circumvent government censorship and by journalists to communicate with whistleblowers and dissidents. The U.S. Department of Homeland Security said TOR IP addresses were used by the Russian hackers who stole data from the Democratic National Committee before last year’s presidential election.
“What makes this thing a holy-crap moment is the understanding of grid operations encoded within it,” Lee told the Daily Beast. The program can run continuously, requiring manual overrides to interrupt it. “It’s like a popup on a website, where you close it and it just keeps opening again. That’s what they’re doing to circuit breakers.”
In a statement Monday from Marcus Sachs, chief security officer for the Electricity Information Sharing and Analysis Center (E-ISAC), NERC said it is aware of the threat but that “there are no reported instances of the malware in North America.”
NERC said it will update its Ukraine Defense Use Case report, issued in March, to reflect the new information.
“There is no question that cyber threats like the one in Ukraine are real and that constant vigilance is needed to protect the reliability of the North American grid,” Sachs said.
But a spokesman for Ukraine’s state cyber police told Reuters it had not been able to confirm Dragos’ claim because the security firms hadn’t provided authorities with samples of the code they analyzed.
Lee toldThe Washington Post the outages caused by CrashOverride would probably not last more than a few days in the U.S. because the electric industry is prepared to respond to disruptions from violent weather. “They’re used to having to restore power with manual operations,” he said. While it is “a significant leap forward in tradecraft, it’s also not a doomsday scenario.”
Two cybersecurity firms on Monday disclosed what may be the most dangerous cyber threat yet to U.S. power systems: malware that can take over control of circuit breakers without any manual involvement.
Maryland-based Dragos and ESET, a Slovakian anti-virus software provider, said the malware — which the former is calling CrashOverride and the latter named Industroyer — was likely the cause of a disruption last December that cut about one-fifth of Kiev’s power consumption for about an hour.
| Dragos, ESET
Unlike the December 2015 hack of the Ukraine system — caused by the BlackEnergy program that took advantage of vulnerabilities in Microsoft Office and required manual intervention to control circuit breakers — the new threat takes advantage of the simplicity of supervisory control and data acquisition (SCADA).
Dragos said CrashOverride is the first malware framework designed specifically to attack electric grids and the fourth ever piece of malware tailored for industrial control systems. It follows BlackEnergy 2, Havex and Stuxnet, the last of which was believed deployed by the U.S. to hack centrifuges used in Iran’s nuclear weapons program.
Dragos founder Robert M. Lee told Reuters that the malware could be used to attack power systems across Europe as is — and in the U.S. “with small modifications.” It could cause outages of up to a few days in portions of a nation’s grid, he said.
The program can be detected if utilities monitor their networks for abnormal traffic, such as indications that it is searching for the location of substations or sending messages to breakers, according to Dragos.
The program’s “dangerousness lies in the fact that it uses protocols in the way they were designed to be used,” wrote Anton Cherepanov, senior malware researcher for ESET. “The problem is that these protocols were designed decades ago, and back then industrial systems were meant to be isolated from the outside world. Thus, their communication protocols were not designed with security in mind. That means that the attackers didn’t need to be looking for protocol vulnerabilities; all they needed was to teach the malware ‘to speak’ those protocols.”
Cherepanov said the program can remain undetected and eliminate traces of itself after its work is complete.
“For example, the communication with the [command and control] servers hidden in Tor can be limited to non-working hours. Also, it employs an additional backdoor — masquerading as the Notepad application — designed to regain access to the targeted network in case the main backdoor is detected and/or disabled,” Cherepanov wrote.
Part of the “dark web,” the Tor network allows users to access the Internet through “virtual tunnels” rather than making a direct connection, allowing them protect the privacy of their communications. It has been used to circumvent government censorship and by journalists to communicate with whistleblowers and dissidents. The U.S. Department of Homeland Security said TOR IP addresses were used by the Russian hackers who stole data from the Democratic National Committee before last year’s presidential election.
“What makes this thing a holy-crap moment is the understanding of grid operations encoded within it,” Lee told the Daily Beast. The program can run continuously, requiring manual overrides to interrupt it. “It’s like a popup on a website, where you close it and it just keeps opening again. That’s what they’re doing to circuit breakers.”
In a statement Monday from Marcus Sachs, chief security officer for the Electricity Information Sharing and Analysis Center (E-ISAC), NERC said it is aware of the threat but that “there are no reported instances of the malware in North America.”
NERC said it will update its Ukraine Defense Use Case report, issued in March, to reflect the new information.
“There is no question that cyber threats like the one in Ukraine are real and that constant vigilance is needed to protect the reliability of the North American grid,” Sachs said.
But a spokesman for Ukraine’s state cyber police told Reuters it had not been able to confirm Dragos’ claim because the security firms hadn’t provided authorities with samples of the code they analyzed.
Lee toldThe Washington Post the outages caused by CrashOverride would probably not last more than a few days in the U.S. because the electric industry is prepared to respond to disruptions from violent weather. “They’re used to having to restore power with manual operations,” he said. While it is “a significant leap forward in tradecraft, it’s also not a doomsday scenario.”
SPP members are advancing at least two alternative solutions to address the RTO’s complicated crediting system for transmission upgrades.
The Z2 Task Force agreed last week in Kansas City to present two proposals to simplify the process spelled out in Attachment Z2 of SPP’s Tariff for assigning financial credits and obligations for sponsored upgrades to the Markets and Operations Policy Committee next month for members’ feedback. The proposed alternatives are among the same three the group has spent several months hashing over. (See SPP Members Again Struggle with Solutions to Z2 Credits.)
Xcel Energy upgrade project Burns & McDonnell
“We’re doing an awful lot of talking, but we’re not getting anywhere,” Oklahoma Gas & Electric’s Greg McAuley said during the task force’s meeting.
The problem, McAuley told RTO Insider, is that there’s still not enough detail in the proposals to make informed decisions. But obtaining the necessary data would be “a significant undertaking in itself,” he said.
“Without some kind of analytical comparison, it’s difficult for anyone to make decisions,” he said. “There can be unintended consequences with any of these options that can be significant.”
That became apparent as members peppered Westar Energy’s Grant Wilkerson with questions as he ran through several scenarios related to his solution, which will be among those presented to the MOPC.
Under the Westar proposal, transmission rates would be calculated based on an average cost per megawatt. Wilkerson said his approach would not be affected by the order in which upgrade sponsors are compensated; rates would be trued up annually and credits would be based on directly assigned costs and usage factors (as determined by impacts identified in aggregate studies).
The task force also agreed to share staff’s proposal at the MOPC meeting. It agreed with staff’s recommendation to eliminate credits for new upgrades that don’t add transfer capacity and to eliminate credits for all short-term service, approving a pair of motions in roll-call votes. Staff agreed to provide additional data for the task force’s next meeting, when members will resume their analysis of the proposals.
A third proposal, incremental long-term congestion rights (ILTCRs), while no longer being considered a substitute for Z2 credits, also remains an option.
“I’m comfortable if people want to fund this stuff [with ILTCRs],” said Kansas City Power & Light’s Denise Buffington, the task force chair. “There isn’t any transparency to it, and I struggle to identify [the costs] to regulators. Maybe we do want to socialize the costs, but I don’t know if ILTCRs are any more transparent.”
The task force will meet again June 27 in Dallas. The MOPC meets July 11-12 in Denver.
CARMEL, Ind. — MISO last week committed to adopting its Independent Market Monitor’s recommendation to implement market mitigation for a new category of narrowly constrained areas (NCAs) identified by momentary congestion and associated market power.
Within a month, the RTO will file Tariff revisions on a proposal to create dynamic NCAs after staff spoke extensively with the Monitor on the issue, according to MISO Director of Market Evaluation and Design Dhiman Chatterjee.
“Conceptually, we are in alignment that the broadly constrained areas leave open some needs,” Chatterjee said at a June 8 Market Subcommittee meeting.
But while MISO is adopting the Monitor’s proposal without changes, there are still some minor details to be worked out, and the RTO is accepting stakeholder feedback, Chatterjee said. The RTO and Monitor will both need to make software changes before the definition is introduced into the market in late fall after FERC approval, he said, adding that stakeholders have generally supported the idea.
“We don’t believe at this point there are any broad, outstanding questions that are in the way,” Chatterjee said.
Monitor David Patton recommended in April that the RTO expand mitigation measures on NCAs by creating a new definition aimed at short-lived congestion and applying mitigation if the constraint has bound in 15% or more hours over at least five consecutive days. The new category would set a conduct threshold at $25/MWh. The definition would differ from FERC-defined NCAs, which must bind for more than 500 hours annually. (See MISO IMM Recommends Tighter Rules for Constrained Areas.)
Patton said FERC’s definition of NCAs is inadequate because it only measures binding constraints annually and does not tackle intense but temporary congestion. Only about 10 to 15% of MISO’s footprint is subject to traditional NCA mitigation, in Patton’s estimation.
Patton said dynamic NCAs would only be declared in situational congestion where normal market participants have more market power than usual. Mitigation measures would be lifted once the binding congestion dissipates.
“It won’t be defined on a more permanent basis like the NCAs are,” Patton said.
CARMEL, Ind. — MISO is considering establishing a possible commercial trading hub in Mississippi and will conduct stress tests and sensitivity analyses into the fall to help support its decision.
The RTO will use 12 to 15 months of hourly price and varying load data to create hub parameters and analyze the 618 existing pricing nodes in Mississippi and nearby areas in order to test the viability of the new hub, according to Michael Robinson, principal adviser of market design.
MISO will draft a white paper for stakeholders if the study concludes the Mississippi trading hub is worthwhile, Robinson said. The RTO hopes to finalize the hub in early November and have it go live in early December.
“It looks like there’s enough here to consider,” MISO South Vice President Todd Hillman said of the upcoming study at a June 8 Market Subcommittee meeting.
The RTO has deliberated over the issue since Mississippi became its 10th local resource zone in 2015, Hillman explained. “As the South region has gotten more knowledge, what we found is that when companies look for new locations, part of the reason they might do that is the gas infrastructure, but they also do it to join RTO pricing,” he said.
Hillman also said the state is especially looking for commercial growth. “Mississippi, as you know, is the poorest state in the country, so they’re looking to use their infrastructure.”
MISO has experience in creating and managing new trading hubs. Robinson said the RTO established the FE hub in 2005, redefined the Cinergy hub in 2010 and handled the addition of the Texas, Arkansas and Louisiana hubs during the MISO South integration in 2013.
“We’ve been through this process before, and it’s been a good process,” NRG Energy’s Tia Elliott said. She cautioned that, not being familiar with MISO’s process for creating a new hub, MISO South stakeholders could appreciate periodic updates. Robinson agreed and said he would work with Hillman to keep stakeholders informed about the situation.
CARMEL, Ind. — MISO has issued its annual survey asking stakeholders to rank possible market modifications the RTO should undertake as part of its Market Roadmap process.
The survey contains 34 proposals. Stakeholder results will be measured alongside staff weightings to rank what market projects the RTO will tackle first, Senior Manager of Market Strategy Mia Adams said.
This year, MISO is limiting stakeholders’ scoring to a maximum of four “high” and six “medium” priority designations, with an unlimited number of “low” and “do not pursue” designations.
“We limit this because if everything is a high priority, nothing is a high priority,” Adams said at a special June 8 Market Roadmap workshop. She also said the RTO has finite resources and time to work on simultaneous market changes.
Stakeholders have until July 13 to return their surveys.
This is also the first year that MISO will publicly post a matrix of projects’ scores, representing an attempt to increase transparency around which market changes are pursued. Stakeholders last year voiced disappointment at what they viewed as an opaque approach to project selection. Market projects were ultimately reordered late in the process to account for stakeholder preferences. (See MISO Projects Reordered Following Stakeholder Frustration.)
Executive Director of Market Design Jeff Bladen said projects won’t begin to be ordered until after the Independent Market Monitor releases its annual State of the Market Report. “The actual ranking and prioritization process is months in front of us,” Bladen said.
MISO plans to review the results in August and present a final prioritization in September.
At stakeholders’ request, Bladen said this will be the first year in which the Market Roadmap process will show the Monitor’s recommendations alongside those of the RTO and its participants.
Last month, the Steering Committee created a pair of new project candidates based on Monitor recommendations, improving shortage pricing by revising the operating reserve demand curve to reflect a higher value of lost load and changing the day-ahead margin assurance payment and real-time offer revenue sufficiency guarantee payment rules and performance incentives to reduce gaming. (See MISO Steering Committee OKs IMM Proposals for Market Roadmap.)
Minnesota Public Utilities Commission staffer Hwikwon Ham said it would be helpful for State of the Market Reports to be released earlier in the year to enable stakeholders to read the Monitor’s recommendations before ranking projects.
Monitor David Patton said his office worked to release some project recommendation descriptions earlier this year to meet MISO’s May deadline for submitting Market Roadmap candidates. Patton said in the future his staff will target an earlier publication of the report.
“We’re changing some of our processes on the State of the Market so it better coincides with the Market Roadmap,” Patton said. Adams also said MISO is open to shifting survey deadlines to give stakeholders time to review the reports before completing surveys.
SACRAMENTO, Calif. — California lawmakers on Wednesday expressed concerns that expanding CAISO into a regional grid operator would result in higher electric bills, job losses and the export of energy development to other states.
Members of the Assembly Committee on Utilities and Energy did not appear to reach conclusions during a June 7 hearing, but they did ask detailed questions of representatives of CAISO, public interest groups and power companies.
Committee Chairman Assemblymember Chris Holden (D-41st District)
Chairman Chris Holden, a Democrat, called the hearing to gather information about whether the expansion is necessary and provides the least-cost alternative to meeting the state’s aggressive renewable mandates.
The 2015 Clean Energy and Pollution Reduction Act, which established the state’s 50% by 2030 renewable portfolio standard, also directed the state’s energy agencies to explore transforming CAISO into a regional entity to help meet the RPS target. More recently, the State Senate passed a bill setting a 100% renewable goal by 2045. (See California Senate Passes Bill Mandating 100% RPS.)
There is consensus between the legislature, CAISO and other stakeholders that expansion would have benefits, including enabling California to export its periodic oversupply of renewable generation and reducing the costs of curtailing output. CAISO cites its finding that regionalization would save electricity customers up to $1.5 billion annually by 2030. (See Study Touts Benefit of CAISO Expansion.)
But public interest groups have urged the state to go slow on the initiative, and skeptics challenged some of the study’s findings. (See CAISO Expansion in Question as EIM Grows.) Lawmakers wanted to know what the trade-off is for California consumers.
At the hearing, Republican Assemblyman Brian Dahle said he did not think the legislature had adequately studied the consequences of the “arbitrary” goal in the state’s RPS. He mentioned the costs associated with renewable curtailment and high electricity bills.
“I want to figure that out, and I don’t want to continue to have more solar if I don’t need it in the middle of the day” in some parts of the state, Dahle said. He also expressed concern about the loss of California jobs from regionalization.
This year, CAISO has curtailed about 2.6% of potential solar generation and 1.3% of renewables. But that amount could grow 10-fold and become a very costly problem, CAISO Vice President of Market and Infrastructure Development Keith Casey said. The state is well on its way to meeting a 33% RPS by 2020.
“The solution is to take a holistic approach to meeting the RPS mandate,” Casey told Dahle. That means factoring in the cost of curtailment and the differing costs of renewable resources that are used to meet the RPS.
There are abundant wind and geothermal resources in neighboring states that can be developed cheaply and support out-of-state jobs, but importing low-cost power also has an indirect stimulus on jobs in California, Casey said.
“The bottom line is there is no silver bullet here,” Casey said, asserting that California is leading the world in integrating renewables. Officials in Asia, Africa and South America visit the ISO almost weekly to study the state’s effort.
California State Capitol Building in Sacramento
“Some of this isn’t new at all,” said Jan Smutny-Jones, CEO of the Independent Energy Producers Association, which represents owners and operators of renewable, natural gas, energy storage and demand response resources. California has been involved in a Western energy market in some form for 60 years, but it could be made to work better, he said. Regionalization could reduce costs and create market opportunities.
“Our interest, quite candidly is that we want to grow that market, and we don’t think we can grow that market here in California, assuming you can get stuff sited,” Smutny-Jones said.
CAISO said its goals are to preserve state authority, transparently track greenhouse gas emissions and retain the ability of state representatives to direct policy. But Gov. Jerry Brown has heeded the concerns expressed by some, directing state agencies to take more time to develop a proposal. (See Governor Delays CAISO Regionalization Effort.)
After a pause last summer, the momentum toward regionalization of CAISO may be resuming, but the June 7 hearing indicates there will be careful scrutiny as to whether the negatives outweigh the positives for the state’s consumers and businesses.
CARMEL, Ind. — Behind-the-meter generation would need to demonstrate its deliverability before offering into MISO’s capacity auction, under a new proposal being floated by the RTO.
The proposal would allow “excess” behind-the-meter (BTM) generation without existing transmission service to submit to an optional engineering study identifying a deliverable megawatt volume of capacity eligible to be bid into a single planning resource auction. Any BTM generation that exceeds a utility’s planning reserve margin requirement is considered excess BTM, a term the RTO is considering adding to its Tariff.
But there’s a catch: the excess BTM generation volunteering for the study “must commit” to entering the same number of megawatts into the interconnection queue study process to offer capacity in any subsequent auction.
Going forward, excess BTM generation from new projects would have to enter the interconnection queue and commit to a deliverability study to obtain external network resource interconnection service like other MISO generators, MISO Manager of Resource Adequacy John Harmon said during a June 7 MISO Resource Adequacy Subcommittee (RASC) meeting.
Harmon said the optional study and subsequent queue commitment is intended to treat BTM generation more like traditional capacity resources that must demonstrate access to the transmission system before supplying capacity.
“We don’t want this optional study going into perpetuity. We want there to be a transition at some point. What we want is a commitment to go through those other study processes,” Harmon said. He asked for stakeholders to comment on the proposal by June 21.
MISO said it will continue to allow BTM generation to satisfy load-serving entities’ planning reserve margin requirements without a deliverability demonstration. Under MISO rules, demand response resources have first crack at reducing planning reserve margins, followed by BTM generation.
BTM generators identifying as load-modifying resources were able to demonstrate deliverability for excess capacity in the 2017/18 PRA by meeting with staff for a case-by-case review, a process MISO said it will not repeat in next year’s capacity auction. (See MISO to Take Case-by-Case Approach on BTM Generators.)
Stakeholders have in recent months urged MISO to consider alternatives for BTM generation to demonstrate deliverability other than acquiring full interconnection service or firm transmission service.
More BTM Generation Talk Upcoming
Harmon said the issue of BTM generation entering the capacity auction will be subject to further assignment decisions by the Steering Committee after a common issues meeting tentatively scheduled for July 24. The meeting was called after storage resource owners Consumers Energy, DTE Energy, Ameren, Xcel Energy and Indianapolis Power and Light submitted a joint request for MISO to create a model for the participation of storage in the market and to track its growth using the RTO’s Market Roadmap list of market revisions. (See MISO’s Next Step on Storage: ‘Common Issues’; Task Team?)
RASC Chair Chris Plante said the Steering Committee might task the RASC with defining the criteria for “lowercase” behind-the-meter generation, which represents resources not registered with or dispatchable by the RTO and not subject to market mitigation. “Uppercase” BTM refers to resources that can be dispatched. (See MISO Behind-the-Meter Generation Definitions Create Confusion.)
MISO hopes to adopt business practice manual language that clarifies the market treatment of BTM generation by this fall.
MISO to Study Extended Outage Effect on Loss of Load
Meanwhile, the RTO will continue to investigate whether extended outages should be factored into future loss-of-load-expectation studies. After an analysis of extended outages, the RTO has concluded that planned outages during peak times are “not trivial” to MISO’s planning reserve margin, said Ryan Westphal, of MISO’s Resource Adequacy Coordination department.
The issue will be further discussed in MISO’s Loss-of-Load-Expectation Working Group. MISO is also weighing whether to prohibit units on extended outages from offering into the PRA. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)
Stakeholders on Wednesday pressed CAISO for details on a proposal to broaden and make permanent certain operational measures developed in response to Aliso Canyon gas restrictions.
CAISO is proposing to make the gas-electric coordination measures applicable to the ISO’s entire footprint — including the Western Energy Imbalance Market — and not just the Southern California area affected by the closure of the Aliso Canyon gas storage facility. (See CAISO Mulls Making Aliso Canyon Measures Permanent.)
Key among those measures is a provision allowing the ISO to limit output from gas-fired generators within a specific “gas operating zone.” The limit would allow the ISO to enforce a maximum gas burn during shortages.
Carrie Bentley, a consultant representing the Western Power Trading Forum, asked about the rationale for broadening application of that provision to areas outside those normally dependent on gas from Aliso Canyon.
“To me that seems like it would still be a Southern California issue, but given [that] you’re proposing this for the entire footprint, I wondered what operational risks you saw for the ISO, including the EIM,” Bentley said.
Mark Rothleder, CAISO vice president of market quality and renewable integration, acknowledged that the risks stemming from Aliso Canyon were still specific to Southern California.
“I think the extension — and the things that are being proposed as permanent — is really in light of potentially other types of gas-related constraints arising in other parts of the footprint that we want to be prepared for in case they do arise, not just strictly [constraints] associated with Aliso,” Rothleder said.
Bentley pressed Rothleder for more information about the risks elsewhere in the ISO system.
“I don’t want to give too much detail, but there’s broader rule changes that affect other storage facilities and how much can be withdrawn and injected to other facilities over time, and those will affect not just Aliso or Southern Cal Gas storage facilities,” Rothleder said.
The California Air Resources Board earlier this year passed tougher standards for monitoring and testing for methane leaks from all the state’s underground storage fields, as well as requiring equipment changes that could slow the flow to and from the facilities.
Site of Aliso Canyon leak in December 2016 | SoCalGas
Rothleder also pointed out the that ISO has “become aware of” gas constraints outside California.
“They are probably more localized, but they could affect multiple generators in localized areas of the EIM footprint,” he said. “And we’re at least aware of some of those that could arise [for which] we would need to enforce gas-burn constraints eventually and appropriately allocate gas to multiple physical generators.”
Rothleder said the ISO would be committed to providing “transparency and advance notice” to market participants when it must enforce a constraint and that the measure would be “prudently applied.” The Aliso Canyon gas-burn constraint has been invoked only once, over four days in January when SoCalGas had to withdraw gas from the facility to meet heating needs.
“It was more for the gas-side need than the electrical-side need,” Rothleder said of the event.
Cathleen Colbert, senior market design and regulatory policy developer at the ISO, who gave a presentation on the proposal, said EIM balancing authority areas would gain use of the gas constraint as part of their market role. “This is similar to existing authority for the EIM entities to use [to] dispatch at their discretion,” Colbert said.
Lindsey Schlekeway of NV Energy expressed confusion over how and when EIM members would use the gas constraint.
“I wasn’t sure … if we were supposed to contact the ISO and how this would really work,” Schlekeway said.
“These are some details that we will have to develop as part of the process, but I think it’s important to keep in mind that, whether or not this constraint is enforced, the decision will be made by the balancing authority area and the procedures would be established by the entity itself,” replied Anna McKenna, ISO assistant general counsel.
Ryan Kurlinski of the ISO’s Department of Market Monitoring said that extending to EIM entities the ability to enforce gas constraints would constitute “a major market design change.”
“What we’re looking for is that hopefully the ISO can provide more clarity on what are the conditions under which an EIM entity can define a gas nomogram,” Kurlinski said, referring to the diagram representing the interrelationship of fuel consumption among gas-fired generators on the system under various operating conditions.
Bentley questioned why CAISO was referring to the initiative as “Aliso Canyon Gas-Electric Coordination Phase 3” when the extended measures will in fact have broad application across the ISO. “I think the name is very misleading and I think potentially you won’t get full stakeholder review if you aren’t really clear what you’re doing here,” Bentley said.
“We actually weighed both sides of that,” replied Brad Cooper, the ISO’s manager of market design and regulatory policy. Cooper said the ISO had considered a different name but was concerned that stakeholders might lose sight of the fact that it was proposing to extend and make permanent the Aliso Canyon measures.
“So I take your point, but I think that either way, we had the potential to be misleading, and we thought it would just be clearer calling it Aliso Canyon Phase 3,” Cooper said.
“But I’m not misunderstanding this, right?” Bentley asked. “I mean, the operational risks have really very little to do with Aliso Canyon and you’re saying there’s all these other circumstances that are leading to this need.”
Colbert said the closure of Aliso Canyon had provided insights that can be applied throughout the ISO.
“We’re learning as we go, we’re learning by doing,” Colbert said. “And so other concerns have come up through our continued exercising of this gas-electric coordination. So while we’ve learned about additional constraints, and we’d like to broaden and expand the scope of this project, the genesis of it is from Aliso Canyon.”
