Page 1054 – RTO Insider

September 1, 2020

ERCOT Technical Advisory Committee Briefs: Aug. 26, 2020

ERCOT stakeholders last week debated an artifact from the old zonal market, eventually tabling action without a revision request to act on.

Staff brought forward to the Technical Advisory Committee discussion of the “2% rule,” which directs that generating units with shift factors of less than 2% will not be dispatched by the real-time market to respond to transmission overloads. A desk procedure in 2011, shortly after the nodal market went live, clarified the use of the 2% shift factor cutoff in real time.

Under the rule, if a transmission constraint exists for which there are no generator shift factors of at least 2%, operators must verify a mitigation plan or temporary outage action plan exists for the contingency and they are to review the plans with the affected transmission owner. If no plans exist, then the operators are to develop a mitigation plan with ERCOT’s operations support engineer. If no plans have been developed within 30 minutes, the operations desk issues a transmission watch, a step down from an emergency.

ERCOT has conducted several recent analyses on the effects of activating low shift-factor constraints in the economic dispatch engine. Staff found that the effect of activating the constraints is dependent on the system’s topology near the constraint and observed no oscillation in the resource’s output level.

The Congestion Management Working Group has been unable to reach a consensus on whether to eliminate the rule, despite working on the issue since last year.

“It feels like we’ve been talking about it forever,” said CPS Energy’s David Kee, who chairs the Wholesale Market Subcommittee, to which the working group reports.

ERCOT’s Independent Market Monitor, however, believes the 2% rule should be eliminated, with all congestion priced in real time, regardless of generation’s effect.

“Prices matter. The whole market is predicated on that,” said Monitor Director Carrie Bivens in arguing against out-of-market actions. “Whether or not an existing resource can move to resolve the constraint is not relevant to whether it should be priced. We don’t need to define in advance what the response will be. The magic of the market is that it can and does respond to those market signals.”

Bivens said incorporating a price signal for what would be an out-of-market action on hidden congestion would incentivize the market to resolve the issue.

She noted that ERCOT only activates contingency constraints if three thresholds are met: the system is loaded at 98% of the emergency limit; a resource shift factor of 2% or more exists; and a similar constraint is not already activated.

Other markets have lower constraint thresholds, are lowering them or don’t have them at all, Bivens said. MISO’s Independent Market Monitor is urging the RTO to remove its 1.5% threshold; PJM just removed its threshold; and CAISO is discussing a change to its 2% rule, she said.

With an efficient congestion revenue rights (CRR) market, she said, the overall cost to load does not increase. “If the real-time congestion rent goes up, the day-ahead market’s congestion rent will rise and the CRR revenue goes up,” Bivens said.

“This is a pretty significant issue for the market. It’s in the ERCOT procedure manual, but this needs to be documented in a guide procedure,” Morgan Stanley’s Clayton Greer said. “In my view, we’re going to see [the] effective elimination of the 2% rule anyway with all the distributed generation going out on the system. I’d rather just rip the Band-Aid off, let the market see the change and everyone adapt to the change [at the same time].”

Kenan Ögelman, ERCOT’s vice president of commercial operations, said the Monitor “brought up a worthy issue for consideration,” but because the 2% rule doesn’t reside in the protocols or another binding document, options are limited.

“This is something that needs to be resolved to move the issue forward, one way or another,” Ögelman said.

“Maybe it would be cleaner if there was an NPRR [Nodal Protocol revision request],” said Eric Goff, a residential representative in the Consumer segment.

TAC Chair Bob Helton, of ENGIE, said he will discuss the matter offline with Ögelman and TAC Vice Chair Clif Lange, of South Texas Electric Cooperative, and work on a document that stakeholders can vote on.

On that, members were able to reach consensus.

PRS Prioritizes List of Approved RRs

The Protocol Revision Subcommittee (PRS) and ERCOT staff have spent the past few months prioritizing work on approved revision requests to balance resource availability with the flood of changes.

ERCOT’s Troy Anderson said 40 items on the priority list, “an unusual amount,” have yet to be started. That doesn’t take into account RRs from stakeholder groups working on real-time co-optimization, energy storage and distributed generation.

“We’ll be starting on real-time co-optimization, the [Battery Energy Storage Task Force] and [distributed generation] in the very near future,” Anderson said. “We have to be careful not to put those items at risk. This doesn’t mean the remaining items won’t get done. We will seek opportunities for those items when the resources become available or we have the opportunities to work on them.”

Anderson shared with the TAC a graphic that listed more than 70 RRs or other initiatives currently underway or waiting in the wings. ERCOT has a limited number of resources available to work on the backlog.

“We want to ensure we have prioritized the right items to be worked on soonest,” Anderson said.

ERCOT’s 2020 release targets for the more than 70 approved revision requests | *ERCOT*

Committee Passes 3 Change Requests

The TAC approved three revision requests in two roll-call votes.

The first vote paired an NPRR (NPRR984) with an accompanying Other Binding Document request (OBDRR023), both related to emergency response service (ERS) in what Helton dubbed “the Clayton ballot.” Greer, the ballot’s namesake, said during July’s TAC meeting that he would vote against anything related to ERS. True to form, he cast the lone vote against the measures on behalf of Morgan Stanley, but he did side with the majority on behalf of his proxy, EDF Trading’s Kevin Bunch.

NPRR984 changes the number of ERS standard contract terms from three to four per program year to align the terms with typical seasonal conditions and improve ERS’ procurement. OBDRR023 changes ERS’ procurement methodology to match NPRR984’s protocol changes.

In addition, the committee unanimously approved NPRR10 27, which removes gray-boxed language from the protocols related to NPRR702 (Flexible Accounts, Payment of Invoices, and Disposition of Interest on Cash Collateral) following the elimination of prepay accounts.

September 1, 2020

Stakeholders Speak out on FERC CIP Concerns

Responses to FERC’s Notice of Inquiry on potential gaps in NERC’s Critical Infrastructure Protection (CIP) standards reveal widespread reluctance on the part of industry stakeholders toward the commission’s suggestion of enhancing the standards (RM20-12).

FERC issued the NOI in June, citing concerns that the current version of the standards do not adequately address the rapidly evolving landscape of cybersecurity threats. (See FERC Starts Inquiry on CIP Standards.) Specifically, the commission based its questions on a review of the National Institute of Standards and Technology’s (NIST) Cyber Security Framework, with it asking stakeholders whether the standards provide sufficient protection in the fields of cybersecurity risks pertaining to data security; detection of anomalies and events; and mitigation of cybersecurity events.

The commission also asked for comments on the danger of a coordinated cyberattack against geographically distributed targets, and whether FERC should take action to address this threat.

Separate Spheres for NIST, CIP

Responses to the first part of the inquiry were mostly negative, with several commenters objecting to FERC’s comparison of the CIP standards to the NIST framework. For example, the Large Public Power Council and the American Public Power Association pointed out that organizations are supposed to customize the NIST framework to their specific needs. Moreover, the framework is entirely voluntary, making the idea of “compliance” a contradiction.

FERC CIP Concerns — FERC headquarters in D.C. | *FERC*

In a joint comment, Jason Christopher, principal cyber risk adviser for industrial security firm Dragos, and Tim Conway, industrial control systems curriculum director for cybersecurity training organization at the SANS Institute, noted that FERC’s inquiry seems to share themes with a white paper it published at the same time proposing an incentive framework for cybersecurity investments. (See FERC Seeks Comments on Cyber Investment Incentives.)

In particular, they pointed to the paper’s assertion that “the standards development process does not lend itself to addressing rapidly evolving cybersecurity threats” as indicating a crucial misunderstanding of the way the NERC standards and the NIST framework complement each other.

“While this may be an easy soundbite, the truth is more nuanced,” Christopher and Conway said. “The requirements themselves may have issues, but the ability to adapt to new threats is based on applying new and specific technologies or techniques used for compliance — not necessarily in the ability to comply with specific requirements themselves. … The what to achieve, regardless of how a technology may be deployed, is relatively timeless, independent of evolving threats.”

Arguments for Unified Standards

Supporters of the commission’s desire to reform the standards included the U.S. Army Corps of Engineers and the Bureau of Reclamation, which in a joint comment argued that “maintaining a competing set of standards for critical infrastructure” — referring to the CIP standards — is dangerous for grid stability compared to “[leveraging] the comprehensive set of published NIST standards.” The organizations urged FERC to follow the lead of other federal agencies and adopt a regulatory framework that is objective-based, rather than compliance-based.

“The focus should not be on what is wrong with the CIP standards, or how to better align them to NIST, but what is right with the NIST standards and how a convergence on a single set of standards would improve [bulk electric system] resilience and security,” the agencies said.

The New Jersey Board of Public Utilities also stepped forward to back the commission’s comparison of the CIP standards to the NIST framework, citing specific differences between the two structures to bolster the claim that NERC’s standards have serious deficiencies. Examples include the CIP standards’ lack of a mandate for monitoring data in transit for anomalies and continuity of operations, along with the lack of security requirements for low-impact BES cyber systems to match those for high- and medium-impact systems.

Multiple Defenses Against Mass Attacks

The security implications of unaddressed low-impact systems were a significant factor in FERC’s second area of inquiry, concerning coordinated cyberattacks. The commission’s key concern is whether “smaller, geographically distributed generation resources” such as rooftop solar panels and battery storage facilities — classified as low-impact systems — could provide entry points for an attacker, especially given the exclusion of such assets from NERC’s reliability standards.

Responses largely characterized the current standards as sufficient. NERC itself, commenting jointly with the regional entities as the ERO Enterprise, said that it “recognizes the emerging threat of a coordinated cyberattack” and highlighted a number of processes that it said provided an “in-depth approach to risk mitigation.” Among the tools cited was the NERC Alert process, through which the organization provides “concise, actionable information” to the industry, and forums such as the Reliability Issues Steering Committee that identify emerging risks to the BES.

Southern Co. joined NERC’s defense of its standards, asserting that multiple currently effective CIP standards, as well as several more under development, contain adequate controls for “identifying, preventing and mitigating coordinated cyberattacks.” In reference to low-impact cyber systems, Southern acknowledged the potential for harm in leaving them unaddressed but recommended that future CIP requirements aimed at securing such assets take aim at “the external connectivity that connects them together” rather than the systems themselves.

September 1, 2020

FERC Affirms its Jurisdiction over Tri-State G&T

FERC late last week affirmed that it has exclusive jurisdiction over Tri-State Generation and Transmission Association’s rates and member exit charges, one in a flurry of orders Friday related to the Colorado-based cooperative (EL20-16).

The order pre-empts the Colorado Public Utilities Commission’s jurisdiction over Tri-State and would negate an exit-fee methodology proposed by co-op members United Power and La Plata Electric Association (LPEA). FERC in June accepted Tri-State’s proposed contract-termination payment methodology and set hearing and settlement judge procedures, but a Colorado administrative law judge in July Colo. ALJ Proposes $235M Exit Fee for United Power.)

Tri-State G&T — Tri-State’s headquarters in Westminster, Colo. | *Ludvik Electric*

Tri-State became FERC-jurisdictional in March, when the commission recognized its status following last year’s addition of MIECO, a wholesale energy services company that provides natural gas to the co-op, as its first non-utility member. (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 16, 2020.)

In its order last week, the commission said that, after “further consideration,” it was modifying the March order to find that Tri-State’s assessment of an exit charge “constitutes a commission-jurisdictional rate subject to our exclusive jurisdiction.”

FERC concluded that, as a result, the Colorado PUC’s jurisdiction over complaints regarding Tri-State’s exit charges “is pre-empted as of Sept. 3, 2019,” the date the co-op admitted MIECO.

“This is a monumental decision for our members and Tri-State, and allows us all to move forward in our clean energy transition with much more certainty,” Tri-State CEO Duane Highley said in a statement.

Highley said FERC was the “appropriate regulatory commission to consider these important issues.”

“At the FERC,” he said, “each of our members, no matter in which state they are located, can participate fully, have a voice and be treated equally on wholesale contract and rate matters.”

The commission also reaffirmed that Tri-State’s addition of new members was lawful under the Federal Power Act. It rejected United’s and LPEA’s claims that adding MIECO violated the law.

In a separate order, FERC also dismissed the members’ rehearing requests (ER20-1559). It also sustained Tri-State’s filed rate schedules in additional rehearing requests by United and the Sierra Club (ER20-689, et al. and ER20-676, et al.).

FERC to Investigate Tri-State Policies

FERC also found that Tri-State’s use of fixed-cost equalization in its policy and rate is consistent with federal law and agreed with the cooperative’s use of net metering for energy storage projects, rejecting United’s and Sierra’s claims and setting the matters for hearing (EL20-66).

The commission said Tri-State’s policy reflects “the cost consequences that follow from the choice made by [qualified-facility] sellers to sell their power directly to Tri-State’s utility members rather than to Tri-State under the transmission option.” Referring to precedent set by Order 69, FERC said fixed-cost equalization “is simply a billing mechanism for implementing the avoided-cost pricing for full-requirements contracts.”

While FERC held the settlement judge procedures in abeyance, it also opened FPA Section 206 investigations into whether two Tri-State board policies, a rate schedule and the member project contracts are just and reasonable. It said the policies, rate schedule and contracts raised issues of material fact that cannot be resolved based on the record before it.

One policy describes each member’s option under its wholesale electric service contract to use self-owned or -controlled distributed or renewable generation resources to serve up to 5% of its annual requirement. The second addresses Tri-State’s purchases of power from QFs and sets the terms for Tri-State’s recovery of lost revenue (fixed-cost equalization) when a utility member’s QF power purchases and its non-QF self-supply power exceed the 5% threshold.

The rate schedule in question sets forth the methodology for calculating billing adjustments due to Tri-State under the two board policies.

August 31, 2020

MISO Enacts Rolling Blackouts in Laura Aftermath

Hurricane Laura’s lashing of south Louisiana and southeast Texas on Thursday led MISO to implement last-resort rolling power outages in an Entergy load pocket during restoration efforts.

MISO said its southern member companies are reporting widespread destruction following the storm. Citing transmission system damage and generation outages, MISO directed Entergy to begin periodic power outages just before noon ET in the Atchafalaya Basin load pocket straddling Texas and Louisiana.

It’s unclear how many customers were affected. MISO also cited Laura’s “unpredictable load patterns” as another reason for the load shedding. Entergy was asked to report its load-shed activities through the nonpublic MISO Communications System.

“MISO has implemented emergency operating procedures to address reliability in a load pocket of the region that experienced significant damage from the hurricane,” System Operations Executive Director Renuka Chatterjee said in a statement. “While we continue to support our members’ restoration efforts in the South Region, we maintain our focus on ensuring grid reliability across the entire footprint.”

The RTO said it “escalated to the most severe step in its emergency actions in order to avoid a larger power outage on the bulk electric system in the affected areas.” Periodic load shedding to stymie a more severe blackout was in effect for about 12 hours; the maximum generation emergency was lifted around 10:55 p.m. ET.

MISO has never shed firm load because of a capacity emergency since it began running its market in the new millennium, though it has shed local load during transmission outages. This appears to be the first time that MISO has shed load because of a capacity shortfall and transmission outages. The grid operator called it a “highly unusual action.”

During the blackouts, energy was priced at MISO’s $3,500/MWh value of lost load. The grid operator has been in discussions with its stakeholders to raise the current price limit, saying it could be undervaluing involuntary load sheds. (See MISO Revisits Scarcity Pricing Rethink.)

Entergy appealed to its Texas customers that they pare down their electricity usage.

“The unusual circumstance is the result of extensive damage to Entergy’s transmission system caused by Hurricane Laura in east Texas and west Louisiana and the anticipated high demand for electricity due to high temperatures. Hurricane Laura damaged conductors [and] wooden and steel towers in key transmission lines needed to bring electrical power from the east,” the utility said.

Entergy trucks heading out in the aftermath of Hurricane Laura | *Entergy*

Entergy on Thursday reported more than 540,000 customers without power in its service territory. The utility said it convened a 16,750-strong restoration crew, more than double what it originally pledged before the storm. By Monday, the utility said it restored power to about 115,000 Louisiana customers.

In the height of the storm’s wake, nearly 1 million total customers were without power, according to the Edison Electric Institute. Restoration crews were able to half that number over the weekend, with more than 29,000 workers from at least 29 states, D.C. and Canada assisting the region in restoration efforts, the nonprofit reported.

Entergy said its hardest-hit areas are the Lake Charles, Calcasieu and Cameron parishes, which collectively account for 5,648 poles in need of repairs, 10,037 spans of inoperable wire and 2,484 mangled transformers.

While MISO as a rule doesn’t reveal what member assets are offline from outages, Montgomery County, Texas, County Judge Mark Keough said on Facebook late Thursday that Entergy Texas successfully re-energized its 500-kV Hartburg line.

“Please watch energy consumption for the next few days to ensure we are not putting pressure on the grid as they have to balance the load,” Keough said in his post.

Keough also said Entergy was restoring power to a generator on Thursday and continued to make transmission repairs. He said Entergy was “confident” that its restoration work will avoid the need for further load shed.

MISO extended by a day on Thursday a conservative operations declaration issued ahead of the storm. (See Gulf Grid Operators, Utilities Shore up for Laura.) The RTO also said additional declarations and alerts may be issued in the aftermath.

Compounding matters, MISO said it also experienced “challenging capacity availability” in its North and Central regions Thursday because of a heat wave. The bleak capacity picture led the RTO to issu e a hot-weather alert for the two regions while control room operators contended with a ravaged MISO South.

“We continue to work with our member companies and partner RTOs like SPP and ERCOT toward a speedy recovery,” South Region Executive Director Daryl Brown said. “Mutual assistance and collaboration before and during the storm as well as throughout restoration are necessary to maintain our focus during times of crisis.”

August 30, 2020

Theories Abound over California Blackouts Cause

Observers last week cited dependence on uncontracted imports, underperformance of natural gas and wind, and market manipulation as possible causes of California’s first rolling blackouts in nearly two decades, as a state regulator cautioned against drawing premature conclusions.

“It is not helpful to speculate on the root cause until we have a chance to do a complete analysis on the factors leading to the outages,” Edward Randolph, director of the California Public Utilities Commission’s Energy Division, said Thursday during a commission meeting.

California Blackouts — Edward Randolph, CPUC | © *RTO Insider*

“Within weeks,” the CPUC, CAISO and the California Energy Commission will release a joint initial report on causes, Randolph said. The report will focus on demand forecasts, the state’s resource adequacy process, what resources were scheduled to meet demand during the emergency and whether those resources were actually available.

A second deeper dive will examine factors that will take more time and data to fully understand, he said.

“At this point, we know some basic facts about why there were outages on [Aug. 14 and 15], and why the grid was too close to the edge on [Aug. 17 and 18] than it ever should be,” Randolph said. “The short of it is there was not enough available supply to meet demand. Based on our planning process, there should have been.”

Randolph called out recent analyses and news reports that attempted to identify root causes of blackouts. Some relied on actual data, while others were based on speculation that could be wrong, he said.

Contracted Imports Vital

A report from advisory firm ICF International leans heavily on available data. It cited CAISO’s dependence on imported energy as a leading cause of the blackouts and calls on the ISO and state regulators to reduce the state’s reliance on uncontracted imports for RA. CAISO and the commissions offered a similar view in an Aug. 19 letter to Gov. Gavin Newsom. (See CAISO Provides More Details on Blackouts.)

The report lays out discrepancies between CAISO’s RA assessment for this summer and actual system performance Aug. 14-15, when the ISO declared Stage 3 emergencies prompting the blackouts.

The analysis shows that natural gas, wind and imports underperformed sharply both days from 6 to 8 p.m. — just as declining solar output and continuing high demand from air conditioning use during a triple-digit heat wave required sharp ramps to cover rising net load.

At 6 p.m. on Aug. 15, for example, natural gas generation came in at 4,369 MW — or 15% — short of the RA assessment, while wind lagged 661 MW, or 25%. At the same time, imports fell short of expectations by 5,672 MW, or 56%.

The authors of the ICF report noted that imports account for 10 to 12% of California’s total RA procurement, and they applauded the move last month by the CPUC to require that non-resource-specific imports that count toward a load-serving entity’s RA requirements be reinforced by contracts. The CPUC also required the imports to self-schedule into CAISO’s day-ahead and real-time markets during availability assessment hours — the hours of greatest need on the system.

However, ICF said there is a mismatch between the CPUC’s mandates and the figures used in reliability planning. The state continues “to include import resources that are not backed up by RA contracts (in addition to RA contracted imports) to meet its peak demand in its resource adequacy planning assessment,” the report said.

“According to statistics released by CPUC, jurisdictional LSEs only have around 5.8 GW of contracted import RA capacity, [yet] … CAISO’s 2020 summer assessment assumes availability of imports up to 9.5 GW during constrained hours,” it said.

The ICF report pointed out that CAISO’s August RA assessment assumed 4.9 GW of uncontracted imports alone would be available during peak hours, but instead just 5 GW of total imports were delivered to CAISO during the 6 p.m. interval on Aug. 16, suggesting that most of the uncontracted supply didn’t materialize. “The reliance on uncommitted import resources brings additional uncertainties to a grid with a large amount of intermittent internal resources and brings challenges to system operation under extreme events,” the report said.

It also encouraged California to step up preparations for supply-driven system fluctuations as it brings on increasing volumes of variable renewable resources while retiring thermal units, a development that will reduce the margin for error in RA as demand also becomes more variable.

“California’s RA procurement process should consider potential hourly variations in resource deliverability and prepare for stressful scenarios,” ICF said.

It said it was encouraged by the latest revised straw proposal in CAISO’s RA enhancements initiative, which proposed adopting an RA construct based on unforced capacity — the percentage of resource capacity available after outages are considered. The proposal also considers increasing LSE planning reserve margins from the current level of 15% to 20% or higher.

“The proposal, if implemented, will be helpful in pushing the LSEs to secure additional resources to prepare for emergency conditions,” ICF contended.

Contrary Take

Energy economist Robert McCullough offered a contrarian view on the blackouts. He raised the possibility that CAISO’s flawed market design or even market manipulation caused the outages.

A longtime observer of California’s electricity sector, McCullough pointed to CAISO’s highly complex convergence bidding market, a mechanism that allows market participants to hedge their physical positions and limit exposure to day-ahead and real-time price differentials.

The bid is a purely financial one, implying no obligation to take or deliver electricity. Instead, a market participant buys or sells “virtual” energy in the day-ahead market, a position required to be automatically liquidated in the opposite direction in real time. The objective is to make day-ahead and real-time prices converge as much as possible.

As California’s recent emergency episode unfolded, CAISO announced it would temporarily suspend day-ahead convergence bidding beginning Aug. 17 because the practice was “detrimentally affecting the ISO’s ability to maintain reliable grid operations.” CAISO later pointed to the difficulty of distinguishing how much actual supply was available on the system with physical and virtual bids mingling.

McCullough suggested there might have been a connection between convergence bidding and generation outages during the system emergencies. The ISO had initially explained the crisis as a demand-driven outcome of the heat wave, he said.

“As we now know, the wave of [resource] outages was probably a more important factor. This does suggest market manipulation.”

California’s 2000/01 energy crisis “ended abruptly” when FERC finally imposed price controls, he noted.

“On the day the controls went in place, forced outages ended and prices never reached the price cap,” McCullough said.

“The nature of convergence bidding rewards a similar exploit,” he said. “If you own a unit at a sensitive location, you can schedule an outage and create a price spike. Of course, revenues from that plant would be zero. However, convergence bids are purely financial. This means that the plant owner could both reduce output and make a profit in the convergence market.”

McCullough has previously told RTO Insider that convergence bidding doesn’t even require manipulation to enrich some market participants at the expense of other participants, “just a willingness to gamble on the ISO’s computer systems.”

“Past experience has tended to make this less of a gamble than you might think, since critical information is often learned by specific market participants and then used to advantage,” he said. (See CAISO Blames Blackouts on Inadequate Resources, CPUC.)

Oregon utility Portland General Electric has yet to disclose the precise cause of its staggering trading losses related to recent market volatility in California, but McCullough speculates that convergence bidding could have played a role by creating a “black swan” trading event that left PGE heavily exposed. (See related story, PGE Traders Burned by California Heat Wave.)

McCullough said he hopes Gov. Newsom or Attorney General Xavier Becerra will investigate alternative possibilities behind the blackouts before moving to increase the state’s 15% reserve margin, as ICF and others have urged.

“Collecting ratepayer dollars to offset possible mismanagement and market manipulation is a bad idea, especially since these dollars are needed for system hardening,” he said.

Convergence Breakdown

A question about CAISO’s decision to suspend convergence bidding arose during a biweekly market update call Thursday.

Seth Cochran, manager of market affairs and origination at trading firm DC Energy, said it was still unclear why the ISO suspended bidding when it could have used its day-ahead residual unit commitment (RUC) process to count available units, examine their schedules and make curtailments.

CAISO’s RUC process is designed to procure additional generation needed when the day-ahead market fails to clear enough resources to meet forecasts.

“I wasn’t sure why that process couldn’t be used, and why you had to resort to suspending convergence bidding,” Cochran said. “I would note that the markets didn’t look well converged, and that seems to be a market dysfunction, not something that should impede reliability necessarily.”

CAISO Director of Market Analysis and Forecasting Guillermo Bautista Alderete responded that when the system has sufficient available supply, operators can dip into the RUC market to cover load and back up convergence bids with physical supply.

“The problem is when you don’t have enough physical supply to cover the demand,” Bautista Alderete said. “In this case, the convergence bids are going to be backing up potential exports and load that later on we know won’t be supported and then we have to start curtailing those in the real-time.

“This is a problem. We have to have physical supply enough to cover physical demand and the exports,” he said.

During the same call, Rahul Kalaskar, the ISO’s manager of market validation and analysis, provided an operational rundown of the emergency events.

High demand during the heat wave created congestion on the transmission lines comprising the SP-26 path between Northern and Southern California, creating price separation between the two regions, Kalaskar said. Higher demand in Southern California drove up prices, a situation exacerbated by a shortage of imports because of correspondingly higher demand in neighboring states, he said.

The heat wave also created a scarcity of ancillary services, particularly non-spinning reserves, Kalaskar said. A CAISO market notice issued Friday showed consistently high levels of ancillary service scarcity during the 7 and 8 p.m. delivery periods over Aug. 14-18, with non-spinning reserve shortages peaking around 1,000 MW — or 75% of requirements — on Aug. 18.

“The non-spin reserves scarcity was essentially because of the fact that some of the resources that received a non-spin award in the day-ahead market were committed in real time to provide energy,” Kalaskar explained.

Kalaskar noted the calm after the storm.

“For the period of Aug. 17 and 18, we were facing higher loads in the real-time, or somewhere around 50,000 MW, but the loads came in much lower on these days, so that’s why the real-time events were much milder [compared] to what we saw on Aug. 14 and 15,” Kalaskar said.

During Thursday’s CPUC meeting, Director Randolph said CAISO came close to calling for more outages over Aug. 17-18 but didn’t have to thanks to conservation encouragement and efforts by the governor’s office, state agencies, utilities, community choice aggregators, large and small customers, and customers using backup batteries and generation to support the grid.

“Thanks to massive efforts … California was able to dramatically reduce overall demand and bring more generation into the mix to avoid more outages,” he said.

August 30, 2020

Texas Escapes Disaster, PUC Ends COVID Program

Texas regulators last week approved a timeline for winding down its pandemic relief program as the state apparently escaped significant damage from Hurricane Laura.

The Public Utility Commission met briefly in an open session Thursday, the morning after the hurricane swept through the Texas-Louisiana border area.

The storm left 125,000 Texas customers without power, in PUC Chair DeAnn Walker’s estimation. “For this level of a storm, that’s astounding,” she said.

By Saturday morning, Entergy Texas was reporting more than 73,000 outages, mostly in southeast Texas.

The commission approved an order that formally winds down the state’s Electricity Relief Program (ERP), which has been providing customer protection from disconnection for nonpayment because of the COVID-19 pandemic since late March (50664). (See Texas PUC to End COVID Relief Program.)

Texas PUC COVID-19 — PUC Chair DeAnn Walker calls the open meeting to order. | *Texas PUC*

The ERP was designed to prevent disconnections of those who lost jobs because of the pandemic. More than 595,000 households are currently participating in the program, which has provided more than $30 million in bill payment assistance.

Under the order, the program will stop taking enrollments on Monday. Disconnections for ERP enrollees may resume on Oct. 1, provided they have received at least 10 days advance notice, but not more than 30 days.

“This has been an unusually tough time for our state, and I am proud of our team for managing the details of a program that has protected so many Texans during a difficult time,” Walker said. “I hope we never encounter a similar challenge in the future.”

Texas has reported 622,496 COVID-19 cases and 12,526 deaths as of Friday.

SPS Rate Request Halved to $73.2M

The commission signed off on an unopposed settlement between Southwestern Public Service and other parties that allows the Xcel Energy subsidiary to raise its base rate by $73.2 million a year (49831).

The parties agreed to a “black-box settlement” — with a revenue total but no specific return on equity — of $88 million in base-rate revenues for SPS’ Texas retail jurisdiction. They also agreed to setting the utility’s transmission cost recovery factor to zero, resulting in the net impact of $73.2 million, effective Sept. 12, 2019.

SPS originally asked for an overall increase of $141.3 million/year in its request filed last year. It later reduced that amount to $129.7 million/year.

Parties to the agreement with SPS included PUC staff, the U.S. Department of Energy, Texas Industrial Energy Consumers, the Office of Public Utility Counsel, the International Brotherhood of Electrical Workers Local Union 602 and the Alliance of Xcel Municipalities.

In other actions, the PUC:

approved a settlement agreement that allows Southwestern Electric Power Co. to recover $5.4 million in 2018 rate-case expenses through a rider (47141); and
slapped retail electric provider Our Energy with a $30,000 administrative fee for not responding to informal customer complaints in a timely fashion (50983). The commission has now assessed more than $3 million in penalties during its financial year, which ends Monday.

August 30, 2020January 15, 2025

CAISO Finalizes ESDER Phase 4 Proposal

CAISO on Thursday presented its final proposal in the fourth and last phase of its five-year effort to make it easier for energy storage and distributed energy resources (ESDER) to participate in its markets.

The ESDER initiative includes rooftop solar, energy storage, plug-in electric vehicles and demand response. (See CAISO Eases Rules for Energy Storage, DERs.)

DR is seen as an increasingly important part of California’s resource adequacy programs and played a role in CAISO’s efforts to reduce electricity use during rolling blackouts of Aug. 14-15 and the strained grid conditions of Aug. 17-18. (See CAISO Provides More Details on Blackouts.)

“As we move into the future, California will rely more heavily on variable and availability-limited resources as we move to decarbonize the grid,” Lauren Carr, a CAISO infrastructure and regulatory policy specialist, said during Thursday’s stakeholder call and presentation. “It’s critical to assess the ability of preferred resources to displace both capacity and energy provided by traditional thermal [generation].”

The ESDER Phase 4 final proposal includes an informational section that discusses a new approach to predicting the capacity of variable-output DR resources. The ISO defines a variable-output DR resource as one “whose maximum output can vary over the course of a day, month or season due to production schedules, duty cycles, availability, seasonality, temperature, occupancy, etc.”

Banks of utility scale battery storage | Southern California Edison

“For instance, certain demand response resources’ output may vary with weather, like an AC cycling demand response program that can reduce more load on a hot day, when air-conditioner use is high, versus on a moderate day, when air-conditioner use is low,” the ISO said in its plan.

“When a variable-output demand response resource provides resource adequacy capacity in the year-ahead or month-ahead time frame, depending on conditions, the resource may be unable to deliver its full stated resource adequacy capacity in the day-ahead or real-time given its variable nature.”

CAISO contracted with Energy and Environmental Economics to develop a way to evaluate the resource adequacy value of DR using effective load-carrying capability (ELCC), which evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources. A resource that contributes a significant level of capacity during high-risk hours will have a higher capacity value than a resource that delivers the same capacity only during low-risk hours.

The California Public Utilities Commission currently uses ELCC to determine the qualifying capacity of wind and solar resources, but it has not been used to assess variable-output DR. CAISO said the method could be used by local regulatory authorities to anticipate the true contributions of such resources.

In addition, the ESDER 4 final proposal addresses a state-of-charge biddable parameter for storage resources; streamlines market participation agreements for non-generator resources; applies market power mitigation to storage resources; and sets a maximum daily run time parameter for DR.

Updates to the final plan include details on the market application of the end-of-hour state-of-charge, clarifying when it is recognized within the short-term unit commitment process and how its use by a resource may impact its resource adequacy valuation.

Comments on the final proposal are due Sept. 10. It is scheduled for an advisory vote by the Western Energy Imbalance Market Governing Body on Sept. 16 and a vote by the CAISO Board of Governors on Sept. 30. FERC must then approve the ISO’s Tariff changes.

CAISO said the initiative will apply to EIM participants by changing the non-generator resource and proxy demand resource model, but there are no changes specific to EIM balancing authority areas.

August 30, 2020

FERC Defends Ruling on ISO-NE Winter Program Cost

FERC on Thursday defended its April ruling approving bidding results in ISO-NE’s 2013/14 Winter Reliability Program as just and reasonable, expanding on its reasoning in response to a rehearing request (ER13-2266-005).

TransCanada Power Marketing’s request was automatically rejected when the commission failed to act on it within 30 days. FERC’s April order was prompted by a D.C. Circuit Court of Appeals ruling in December 2015 that directed the commission to provide additional justification for approving the rates. (See FERC Reaffirms ISO-NE Winter Program Cost.)

TransCanada had argued that ISO-NE’s pay-as-bid auction resulted in excessive costs because resources were incented to raise their bid prices knowing they would probably be accepted, but the commission ruled that the RTO’s Internal Market Monitor’s cost-based supply curve and a 25% adder used in the analysis were reasonable.

ISO-NE’s program procured reliability service from resources providing demand response and generators able to run on oil — a response to limited natural gas supplies that can leave gas-fired generators without fuel during peak winter heating demand.

ISO-NE Winter Program Cost — ISO-NE and its Internal Market Monitor calculated different expected marginal bids for the Winter Reliability Program because the RTO assumed procurement of 2.25 million MWh and the Monitor assumed the purchase of only 1.95 million MWh. | *FERC*

In requesting rehearing, TransCanada claimed that the “only support” for the 25% upward adjustment was that the suppliers were “likely to adjust their bid prices upward to compensate” for their lack of knowledge regarding how other suppliers would bid in the market.

“This is incorrect,” the commission responded, saying it also considered analysis submitted by ISO-NE and its Monitor that included a cost-based offer curve (i.e., supply curve) that intersected with an expected procurement of 2.25 million MWh at a price of $24.86/MWh-month. “This adjustment revealed an expected clearing price of $31.08/MWh per month. Given that no accepted bids from the auction exceeded that price, the commission concluded that the accepted bids were reasonable.”

TransCanada also asserted that ISO-NE did not seek commission approval to administer the program as a competitive “oil inventory services” market, and that the commission failed to make an ex ante finding of the absence of market power.

“TransCanada’s attempt to invoke the commission’s market-based rate regulations in the instant proceeding is unavailing because the Winter Reliability Program does not fall within the rubric of the commission’s market-based rate program, and, contrary to TransCanada’s arguments, our use of a market-based paradigm to review the bids did not convert the bids and awards into transactions under our market-based rate program,” FERC said.

This case instead involved FERC’s analysis of the RTO’s bid and auction results from a one-time process created for the purpose of maintaining reliability during the 2013-2014 winter season, the commission said.

“Finally, we continue to find that a market-based analysis of the auction results is appropriate and is not indicative of any ‘post hoc rationalization,’ as TransCanada alleges,” the commission said.

August 30, 2020

MISO in Final Stretch of $4B MTEP 20

MISO is putting the final touches on its most expensive annual transmission investment package yet after a final round of subregional planning meetings last week.

The RTO’s 2020 Transmission Expansion Plan (MTEP 20) now contains 519 new projects costing slightly more than $4 billion. Last year’s 480-project portfolio was just shy of $4 billion.

The Planning Advisory Committee will vote on the package during its Sept. 23 meeting. If approved, the Board of Directors’ System Planning Committee will then vote on it during an Oct. 26 meeting, with the full board deciding on final approval during its December meeting.

MISO Executive Director of System Planning Aubrey Johnson last month said MTEP 20 investment closely resembles that of MTEP 19.

The grid operator said the majority of MTEP 20 projects are line and substation work and will go into service within four years. Assuming the portfolio’s approval, MISO members will spend $684 million in baseline reliability projects (BRPs) and another $538 million on generator interconnection projects. Ameren alone proposed 156 new projects costing $1.6 billion for reliability and interconnection reasons in Illinois and Missouri and to replace aging equipment and accommodate load growth. Ameren has embarked on a $7.6 billion, five-year grid modernization plan in Missouri.

MISO MTEP — Draft breakdown of MTEP 20 spending by region | *MISO*

MTEP 20 doesn’t yet contain any market efficiency projects.

Speaking during a West subregional planning teleconference Thursday, Senior Expansion Planning Engineer James Slegers said MISO tested four BRPs that were rated 230 kV and higher and cost at least $5 million. The projects — in central Illinois, southeast Michigan, eastern Missouri and eastern Louisiana — didn’t show enough economic benefits, Slegers said.

Project investment in MISO South will be less this year than in 2019. The region will pick up $530 million worth of 46 new projects. Most of the investment — $309 million — is to accommodate load growth. Last year, MISO South was on the receiving end of 71 new projects costing about $811 million.

Entergy Cancels MTEP 16 Project

Entergy Louisiana, meanwhile, will withdraw a major project near New Orleans originally approved in MTEP 16. The utility announced that the nearly $74 million, 27-mile, 230-kV Waterford-to-Churchill transmission line no longer demonstrates the benefits it once did. Over four years, the benefit-cost ratio dropped from 2.3 to about 0.2, according to the company.

The line has not entered the construction phase. It was originally estimated to be in service by early 2022.

Entergy has since built new projects in the area that have eased congestion and eroded the original project’s benefits, MISO Senior Manager of Expansion Planning Edin Habibovic said during an Aug. 25 South subregional planning meeting. He also said Entergy found cost increases after more detailed project scoping.

“We are OK with removing this project from the economic point of view, the reliability point of view [and] the impact of any other processes,” Habibovic said. “If the load didn’t materialize, then obviously there’s no need for this project.”

August 30, 2020

LS Power Again Seeks MISO Cost Allocation Change

Competitive transmission developer LS Power on Thursday made a three-pronged attack on MISO’s cost-allocation structure with a trio of FERC filings against the rules.

Two of LS Power’s requests for rehearing pushed back against MISO’s contention that sub-230-kV projects do not demonstrate enough benefits to share costs regionally, while a third decries the RTO’s local allocation for baseline reliability projects.

LS Power said MISO’s use of an “arbitrary” 230-kV threshold for its market efficiency project (MEP) category, a class of projects that enjoy regionwide allocation, is wrong. The RTO gained FERC approval to use the 230-kV cutoff in late July; the commission’s acceptance also denied LS Power’s entreaty for a 100-kV threshold for MEPs (ER20-1723). (See MISO Cost Allocation Plan Wins OK on 3rd Round.)

The company sought rehearing on both its 100-kV petition and FERC’s cost-allocation order. It said relegating economically beneficial sub-230-kV projects to allocation only at the transmission-pricing-zone level does “real harm” and argued that projects as low as 100 kV have proven regional benefits.

“The evidence presented in the proceeding leaves no doubt that a 230-kV minimum voltage threshold for market efficiency projects will preclude from regional consideration sub-230-kV projects that have consumer and regional benefits,” LS Power said. “The commission’s acceptance of the limited expansion of the MEP category seems to conclude that lowering the voltage threshold to 230 kV would be ‘good enough’ and shirked its obligation under [Federal Power Act] Section 205 to fully evaluate whether a 230-kV minimum voltage threshold actually results in a just and reasonable rate in every case.”

The company said FERC dismissed its request for a 100-kV threshold “in the face of substantial evidence” that lines under 230 kV deliver economic advantages.

“[FERC’s] decision ignored evidence that MISO currently identifies the regional benefits of economic projects operating between 100 kV and 230 kV,” LS Power said.

The company also argued for a second time that MISO should devise a better allocation for its baseline reliability projects that identifies beneficiaries beyond transmission pricing zones.

Early this year, LS Power signed on to a complaint against MISO’s current location-based, cost-allocation methodology for baseline reliability projects (BRPs), saying it doesn’t comport with the commission’s principle that transmission projects’ beneficiaries should pay for them (EL20-19). FERC said the complaint failed to show that MISO’s current approach was unfair and said any spillover benefits were modest. (See FERC Upholds Cost Allocation on MISO BRPs.)

MISO allocates BRP costs only to local transmission zones where project facilities are physically located; costs are recovered by the transmission owners developing the projects.

LS Power said FERC was “presented with unrebutted evidence” that the current allocation methodology can result in unjust and unreasonable rates, and chose to ignore it.

“The commission’s complaint denial order appears to be based on the unsupported premise that the commission’s obligation to ensure just and reasonable rates is a ‘most of the time’ standard. There is no precedent to support such a laissez-faire approach to the commission’s obligations under the Federal Power Act,” LS Power wrote.

The company said FERC, in making its decision, instead “reverted to statistics that suggest that the current location-based, nonquantitative methodology gets cost allocation mostly right, most of the time, and therefore meets the commission’s statutory standard of establishing just and reasonable rates.”

LS Power said far from modest spillover benefits, BRPs passed benefits to outside zones 28 to 100% of the time. It again pressed for an allocation based on a line-outage distribution factor methodology.