Hurricane Laura’s impending landfall along the Gulf Coast has MISO, Entergy, SPP and ERCOT bracing for grid impacts.
The intensifying Category 4 storm (as of press time) will unleash torrential rain, coastal flooding and fierce winds on southwest Louisiana and southeastern Texas tonight and tomorrow.
“MISO expects transmission and generation facilities along the path of the hurricane to be unavailable due to damage caused by high winds and flooding. MISO is working with its members to estimate the extent of the impacts, including loss of load, generation and transmission and communication systems,” spokesperson Allison Bermudez told RTO Insider ahead of the storm’s landfall tonight.
MISO on Tuesday declared a severe weather alert and conservative operations in effect for Wednesday and Thursday for portions of its Texas and Louisiana footprint. It asked members to suspend all transmission and generation maintenance.
The RTO also warned of fuel supply limitations, saying Laura could inflict major damage on gas refineries near the Gulf. It asked generators to report any fuel supply issues as soon as possible.
SPP likewise declared conservative operations in the Southwestern Electric Power Co. portion of its balancing authority Wednesday through Friday. With conservative operations, the grid operator can expand unit commitment times and “enforce other reliability safeguards as needed.”
| Entergy
Bermudez said that before MISO made the conservative operations declaration, it was working with members to “maximize availability of generation and transmission assets necessary to ensure grid reliability.” She said the RTO is closely monitoring load in western Louisiana and eastern Texas.
“MISO control room teams are well trained to handle extreme weather events, such as Hurricane Laura, and remain committed to reliable grid operations,” she said. “MISO is taking extensive measures to ensure grid and market operating systems are secure and protected throughout the Hurricane Laura event.”
Entergy said it was readying a nearly 7,400-strong storm crew to respond in the Texas and Louisiana portions of its territory. The utility said it enacted flood protection for its facilities and equipment that could experience high water and secured the use of high-water vehicles, drones, helicopters and air boats for restoration efforts.
The utility also warned that restoration times might be longer than normal because of COVID-19 pandemic safety precautions. It said its field restoration crews will adhere to social distancing.
Entergy said its system was largely spared by Tropical Storm Marco passing through its territory on Monday, as the storm had significantly weakened by then.
“While we were fortunate that Marco had limited impact on our systems, customers should keep their guard up as Hurricane Laura, which is predicted to be much stronger, is on the way,” said Entergy Vice President of Utility Distribution Operations Eli Viamontes. “Please remain storm-ready and take this as seriously as we are. This is expected to be a major hurricane and should be treated as such.”
ERCOT Senior Meteorologist Chris Coleman predicted “devastating” 10- to 15-foot storm surges in some coastal areas of Texas and sustained winds of at least 130 mph.
“This is a very large, powerful hurricane — by far the worst thus far in the 2020 hurricane season,” he warned.
NYISO energy markets performed competitively in the second quarter of 2020, with the economic shutdown caused by the COVID-19 pandemic leading to the lowest load levels and average fuel prices seen in more than a decade, according to the Market Monitoring Unit.
“Demand was extremely low, and fuel prices were extremely low,” Pallas LeeVanSchaick of MMU Potomac Economics told the ISO’s Installed Capacity/Market Issues Working Group on Tuesday in presenting its quarterly report on the markets.
“All-in prices ranged from $15 to $61/MWh, down 9 to 31% from 2019 in all regions except New York City, which saw an increase of 12% because of the higher capacity prices we saw there,” LeeVanSchaick said.
For the first time in more than a decade, capacity costs constituted the majority of the city’s all-in prices (71%), compared to the usual third or so, because of an increased locational minimum installed capacity requirement (LCR) and very low energy prices, he said.
All-in prices by region | NYISO
Energy consultancy ICF International in June 2018 highlighted the possibility of increasing capacity prices in New York City, citing NYISO’s revised assumptions and references for its buyer-side mitigation analysis that forecasted the LCR for the city at 2.5 to 4.5% above its then-current level of 80.5% in the 2020/2021, 2021/2022 and 2022/2023 capability years, saying the “higher LCRs are equivalent to approximately 320 MW of demand in 2020 and 550 MW in 2021 and 2022.”
The report said the actual LCR rose from 82.8% to 86.6% in New York City. Capacity costs fell by 5% on Long Island and 40% in the Lower Hudson Valley but rose by 64% in the city and doubled in the Rest-of-State regions, both from changes in demand and supply.
“In ROS, Kintigh retired at the end of March, and both Cayuga units retired in June, marking the end of the coal era in NYISO,” he said.
Natural gas prices continued to fall, with quarterly averages being the lowest witnessed over the last decade, regardless of season: $1.43/MMBtu at the Transco Z6 hub, down from $2.25/MMBtu in the same quarter a year ago.
Swing Low and Loose
The 5% average load reduction was a decrease against what had previously been the lowest second-quarter load in more than a decade, although peak load levels were consistent with last year because of a heat wave in June that drove energy demand higher.
The pandemic had a significant reductive impact on loads, reducing New York City’s load by 11%, based on weather-normalized values. The pandemic drove most of the load reduction from 2019, continuing the trend seen in the first quarter. (See NYISO Q1 Energy Prices Hit 11-Year Low.)
Generation patterns and capacity supply changed with the retirement of the Indian Point 2 nuclear unit, as well as the last two coal plants in the state, and some of those impacts were offset by the new entry of the Cricket Valley Energy Center, LeeVanSchaick said.
Lower load levels and gas prices led to lower transmission congestion and uplift.
Mapping Congestion
The report featured a new system congestion map, which LeeVanSchaick said offers a truer representation of congestion patterns.
“Where there’s a generator, it shows you what the pricing of that generator location is, but all of the load zones are shown according to the average price of the load zone on the other chart; but on this one, it’s on a gray background, and that’s helpful to distinguish between areas where there’s not a lot of generation versus areas where there may be a concentration,” he said.
Day-ahead congestion revenues totaled $62 million, down 46% from a year ago, primarily because of lower gas prices and load levels. Day-ahead congestion fell across the system, with most of the decrease occurring on the Central-East interface and in the West Zone.
System congestion real-time price map at generator nodes | NYISO
New York City constraints accounted for only about 5% of congestion, which fell by nearly 80% in the city from the previous year.
Unlike most other transmission corridors, congestion from the North Zone to central New York rose by more than 100% from a year ago, and 90% of this congestion occurred on the 230-kV Moses-Adirondack MA1 line when the parallel MA2 line was out of service in most of May and June.
“We also saw wind curtailments about 8% of the time because of unusually high congestion from the north,” he said.
Day-ahead Congestion Revenues
The report included a graph of day-ahead congestion revenue shortfalls, identified by transmission corridor, with the majority coming on the West Zone lines.
Day-ahead congestion revenue shortfalls by transmission facility | NYISO
To the extent that the congestion revenue shortfalls weren’t associated with Lake Erie circulation, they were generally related to outages at the Niagara plant of transformers 1, 2 and 4, as well as the Niagara-Rochester line, LeeVanSchaick said.
“Those outages will reduce how much can flow through there, so you see where that resulted in significant uplift,” he said. “We also saw in May and June very significant amounts of shortfalls coming down from northern New York, and those were associated with the outages of those Moses-Adirondack lines related to the [New York Power Authority] Smart Path Reliability Project.”
NERC CEO Jim Robb said in a media briefing Thursday that the organization has no plans to request further delays in the effective dates of seven reliability standards that were deferred earlier this year in light of the COVID-19 pandemic.
FERC Agrees to Defer Standards Implementation.) Affected measures include the following cybersecurity supply chain standards, whose implementation dates were pushed back from July 1 to Oct. 1:
PRC-027-1 (Coordination of protection systems for performance during faults)
In addition, the effective date of certain provisions of PRC-002-2 (Disturbance monitoring and reporting requirements) and PRC-025-2 (generator relay loadability), originally scheduled to take effect July 1, was moved to Jan. 1, 2021.
In discussing the decision not to seek further deferrals, Robb drew a distinction between these measures and other COVID-19 responses that NERC has sought to extend in recent months as the pandemic wears on, with no end in sight. For example, the organization announced last week it would keep its offices in Atlanta and D.C. closed through the end of 2020. (See NERC Extends Self-logging, Deferments Through Dec.)
While NERC and FERC have discussed giving registered entities more time to complete their compliance preparations in light of the evolving public health situation, the organizations ultimately decided that the standards — particularly those dealing with cybersecurity — were too critical to reliable operation of the grid to delay any further (echoing criticism voiced at the time of the original deferral).
“Given how important [the] supply chain is, it just doesn’t feel prudent to continue to push [those standards] off,” Robb said.
NERC Compiling Alert Responses
Manny Cancel, NERC | NERC
The briefing also included an update from Manny Cancel, senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center, on the Level 2 alert issued by the ERO earlier this year requesting information on the bulk power system’s vulnerability to cyberattacks by foreign governments. (See Trump Declares BPS Supply Chain Emergency.)
With the Aug. 21 deadline for responses to the alert past, NERC is now busy compiling the results for a report to be submitted to FERC, Cancel said. Data from the alert will be used to determine “how many devices [on the grid] have been manufactured in potentially rogue nation-states that might be looking to take advantage of our infrastructure here.” While the information itself will be confidential, NERC may share “themes” of the results with the public if necessary.
China and Russia have been identified as particularly concerning “foreign adversaries” with the capability to launch cyberattacks against the grid, with Iran, Cuba, North Korea and Venezuela also referred to as noteworthy threats.
Details of NERC’s Level 2 alert were confidential, but Mark Kuras, senior lead engineer in PJM’s Reliability Compliance Unit, told the RTO’s Operating Committee that the information requested focuses on transformer control and protection systems that are 10 years old or newer. The alert applied mostly to generation and transmission owners, and on “distribution providers to some extent,” he said.
PJM members last week approved two changes to the RTO’s market efficiency project planning process while rejecting a third to create a new regional targeted market efficiency project (RTMEP) process that had been challenged by stakeholders.
The RTMEP package proposed by American Electric Power and FirstEnergy received a sector-weighted vote of 1.56 (31%), failing to meet the 3.33 (66.7%) threshold for passage at Thursday’s Market and Reliability Committee meeting. The package, which transmission owners said would target small projects addressing persistent congestion not identified in the forward-looking planning model and would have awarded RTMEPs to the incumbent TO, was opposed by other stakeholders who had criticized it for excluding competition. (See PJM Stakeholders Debate Market Efficiency Proposals.)
PJM’s proposal, which called for 30-day competitive windows to select the developer in the RTMEP process, also failed to garner support, receiving a sector-weighted vote of 2.63 (53%). The AEP-FE proposal originally won 56% support in Planning Committee vote in May, edging out the PJM proposal, which received 55% support.
Brian Chmielewski of PJM said the RTMEP issues have been worked on by stakeholders for more than two years, and the packages were the product of extensive member input. Chmielewski said the idea to examine the RTMEP process originated from the interregional PJM-MISO TMEP planning process that had successfully produced a half-dozen projects.
Steve Lieberman, director of regulatory affairs for American Municipal Power (AMP), said he appreciated the effort that went into the packages, but he said AMP didn’t feel like the solutions in the packages were supportable.
“That’s not an indication for the need for more discussion,” Lieberman said. “We just don’t think there’s a problem here to be solved.”
Stakeholders did approve two changes regarding the RTO’s existing market efficiency, or “economic,” projects.
In a vote on the benefit calculation metric MEPs, stakeholders rejected a FirstEnergy solution package, which would have averaged multiple Monte Carlo results and run them on Regional Transmission Expansion Plan (RTEP), RTEP+3 and RTEP+6 years. That package failed with a sector-weighted vote of 2.02 (40%).
But PJM’s proposal and Operating Agreement revisions, which would use a single-draw Monte Carlo simulation, with simulations for both Reliability Pricing Model and RTEP years, won support from stakeholders, coming away with a sector-weighted vote of 3.75 (75%).
Stakeholders also approved PJM’s package to clarify when capacity benefits of MEPs are calculated, removing obsolete language from the Tariff that conflicted with the OA.
The approved packages now move on to the Members Committee for a final vote on Sept. 17 and a FERC filing in October.
Zonal NSPL Values
Stakeholders by acclamation endorsed deadline changes for adjustments associated with finalizing the zonal network service peak load (NSPL) values in Manual 14D and Manual 27.
Ray Fernandez, PJM manager for market settlements development, reviewed updates to the generator operational requirements in Manual 14D and the Tariff Accounting section of Manual 27. The Manual 27 revisions were endorsed at the Aug. 5 Market Implementation Committee meeting, while the related Manual 14D revisions were endorsed at the Aug. 6 Operating Committee meeting.
The revisions are related to the border yearly charge (BYC), the charge for long- and short-term point-to-point transmission service for points of delivery at PJM’s border, which goes into effect on Jan. 1 of each year. Fernandez said deadlines in both manuals conflicted with the deadlines of the BYC, including ones for the NSPL verification and zonal adjustments.
In Manual 14D, the behind-the-meter generation business rules had a Dec. 1 deadline for a load-serving entity to request a downward adjustment to its NSPL or obligation peak load. PJM proposed revising the deadline from Dec. 1 to Oct. 31.
Changes in Manual 27 included adding clauses to section 5.2 stipulating adjustments that need to be provided to PJM Market Settlements by Nov. 10. Any adjustments provided after the deadline will not be included in the NSPLs for the next calendar year and won’t be used in the BYC calculation.
Risk Management Committee Charter
The newly minted Risk Management Committee is set to meet for the first time in fall after stakeholders approved revisions to the Credit Subcommittee charter, expanding its scope to incorporate risk and changing its reporting structure.
Under the revised charter, the renamed subcommittee is also being elevated to a standing committee, reporting to the MRC rather than the MIC.
In her presentation, Jen Tribulski, PJM’s senior director of member services, said the Credit Subcommittee last met in March 2019 with much of the work around the RTO’s credit and risk rules accomplished through the Financial Risk Management Senior Task Force in the wake of the GreenHat Energy default.
Tribulski said the task force was established for the specific purpose of overhauling PJM’s rules for managing the credit risks of market participants and was not tasked with reviewing credit and risk management issues outside of its limited purposes. (See PJM Members OK Tighter Credit Rules.) She said PJM felt it was important to have a committee available to review and work on issues beyond those contemplated by the task force.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, and Erik Heinle of the D.C. Office of the People’s Counsel had proposed creating a Critical Infrastructure Stakeholder Oversight Senior Task Force under the MRC.
Poulos and Heinle said the task force would have considered whether rule changes are needed to address facility avoidance and mitigation through planning processes and criteria on NERC’s critical infrastructure protection (CIP-014-2) list. (See PJM TO Tariff Filing Stirs up Transparency Concerns.)
PC special sessions on the topic are currently scheduled through September, with avoidance and mitigation processes and criteria under consideration. (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.) In proposing the task force, Poulos and Heinle expressed concern progress wasn’t being made in the PC special sessions and that TOs can bypass the stakeholder process with filings under Federal Power Act Section 205.
But on Thursday, Poulos said the PC is “in a much better position this month” with “great discussions” among members on mitigation and avoidance of CIP-014 projects. Poulos said PJM and AMP have been putting together “thoughtful packages” to achieve compromises.
Alex Stern, director of RTO strategy for PSEG Services, said he was “a little anxious” of the idea of members being able to make a motion at the MRC if they don’t like the direction the stakeholder process is going on an issue.
Poulos said he recognizes stakeholders can vote any way they want to on an issue, but the ability to bring an issue to a vote at the MRC is the right of stakeholders.
Cost Development Subcommittee
Glen Boyle of PJM reviewed proposed revisions to the Cost Development Subcommittee charter during a first read. Boyle said the CDS has been dormant since 2013 and was tasked with developing, reviewing and recommending standard procedures for calculating the costs of products or services.
PJM and the Independent Market Monitor have discussed the need to restart the CDS to address several issues, Boyle said, including Manual 15 clarifications, variable operations and maintenance (VOM), and fuel-cost policy clarifications and educational topics.
The CDS charter has been revised by PJM to report to the MIC instead of the MRC, as most of the issues are handled at the MIC.
The charter changes are scheduled to be voted on at the September MRC meeting.
Consent Agenda
Two issues were endorsed in the consent agenda, with one stakeholder voting no on the agenda items.
Second, stakeholders endorsed OA revisions to grant TOs access to the Dispatch Interactive Map Application. (See “DIMA Quick Fix Endorsed,” PJM OC Briefs: July 9, 2020.)
The three California organizations that oversee electricity responded to a request by Gov. Gavin Newsom to explain why the state had two days of rolling blackouts on Aug. 14 and 15 and would have had more if not for statewide conservation efforts.
“We agree that the power outages experienced by Californians this week are unacceptable and unbefitting of our state and the people we serve,” CAISO, the Public Utilities Commission and the Energy Commission told Newsom in a joint letter last week. “We understand the critical importance of providing reliable energy to Californians at all times, but especially now, as the state faces a prolonged heat wave and continues to deal with impacts from the COVID-19 pandemic.”
The organizations operate independently but coordinate efforts to supply the state with electricity. CAISO operates the transmission grid. The CPUC regulates investor-owned utilities and orders procurement. The CEC forecasts demand, among other functions.
“We are working closely as joint energy organizations to understand exactly why these events occurred,” they said.
The tone of shared responsibility differed from CAISO initially blaming the CPUC for failing to procure sufficient energy despite warnings of capacity shortfalls starting this summer. (See CAISO Blames Blackouts on Inadequate Resources, CPUC.)
Disconnecting Navy ships from shore power helped CAISO avoid more blackouts. | U.S. Navy
Leaders of the three organizations said their staffs would need more time to fully analyze the causes of the blackouts, but they provided Newsom with their initial findings. The letter was signed by CAISO CEO Steve Berberich, CPUC President Marybel Batjer and CEC Chair David Hochschild.
Demand on Aug. 14-15 was high, peaking at approximately 47 GW and 45 GW respectively, they said, “but not above similar hot days in prior years. Given this, our organizations will need to conduct a deep dive into how we ensure sufficient electric supply and will make modifications to our reliability rules to make sure reliability resources can be available to address unexpected grid conditions.” (See CAISO: Blackouts May Continue, Calls Emergency Meetings.)
The state’s “heavy reliance” on imports was one obvious factor in the blackouts, the leaders told Newsom.
The heat wave that engulfed the West in triple-digit temperatures dried up imports that weren’t secured by long-term contracts, CAISO said. It struggled to meet peak demand during the late afternoon and evening hours and would have ordered additional days of rolling blackouts if conservation efforts hadn’t cut demand by 2,000 to 3,000 MW and the state hadn’t secured more megawatts. (See ‘Last Challenging Night’ for CAISO, Governor Hopes.)
Conservation, More MWs
The organizations provided additional details on those efforts in the letter to Newsom.
The CEC coordinated with data centers in Silicon Valley to move approximately 100 MW of load to on-site backup generation, the letter said. It worked with the U.S. Navy and Marine Corps to “disconnect 22 ships from shore power, move a submarine base to backup generators and activate several microgrid facilities resulting in approximately 23.5 MW of load reduction.”
The state Department of Water Resources and the Metropolitan Water District of Southern California shifted 80 MW of hydroelectric generation to peak demand times. The department and the U.S. Bureau of Reclamation made changes in pumping schedules that secured another 72 MW. And San Francisco maximized output at its Hetch Hetchy hydroelectric facilities to generate an additional 150 MW during peak demand periods.
CAISO and the CPUC have both warned of more severe shortfalls going forward as fossil fuel plants and the state’s last nuclear power generating station retire. The state’s switch to solar and wind resources isn’t to blame for the shortfall, but far greater storage is needed to meet “net-peak” demand after the sun sets, CAISO and the CPUC said recently. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)
To avoid shortfalls in the coming summers, “forecasts and planning reserves need to better account for the fact that climate change will mean more heat storms and more volatile imports, and that our changing electricity system may need larger reserves,” the organizations wrote.
The CEC is holding sessions Wednesday to help forecast demand through 2030, with the recent shortfalls part of that discussion.
Renewable energy’s proliferation has played a key role in helping ERCOT meet demand, but it is also beginning to cause transmission constraints that are likely to increase during the next five years.
Staff are previewing what they say are necessary future conversations. They say that while planning studies have not shown that transmission constraints will hamper resource adequacy in the near term, they will pose an increasing challenge requiring more training, detailed models and more powerful software.
The problem is that new resources are being sited farther away from urban load centers, taking advantage of Texas’ ample wind and solar potential. This shift from traditional, large fossil-fired plants near load centers to smaller renewable resources on the farthest reaches of the ERCOT system has led to the stability challenges.
ERCOT’s transmission-constrained areas | ERCOT
“Every year, we’re seeing generation getting a little further from load. That’s our underlying issue,” said Woody Rickerson, ERCOT’s vice president of grid planning and operations. “It’s inherently harder to serve load on the edge of the system, where it’s not networked deeply into the system.”
Rickerson told ERCOT’s Board of Directors during its Aug. 11 meeting that most new generation projects are inverter-based resources. These resources are added to the planning models six months to two years ahead of their commercial operation date, but transmission upgrades resolving congestion can take up to six years to complete.
Planning studies beyond 2022 don’t include wind or solar projects, Rickerson said, “because the development time frame puts them inside the 2023 timeline.”
“The planning process will result in some lag and congestion,” he said.
Jeff Billo, ERCOT’s senior manager of transmission planning, said the grid operator’s “generator-friendly” interconnection process has also played a role. Beginning with the Competitive Renewable Energy Zone (CREZ) initiative — which resulted in 3,500 miles of transmission facilities in 2013, freeing up 18.5 GW of West Texas wind energy — the grid operator’s stakeholders have set up processes designed to quickly add generation to the grid.
“Most developers I talk to prefer the ERCOT way, with the firm transmission rights and being able to get interconnected in less than two years, versus other [regions], where I hear anecdotally it can take six to seven years,” Billo said. “We really needed to build some amount of transmission that was appropriate for new generation.”
Not surprisingly, ERCOT has identified its West Texas zone, home to most of the state’s wind resources, as one of five geographical areas where it expects emerging reliability and/or economic issues. Reliability issues are driven by load growth, and economic issues are typically driven by generation growth.
Rickerson said 28 GW of renewable generation is expected to be connected in West Texas, far beyond CREZ’s plans. Stability limitations are expected to lead to high levels of congestion on West Texas exports, he said, but ERCOT is studying the region’s congestion solutions in its 2020 Regional Transmission Plan.
Far West Texas is also home to the oil-rich Permian Basin’s Delaware Basin, the fastest growing load in Texas. The region’s annual peak load has grown by more than 10% since 2010, compared to the ERCOT’s systemwide growth rate of about 1.5% during the same time frame.
ERCOT’s new generation resources are mostly in West Texas, while demand is in the east and south. | ERCOT
Staff analyzed the Delaware Basin and has identified a five-stage roadmap of transmission upgrades to continue meeting the oil and gas load.
“If you are moving power across a longer distance, you’ll have more marginal losses and reactive losses. With the inverter controls, you’re pushing a lot of power on your circuit … and getting stability challenges,” Billo said. “Going forward, stability is going to be more limiting than thermal issues. That’s just the way our generation fleet is evolving.
“Because we have that generation-friendly environment, we can wait until the last minute [for developers] to turn in their data or make a commitment,” he said. “We don’t have a lot of lead time to know where the generation constraints are through this process. We’ve seen the system is evolving to where we see more and more stability constraints on the system, but the stability studies take time.”
The Delaware Basin’s peak demand has been steadily increasing. | ERCOT
Interconnecting resources are increasingly requesting remedial action schemes (RASes) as a protection scheme. These hardwired relay systems detect predetermined system conditions and automatically take corrective actions, which can include transmission reconfiguration and load sheds or generation trips that allow resources to produce beyond local transmission constraints.
“When [an RAS] sees a condition, it doesn’t call the operator. It acts,” Rickerson said. “A lot of study goes into them from a reliability standpoint. It’s something you really have to pay attention to.”
ERCOT has drafted a change to the Nodal Operating Guide (NOGRR215) that is currently winding its way through the stakeholder process. The change proposes boundaries for new RASes that limit reliability risks associated with their potential widespread use.
The schemes were a major topic of conversation last week during a workshop on transmission issues related to generation constraints. EDF Renewables, SolarPrime and other renewable interests submitted presentations advocating for RASes and the need to meet economic criteria.
The grid operator also relies on generic transmission constraints (GTCs), predefined collections of transmission elements, to maintain grid reliability to subject the aggregate power flow to a defined limit in real time. This is necessary because economic dispatch, reliability unit commitment and other existing market tools are not capable of calculating other operating limits.
ERCOT held a GTC-themed workshop in February and has drafted a GTC white paper to educate and inform stakeholders.
Five of the grid operator’s 12 GTCs can be found in South Texas, which faces both import (reliability) and export (economic) stability constraints. LNG facilities in the Rio Grande Valley could require up to $1.2 billion in transmission improvements and additional generation development in the region could lead to further stability constraints.
ERCOT’s other staff-flagged transmission-constrained areas include:
The Northwest Dallas-Fort Worth Import: One of the highest congested areas in recent planning studies, generation development northwest of the DFW area and load growth within the metroplex is expected to exceed the region’s transmission capacity. Rickerson said staff are actively analyzing project options to relieve these constraints.
Houston-Freeport Import: The Houston Import went into service in 2018 and the Freeport Import will be completed in 2021. (See ERCOT Stakeholders OK $246.7M in Freeport Reliability Projects.) However, the 2014 Houston Import Project study indicated additional upgrades would be needed by 2027 to continue meeting reliability criteria. Recent planning studies indicate congestion will increase in coming years as power is imported into the Houston and Freeport areas.
Oregon regulators are grappling with how to modernize the state’s customer-choice electricity program to accommodate a rapidly changing energy landscape that’s being reshaped by decarbonization policies across the West.
The Oregon Public Utility Commission last year opened an investigation (UM 2024) into the state’s 20-year-old long-term direct-access programs, which give large energy consumers the ability to obtain electricity service outside the regulated cost-of-service regime. The commission is now seeking how to shape the inquiry.
The state legislature authorized the PUC to implement direct access as part of a raft of provisions in SB 978, a 1998 law intended to equip the commission with authority to implement programs that could address investor-owned utility greenhouse gas emissions, encourage the development of a regional electricity market and create retail choice options for nonresidential customers.
Oregon’s two main IOUs, Portland General Electric (PGE) and PacifiCorp, function as gatekeepers for the programs, providing larger consumers with a yearly process for applying to opt out of regulated service in order to enroll in either a utility-run, market-based program, or contract with a third-party direct-access electricity service supplier (ESS). Similar to the process in other Western states, opting in to direct access carries certain “transition” costs for customers that ensure utilities reduce their exposure to stranded costs for providing regulated service, including meeting resource adequacy requirements. Those costs ultimately fall to the larger pool of cost-of-service customers.
Evolutionary Need
UM 2024 comes in response to a June 2019 petition from the Alliance of Western Energy Consumers (AWEC), whose membership represents companies with 160 facilities (that employ 170,000 workers) comprising both direct-access and cost-of-service customers, according to the organization.
Oregon PUC Commissioner Letha Tawney | Oregon PUC
In seeking the investigation, AWEC’s petition cited “significant disputes” over the programs in recent years, including those related to whether the state should further expand or restrict the programs and whether the programs have benefited or harmed cost-of-service customers. AWEC also noted that PGE’s direct-access program — what it called the only one “that has successfully contributed to the development of a competitive market in Oregon” — is nearing its 300-MW cap, making it soon unavailable for customers.
“My goal, when I think about this docket, is to sort of see how and where this customer-choice option needs to adapt to the current and likely future of the system — the policy, the regulation, the markets and technology that are all evolving alongside a customer-choice program that we set and have tinkered around the edges with but not fundamentally grappled with for two decades,” Commissioner Letha Tawney said during a Thursday workshop on the issue.
The PUC is proposing that its line of investigation address four sets of questions:
Does the direct-access law currently raise concerns about unwarranted cost-shifting “or other relevant harms to the public interest?” Would expansion of the programs in size and reach create additional “concerns related to unwarranted cost-shifting or other relevant harms to the public interest?”
Can program design mitigate unwarranted cost-shifting or other relevant harms? “What mechanisms should be used; how should such mechanisms be structured; and what are the legal or practical barriers to implementing them?”
“With such mechanisms in place, are unwarranted cost-shifting or other relevant harms to the public interest mitigated to the degree that the commission should expand access to direct-access programs?”
What evidence has been presented or could be presented in the docket (or a future one) to show that existence of cost-shifting and whether it would occur under an expansion of the program, and whether mitigation would be effective at preventing cost-shifting?
“I think our task here is in no small measure updating direct access and this particular kind of customer choice to where the world is today and the realities that are unfolding before us. … We talk a lot about existing cost-shifting, but I worry about the future,” Tawney said.
From Cost-shifting to Risk-shifting
In comments filed ahead of the workshop, PGE asked the commission to consider the future potential for future “risk-shifting” in addition to historical concerns around cost-shifting.
Nidhi Thakar, PGE | Oregon PUC
Elaborating in the workshop, PGE Director of Strategy Nidhi Thakar offered an example of risk-shifting: the fact that IOUs must serve as “de facto” energy providers of last resort in cases when an ESS fails financially, foisting its customers back on the utilities.
“We just want to call out again that we really see a distinction between the terms ‘cost-shifting’ and ‘risk-shifting,’” Thakar said during the workshop. “There are … going to be risks that are quantifiable. We really do believe that there are risks that are going to be harder to quantify, which to the extent that they can be quantified, those numbers could continually be changing.
“The markets are constantly evolving and changing at a rapid pace in the West, and I think it’s important that there is some breathing room from the regulatory standpoint to readjust what some of these pricing mechanisms may look like that may potentially come out of this discussion.”
Etta Lockey, PacifiCorp | Oregon PUC
Etta Lockey, PacifiCorp vice president of regulation, seconded PGE’s take: “We don’t want to get hung up on not being able to take action now because a particular risk can’t be fully quantifiable or there’s not full evidence of an unintended consequence that is likely to happen in the future.”
Speaking for the Northwest & Intermountain Power Producers Coalition, which represents ESSes, attorney Carl Fink rebuffed the notion that the PUC’s proceeding should examine potential future risks for the IOUs.
“I don’t really believe that’s within the scope of what we can be doing here, nor do I think it’s appropriate to really be looking at some of the opportunity costs that may or may not occur to the extent that utilities lose market share,” Fink said.
Oregon PUC Chair Megan Decker | Oregon PUC
PUC Chair Megan Decker clarified her own thoughts about how to address potential opportunity costs for IOUs that could lose market share while still needing to maintain resource adequacy in their service territories.
“When I’m talking about that opportunity cost around meeting a flexible load in the grid, I’m very open to how that load comes to the table and participates. I think there’s a need, and I have an interest in how the ESSes might participate in that flexible future,” Decker said.
Fink also advocated for further expansion of direct access.
Carl Fink, Blue Planet Energy Law | Oregon PUC
“We do want to stress that, to the extent the commission is looking back at how we should be doing direct access, we always need to start with the statute, as we say in every one of our pleadings,” Fink said. “The statute puts requirements on the commission. It doesn’t ask the commission to decide whether direct access is supposed to be OK; it says you shall ensure direct access. And it says it needs to be direct access for all customers.”
Tawney expressed concerned that, under the current structure, “a sort of wall comes down” after an electricity customer converts to direct access, cutting it off from the mechanisms in the regulated sector, “even though these customers have some of the most flexible and most interesting — and most capable — on-site resources that might help us through our transition to a clean-energy, high-renewables-based grid.”
“There is a lot to be said for policy stability, but that means we need to set out boundaries or structures that will be resilient for how this future unfolds in the next decade, and that really requires thinking about the unexpected and setting up policies and structures that will manage those changes effectively,” Tawney said.
Tyler Pepple, Davison Van Cleve | Oregon PUC
Tyler Pepple, the attorney who filed the petition on AWEC’s behalf, asked whether the PUC would proceed under the presumption that direct access is in fact in the public interest.
Oregon PUC Commissioner Mark Thompson | Oregon PUC
“Is that the intention there, that we’re sort of assuming that direct access is in the public interest because it’s required by statute, or do you think that it’s important for the parties to present evidence on the benefits of direct access and whether that would be helpful?” Pepple asked.
Commissioner Mark Thompson said he didn’t think the PUC is being asked to consider whether direct access is in the public interest because state law has already established the program.
“I guess where I think the public interest question enters into it for us is with respect to how do we implement the statute’s guidance that we’re supposed to protect against unwarranted cost-shifting; and I do think the statute clearly contemplates us having a role there to put potential limits or guidelines on how that program is implemented,” Thompson said.
SPP staff are working feverishly to address FERC and Market Monitoring Unit concerns that threaten the launch of its Western Energy Imbalance Service (WEIS) market.
FERC last month rejected the RTO’s proposed Tariff for the market, saying it failed to respect nonparticipants’ transmission rights and could improperly burden reliability coordinators. The commission also cited shortcomings on supply adequacy, market power protections and line-loss calculations (ER20-1059, ER20-1060). (See FERC Rejects SPP’s WEIS Tariff.)
On Aug. 3, SPP’s MMU posted a report on a WEIS market study that found “high potential” for structural market power. The Monitor concluded that the WEIS presents “significant structural market power concerns” for energy and imbalance energy that should be addressed before its implementation.
SPP’s regulatory and legal departments are working to revise the Tariff for another filing in early September. Staff have met with the region’s nonparticipants to understand and address their concerns and then fold them into the next filing. They plan to meet with FERC staff in September to lay out a plan for moving forward.
The WEIS working group and executive committee last week passed four revision requests (WRRs) responding to the FERC and MMU issues. Those groups have scheduled two joint meetings this week to hammer out additional WRRs needed to finalize the filing.
Market Design Manager Gary Cate said he is still confident SPP can meet a Feb. 1 deadline for launching the market.
“I think we’ve put together a really good package and minimized changes to everyone’s system involved, and I think we’ve hit directly at what the FERC’s recommendations are. I don’t see why we can’t move forward,” Cate told the Western Markets Executive Committee during its meeting Friday.
David Kelley, SPP’s director of seams and market design, noted that the commission provided specific guidance to help staff respond to the filing’s deficiencies.
“This order was really a good order for us,” he said. “When you read through it, it was very complimentary of our efforts and recognized the benefits of markets being developed in the West. I got the sense the commission was encouraging us to continue developing the WEIS market and address the issues they noted in the order.
“We will know where we stand after meeting with FERC in September,” Kelley said.
The WMEC and Western Market Working Group’s approved revision requests last week included WRR5, a response to FERC’s assertion that there was a lack of justification for automatic increases to market mitigation thresholds and the MMU’s concerns over market power.
SPP based its proposal on its Integrated Marketplace market power mitigation provisions, where it automatically applies mitigation measures to resource offers if the offer exceeds applicable thresholds and fails the market impact test.
The change expands the local market power test to include an assessment of structural market power at the system level. It also “appropriately” mitigates the energy offers when a resource has system-level structural market power and an energy offer curve that exceeds the conduct test threshold, when an impact test has failed for that market interval.
MMU Executive Director Keith Collins said the Monitor “fully supports” WRR5, which borrows from a similar ISO-NE mechanism.
MMU Director Keith Collins shares his thoughts on the WEIS market power study. | SPP
“We think it’s a good alternative,” he said.
The Western markets governance groups also approved three other WRRs:
WRR2: updates the WEIS protocols to be consistent with SPP’s system change process and modifies the emergency change language to clarify that the RTO will notify stakeholders of the change as soon as practicable.
WRR3: aligns the WEIS protocols to the Tariff, and documents the changes for the WRR process.
WRR4: corrects a calculation of the lower operating tolerance for underground residential distribution (URD) and clarifies language expanding URD tolerance during contingency reserve events.
The WEIS currently includes eight members and covers the Western Area Power Administration’s Western Area Colorado Missouri and Western Area Upper Great Plains West balancing authority areas. Several other Western utilities are interested in participating as well, SPP has said.
Market participants are currently undergoing structured testing of SPP’s upstream systems. They are testing data inputs in certain scenarios to ensure they act as expected.
Utilities in seven Southeastern states could cut their electric rates by more than a quarter and reduce greenhouse gas emissions by almost half by joining an organized wholesale market, according to a study by a clean energy think tank.
The study by Energy Innovation Policy & Technology compared the use of utility-specific integrated resource plans (IRPs) with an RTO Scenario, which chose the most economical resources, optimized dispatch to minimize cost, and co-optimized transmission and distribution planning and regionwide reserve sharing. The results were based on a combined production-cost and capacity-expansion model of the electric power system in Alabama, Florida, Georgia, North Carolina, South Carolina, Tennessee and the non-MISO portion of Mississippi.
It projected cumulative economic savings of about $384 billion for the RTO Scenario compared to the IRP Scenario. By 2040, researchers say, retail rates would average 2.5 cents/kWh, or 29% less than current costs (adjusted for inflation).
The researchers also project a 37% reduction in carbon emissions compared with 2018 levels, and a 46% reduction compared to the IRP Scenario. They said the RTO Scenario would create 285,000 more jobs than the IRP Scenario, thanks to the construction of 62 GW of solar, 41 GW of onshore wind and 46 GW of battery storage.
The study projects cumulative savings of about $384 billion for the RTO Scenario compared to the IRP Scenario. By 2040, researchers say, retail rates would average 2.5 cents/kWh (29%) less than current costs (adjusted for inflation). | Energy Innovation Policy & Technology
Energy Innovation’s online data explorer allows readers to review the impact of a Southeast RTO on the region’s fuel mix, emissions, jobs and costs by region and state.
The study is the latest of several recent initiatives looking at the Southeast’s alternatives to the current vertically integrated model. Legislators in the Carolinas have proposed studies on creating an RTO and about 20 utilities and cooperatives in the region — including Duke Energy, Southern Co. and Tennessee Valley Authority — are discussing a voluntary 15-minute energy market, the Southeast Energy Exchange Market (SEEM). (See Southeast Utilities Talking Regional Market.)
Last September, Santee Cooper’s largest customer joined PJM in the wake of the South Carolina-owned utility’s abandoned plans to build a new unit at the V.C. Summer nuclear plant. (See South Carolina Power Cooperative Joins PJM.)
“Despite the fact that new renewable energy and battery storage resources are the least-cost forms of generating electricity, the Southeast region is largely beholden to monopoly utilities that rely on existing coal fleets and new gas-fired power plants to meet consumer electricity needs,” Energy Innovation said. “Policymakers considering a regional market or state-level competitive procurement should be encouraged by this analysis to keep pressing in legislative and regulatory forums. State stakeholders where utilities block competitive reforms now have new quantitative findings to challenge the assumption that the way utilities have traditionally done business is in the public’s best interest.”
Asked to respond to the findings, Duke spokeswoman Erin Culbert said Monday that the utility has “been advancing a clean energy transition for more than a decade” and doesn’t “need to wait for an RTO.”
“Duke Energy customers already enjoy many of the benefits RTOs claim to bring because of our large geographic size and generation diversity,” she added. “The energy market we’re considering would enhance that and better integrate renewables at a much lower cost than an RTO.”
TVA spokesman Scott Fiedler said, “It would be inappropriate to comment on a study that we did not participate in, nor had the opportunity to review the underlying data used to develop the conclusions.”
Officials of Southern Co. did not immediately respond to requests for comment.
Region Resistant to Renewables
Energy Innovation describes itself as a nonprofit energy and environmental policy firm funded by foundations and philanthropic donors that support decarbonization and climate policy. For the study, Energy Innovation used a model from Vibrant Clean Energy, which was supported by funding from the Hewlett Foundation.
The firm says ratepayers in the Southeast are missing out on the economies of a regional market because their monopoly utilities plan their grids and generation needs independently from their neighbors — including subsidiaries of the same holding companies — and discourage competition by imposing wheeling charges on imports. “Largely insulated from meaningful forms of competition, Southeastern utilities have been among the slowest to embrace clean electricity resources, even as resource costs have fallen precipitously in recent years,” it said.
About 92% of the region’s coal capacity was uneconomic compared to local wind or solar as of 2018, the researchers said. “By 2025, that number grows to 100%.”
About 92% of the Southeast’s coal capacity was uneconomic compared to local wind or solar as of 2018, according to Energy Innovation Policy & Technology. By 2025, all coal will be uneconomic, the group says. | Energy Innovation Policy & Technology
The study did not include any carbon constraints and also did not imply a market design. “This is not PJM’s RTO. This is not MISO’s RTO. It is a technical optimization of costs based on one single regional grid,” coauthor Michael O’Boyle, Energy Innovation’s electricity policy director, said during a press briefing Friday.
The RTO model used a single planning reserve margin for the region, eliminating the inefficiencies of serving loads on a state-by-state basis in the IRP Scenario. It did not optimize transmission and dispatch with neighboring PJM and MISO, however.
Energy Innovation said its model represented the maximum benefits of competition, noting that some markets allow vertically integrated monopolies to continue recovering costs of generation from captive customers. “RTOs today also face structural and political barriers to transmission development and fair cost allocation, distribution optimization, and clean or distributed energy resource participation,” the researchers noted.
The researchers also acknowledged that the IRP Scenario is likely to differ from utilities’ ultimate 2040 mix because the 10- to 15-year IRPs are updated periodically. “Hopefully, as utilities and their regulators catch up to the reality that clean electricity is less expensive than the status quo, it is reasonable to assume the inefficiencies won’t be quite as stark as the modeling implies,” they said. “Nevertheless, we model the current IRPs to demonstrate how current utility plans … open up customers to financial risk from potential stranded assets.”
A Southeastern RTO would add increasing amounts of renewable generation, replacing coal and natural gas selected under utility integrated resource plans, according to Energy Innovation Policy & Technology. | Energy Innovation Policy & Technology
Additional Scenarios
The study also looked at two additional possibilities, including the Economic IRP Scenario, which includes a cost-optimal resource mix — reflecting competitive procurement within existing monopoly service territories — but without the co-optimized transmission and reliability planning in the RTO Scenario. It would save $298 billion through 2040 compared to the IRP Scenario — about three-quarters of the savings of the RTO Scenario.
“This recognizes the reality that full regionalization may be politically infeasible in the near to medium term but shows that a majority of the cost savings can still be achieved by subjecting utility procurement plans and existing generators to market competition,” Energy Innovation said.
The study looked at four scenarios. | Energy Innovation Policy & Technology
The RTO with Nuclear Scenario adds to the RTO Scenario the assumption that all existing nuclear plants extend their licenses and remain operational through 2040, regardless of cost-competitiveness — essentially assuming they would be kept in service through subsidies such as those enacted in Illinois, New Jersey and New York.
It would save about $375 billion through 2040, $9 billion less than the RTO Scenario but with a 41% cut in emissions below 2018 levels compared to a 37% drop in the RTO Scenario.
Reduced Reserve Margins
The RTO Scenario rationalizes transmission planning to reduce congestion and allow load pockets access to cheaper generation. It realizes about 10% of cumulative savings ($38 billion) from co-optimized distribution system planning that uses behind-the-meter generation and storage when it reduces total system costs.
The IRP Scenario would result in a reserve margin over 40% by 2040, according to the study, far above the 16% margin for the RTO Scenario. | Energy Innovation Policy & Technology
“This co-optimization of bulk and small-scale resources helps reduce peak load in the RTO Scenario 11.8% below the IRP Scenario, creating savings from generation all the way down to distribution,” the study says. “Realizing these savings goes beyond reforming the market structure for the bulk power system and likely requires regulatory incentives at the distribution level to coordinate with a central RTO.”
The researchers say the IRP Scenario would result in a reserve margin over 40%, resulting in more jobs in unnecessary coal and gas plants. “Utility IRPs in aggregate are redundant and excessive on their own, but when taking a regional view where significant efficiencies could be obtained by sharing reserves, the waste becomes more apparent,” the researchers said. “Utilities are rushing to build new gas generation that increases their earnings while planning to hold onto uneconomic coal generation for decades longer than economics would dictate.”
The RTO Scenario assumes a 16% reserve margin in 2040. Nevertheless, Energy Innovation says, “By 2040, the RTO Scenario leads to an additional 408,000 jobs in the sector, compared to just 122,000 new jobs in the IRP Scenario, a net of 285,000 jobs.”
Emissions
The study notes that Duke and Southern Co., which represent 45% of retail sales in the Southeast, have pledged net-zero company emissions by 2050. But it says, “a competitive market with no carbon policy does a better job of reducing emissions than Duke and Southern’s efforts.”
“Vertically integrated utilities’ incentives to maintain and earn on existing infrastructure conflicts with both customer wellbeing and environmental goals. … Regional transmission and operational approaches are more effective at integrating high shares of renewable electricity, and Duke and Southern hamper their own efforts to decarbonize at least cost by resisting regionalization efforts,” the researchers said.
The IRP Scenario adds little renewable generation or battery storage, while the RTO Scenario adds large amounts of wind and solar PV, including distributed PV, and utility-scale and distributed storage, with most gas peakers retiring by 2040.
Most generation would remain fossil fuel by 2040 under the IRP Scenario. “In the IRP Scenario, there is almost no wind generation, and solar PV provides just 4% of annual generation. In contrast, wind and solar provide 22% of generation in the RTO Scenario; when aggregated with nuclear (20%), geothermal/bioenergy (5%) and hydropower (4%), 51% of the Southeast fleet is zero-carbon by 2040.”
Other pollutants, including NOX, SO2 and PM2.5, also would be reduced by the elimination of coal-fired generation, the researchers say.
Endorsement
During the press briefing Friday, the Renewable Energy Buyers Alliance, which represents more than 120 major corporate purchasers, endorsed the call for regionalization and suggested the region’s competitiveness is at stake.
Bryn Baker, Renewable Energy Buyers Alliance | REBA
“More and more businesses are setting [clean energy] goals. They’re making decisions about siting and expanding facilities based on access to renewable energy,” said Bryn Baker, REBA’s director of policy innovation. “Right now, many parts of the country, including the Southeast, their only option is often a green tariff through the existing utility, which can often be limited.”
Baker said full regionalization offers savings “10-fold higher than anything that’s being contemplated now” in the region, including SEEM.
Michael O’Boyle, Energy Innovation | Energy Innovation Policy & Technology
“There are so many details that need to be filled out that it is a little bit premature to say, ‘the SEEM is x.’ We just don’t know exactly what it’s going to be,” O’Boyle said. “There doesn’t appear to be an agreement to use transmission without those wheeling charges, so … unless there’s an open transmission agreement, there’s still going to be unnecessary costs and a lack of optimization across the region.”
Duke’s Culbert said the SEEM would be much cheaper and faster to create than an RTO, “meaning energy customers in the Southeast would see real benefits much sooner.”
“Participating in that would not prevent any of the companies from participating in an RTO in the future. From our perspective, we don’t see RTOs as the right solution for Duke Energy customers in the Carolinas at this time. We’re currently in the phase of engaging with stakeholders on SEEM and are working through their questions and feedback as we continue to formulate the concept.”
Portland General Electric said Monday that it suffered $127 million in losses from wholesale electricity trades because of recent volatility in the California energy market — a figure that is almost certain to rise.
PGE estimates the losses could undercut its 2020 earnings by as much as 48%.
“Certain PGE personnel entered into a number of energy trades during 2020, with increasing volume accumulating late in the second quarter and into the third quarter, resulting in significant exposure to the company,” CEO Maria Pope said in an email to employees included in a filing with the U.S. Securities and Exchange Commission. “Simply put, these trades were ill conceived.”
“As a result of the convergence of these conditions, the company’s energy portfolio, as of Aug. 24, 2020, has experienced realized losses of $104 million and unrealized, mark-to-market losses of $23 million,” PGE said. “Total third-quarter losses in the portfolio are estimated to be up to $155 million subject to market conditions — although the ultimate amount of losses could exceed that amount.”
PGE on Monday moved quickly to contain potential political damage from the incident, saying it had placed two unnamed staff members on administrative leave pending further review. It also assured customers that it would not seek to recover the losses through increased rates.
PGE wind farm in Eastern Oregon | Sherman County Government
The utility also announced the formation of a special committee consisting of five independent board members to examine the events leading to the losses and review existing procedures and controls. The company has additionally engaged external consultants “to perform a full operational review of our energy supply risk management policies, procedures and personnel,” Pope said.
She also said the company would not be adjusting its 2020 and 2021 capital and operational budgets and assured employees that “we do not anticipate any layoffs as a result of this situation.”
“This situation is not reflective of who we are at our core, and we will learn from the situation and make the necessary changes to ensure this will never happen again,” Pope said.
Black Swan?
While PGE has not disclosed the exact cause of the losses, their sheer size — and the utility’s response — suggests the trading activity leading to the losses fell outside expected norms.
“The way Pope worded it — ‘ill-conceived’ — makes me think it’s something nonstandard,” said a compliance analyst with another Northwest utility who asked not to be named.
The analyst also questioned how traders could build up such exposure under a standard protocol of daily trading and position limits.
“I know we have significant risk controls. But I don’t really know what kind of trading led to the losses,” the analyst said.
Portland-based energy economist Robert McCullough pointed to the potential impact of CAISO’s convergence bidding market on PGE’s trading woes.
“The nature of a relatively unregulated pure derivative — like the convergence market in California — has an enormously asymmetric risk profile. In English, this means that a prudent trade, on rare occasions, can lose 50 times the expected profit,” McCullough said.
He said CAISO’s suspension of convergence bidding during the heat wave — right after the declaration of a Stage 3 emergency — indicates that market losses were high at the time and that manipulation was a possible explanation.
“PGE is hardly a high-risk trading operation,” McCullough said. “A regional utility with substantial assets, they traditionally ‘trade around assets.’ I would suspect that the natural asymmetry of a black swan caught them off guard.”
Even CAISO officials seem aware of the potential for convergence bidding to produce a “black swan” trading event.
During a CAISO stakeholder call Aug. 21 to discuss the recent blackouts, ISO Director of Market Analysis and Forecasting Guillermo Bautista Alderete said convergence bidding can add confusion to the market in times of short supply because convergence bids and physical supply are cleared on the same basis.
When there’s sufficient capacity and supply, “the positions taken in the day-ahead market can be supported. However, when the system is constrained … the position parties can take can result in chaos,” he said.
