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 issue 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.”
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.
“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.
This chart shows the wide discrepancy between CAISO’s RA assessment for August and the actual performance during key periods of the system emergency. | ICF
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.
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.
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.
FERC on Friday accepted settlements between Texas Reliability Entity and Electric Transmission Texas (ETT), as well as with at least one unnamed entity in the Texas Interconnection. It also approved a settlement between WECC and an unnamed entity in the Western Interconnection for violations of NERC reliability standards (NP20-20).
NERC submitted the settlements July 30 in a spreadsheet Notice of Penalty (NOP); FERC indicated in a notice that it would not review the filing, leaving the penalties intact.
ETT Admits Rating Missteps
Texas RE’s settlement with ETT — the only one in the spreadsheet NOP in which the registered entity was identified — involved a violation of FAC-008-3, which covers entities’ facility ratings.
NERC regional entities | NERC
ETT self-reported the violation in December 2018, saying that one of its affiliates had discovered incorrect ratings in five transmission segments during an “extent of condition” review for an unrelated instance of noncompliance. The misratings had been in effect since May 2016, when the first of the affected segments was placed into service, and ended in October 2018, when ETT revised the ratings.
Texas RE attributed the violations to “an insufficient process for compliance with FAC-008-3.” Specifically, for four of the transmission segments, ETT failed to identify the most limiting series element (MLSE), while in the remaining segment, the utility had adopted a new facility rating methodology but neglected to revise the line’s rating.
ETT’s mitigation measures included another extent-of-condition review to document any additional revised facility ratings. The utility also began conducting quarterly reviews on randomly selected facility ratings and revised its FAC-008-3 compliance processes, including a process for identifying the MLSE for transmission assets.
In assessing its penalty, Texas RE decided not to give ETT mitigating credit for self-reporting the violation, as the review that led to the discovery was itself a result of noncompliance. However, the regional entity also acknowledged that ETT addressed the issue quickly and thoroughly, and that its affiliate had already been assessed a penalty for the previous infraction. As a result, Texas RE determined that no monetary penalty would be required.
Multiple CIP Violations in Texas, West
The remaining six settlements in the spreadsheet NOP — five involved Texas RE and one WECC — relate to violations of NERC’s Critical Infrastructure Protection (CIP) standards and thus have had significant amounts of information removed, including the names of violating entities.
Texas RE’s first entry in this series, for which no monetary penalty was assessed, was prompted by a violation of CIP-002-5.1 (bulk electric system cyber system configuration). According to the RE, the entity incorrectly identified at least one of its cyber systems as low-impact because the third party that reviewed the system in 2015 only considered “normal conditions”; a second review in 2017 by another third party found that the system should be considered medium-impact.
While Texas RE acknowledged that the violation posed a risk to the grid, it described the risk level as “moderate,” rather than substantial or severe. The RE also observed that the entity had reclassified the systems in question as medium-impact once it was informed of the oversight and developed its own “comprehensive evaluation methodology” for categorizing its cyber assets.
In addition, the fact that the entity conducted another review with a different third party just two years after the last one spoke to its strong compliance culture, Texas RE said. These factors led the RE to conclude that no further penalty was needed.
Unnamed Entity Hit for Cyber Problems
Texas RE’s next four settlements involved violations of CIP-007-6 (systems security management) and CIP-010-2 (configuration change management and vulnerability assessments), all apparently by the same entity. All violations were self-reported in July 2017.
The CIP-007-6 violations, which accounted for three of the four settlements, stemmed from a number of issues. In one instance, the entity had failed to evaluate or apply multiple security patches. According to the standard, the patches should have been reviewed within 35 days, but in some cases, they went unreviewed for more than a year. Texas RE identified the root cause of the noncompliance as a combination of inadequate patching procedure, changes in personnel responsible for patch management and fumbled planning for the transition to CIP-007-6 in July 2016.
Another violation of the same standard arose from the enabling of an unneeded listening port on one of the entity’s cyber assets, potentially providing an entry point for unauthorized personnel. In the third case, the entity found that it was not properly recording logs of malicious code on its cyber assets in accordance with the standard. The root cause of this violation was determined to be “insufficient procedures … to ensure the entity would be compliant” with CIP-007-6.
For the CIP-010-2 violation, the entity reported to Texas RE that it had failed to include the standard in its baseline documentation for some of its cyber assets because of the use of change-management processes that did not include the standard, either because of age or oversight. The baseline documentation was updated in July 2017.
In assessing the penalty for these violations, Texas RE balanced the number of infringements — and the fact they were only reported when the entity was informed of an upcoming compliance audit — with the entity’s lack of previous violations. Another significant factor was the fact that “the issue was part of a noncompliance spanning multiple regions and registered entities,” meaning that one of the entity’s affiliates had already been assessed a penalty for the same violation. Texas RE considered this an acceptable reason to reduce the total penalty to $36,750.
WECC Makes a Cybersecurity Example
The final settlement in the spreadsheet NOP involved a violation of CIP-011-2 (information protection) by an unnamed entity in the Western Interconnection. The entity reported the issue to WECC via the self-logging program in October 2018.
According to the entity’s report, a contractor on one of its projects forwarded documents containing bulk electric system cyber system information (BCSI) to a personal email account on five separate occasions, in breach of the entity’s procedure for protecting and securely handling BCSI. The violation ended in July 2018 when the contractor removed all BCSI information from their personal email account.
To mitigate the violation, the entity terminated the contractor’s physical and electronic access authorization after recovering all data and ensuring that the contractor had purged the data. It also reminded all other contractors associated with the project about the information security policies.
WECC found that the violation posed a minimal risk: While the information involved could have been damaging if disclosed to a malicious actor, the RE determined that the entity had exercised sufficient diligence in confirming that the emails had not been forwarded to any other individuals, and an investigation found that the contractor had not mishandled any other information. Furthermore, the BCSI in question was surrounded by noncritical data and thus unlikely to be recognized by an outsider as significant.
The low-risk assessment and zero monetary penalty could have justified handling the violation as a compliance exception. However, WECC decided to elevate the issue to an expedited settlement agreement in order to bring greater visibility to the issue of information security.
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.
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.
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 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.
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.
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.”
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.”
| LS Power
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.
FERC last week ordered a technical conference to investigate overlapping congestion charges imposed on pseudo-tie transactions between MISO and SPP.
The commission said it was displeased with MISO’s and SPP’s first round of briefs in the matter (EL17-89, EL19-60). Commission staff will set a date for the technical conference.
FERC last September said it would investigate the possibility of overlapping congestion charges between the grid operators after American Electric Power subsidiary Southwestern Electric Power Co. and the city of Prescott, Ark., complained. (See FERC Sets Briefings on MISO, SPP Congestion Fees.)
The RTOs have argued in briefs that though duplicative congestion charges are possible for their pseudo-tie transactions, mechanisms such as virtual transactions, financial transmission rights and firm-flow entitlements (FFE) counteract double charging. MISO has maintained that congestion charges on pseudo-tied generation with SPP do not require special Tariff remedies similar to those it took correcting double-charging with PJM, which it said, are less than those with SPP.
MISO and SPP seams | Organization of MISO States
MISO-SPP pseudo-tied generation has “minimal impacts” on reciprocally coordinated flowgates, and generators can also pursue FFE allocations, MISO said. The RTO also said it models pseudo-tied loads in aggregate with the load at its commercial pricing nodes, “which prevents discretely quantifying the individual impact on pricing, settlement and congestion associated with the pseudo-tied load.”
SPP also said it doesn’t think it needs changes to its Tariff or its joint operating agreement with MISO, and said such changes would disturb FERC’s longstanding position that RTOs and utilities “are not required to offer special terms and conditions to accommodate pseudo-tie requests.”
The commission wasn’t satisfied with those characterizations.
“We find that the current record, after the briefing, is still not adequate for us to either (1) confirm that the mechanisms available to market participants are sufficient to remedy any potential for overlapping congestion charges, or (2) find that MISO and/or SPP must make changes to their JOA and/or individual tariffs,” FERC wrote.
The commission said the RTOs failed to answer when and how many times pseudo-tied generation imposed duplicative congestion charges and their total cost. It ordered another round of briefs and posed additional questions, including how the RTOs handle charges under the simultaneous binding of flowgates, MISO’s aggregation methods and a more detailed description of the grid operators’ FFE process and other existing offsetting mechanisms.
FERC also asked the RTOs to explore a grandfathered treatment of pseudo-tied loads, as SWEPCO suggested.
Economy-wide carbon dioxide emissions in New England fell by 28 to 34% between March and June versus a year earlier, driven by a big cut in transportation because of stay-at-home orders issued in response to the COVID-19 pandemic.
But carbon emissions from the region’s electric generation increased 1.4% in the first half of 2020 because the retirement of Entergy’s 680-MW Pilgrim nuclear plant in Plymouth, Mass., caused an increase in natural gas generation, ISO-NE’s Patricio Silva told the ISO-NE Planning Advisory Committee on Thursday.
Moody’s Analytics expects real gross state product (RGSP) for New England to be 7% lower in 2021 than projected in its October 2019 forecast because of the COVID-19 pandemic. There is a 4% chance that the RGSP will be as much as 14.3% lower in 2021. | ISO-NE, Moody’s Analytics
The U.S. saw a 7% cut in electric generation in April versus a year earlier and a 16% reduction in emissions. The Energy Information Administration is projecting that U.S. energy-related carbon emissions for 2020 will be 11% lower than in 2019.
The pandemic caused significant reductions in electric demand during the spring, but load has rebounded with the hot, humid weather of July and August, ISO-NE’s Jon Black said.
2019 and 2020 year-to-date carbon dioxide emissions by fuel type (metric tons) | ISO-NE, using Moody’s Analytics data
Black provided the PAC a briefing on Moody’s Analytics’ updated macroeconomic forecast and performance of the peak load forecast model in preparation for the 2021 Capacity, Energy, Loads and Transmission (CELT) forecast.
Because of the pandemic, Moody’s June 2020 forecast predicts real gross state product (RGSP) for the region to be 7% lower in 2021 than projected in its October 2019 forecast used in the 2020 CELT, recovering somewhat to 1.4% lower by 2024. Black said that translated to a baseline summer demand forecast for 2021 that is about 113 MW lower in 2021 and 24 MW lower in 2024.
The baseline assumes that new COVID-19 infections peaked in April and there is no second wave that causes states to shut down again, with a 6% confirmed case fatality rate and a 10% hospitalization rate.
Moody’s said there is a 4% chance that the RGSP will be as much as 14.3% lower in 2021, rebounding to 8.5% lower by 2024. That would result in a 232-MW reduction in summer 2021, with a 147-MW reduction in 2024. It is based on a 12% confirmed case fatality rate and 17.5% hospitalization rate with a much higher than expected incidence of new infections and deaths in late 2020.
ISO-NE plans to use Moody’s October 2020 macroeconomic outlook to develop CELT 2021.
Comments due on Boston Tx Project
ISO-NE will open a 15-day comment window on its selection of the $48.6 million Eversource Energy-National Grid project to reinforce the Boston-area transmission grid in response to the retirement of Mystic Units 8 and 9.
The RTO announced the companies’ Boston Area Optimized Solution (BAOS) as the winner of its first competitive transmission procurement on July 17. (See ISO-NE Chooses Incumbent as Boston RFP Winner.)
ISO-NE’s Andrew Kniska, who briefed the PAC on the project, said the comment period will begin once the RTO posts the draft solutions study report.
The BAOS was the cheapest of 36 projects submitted in response to the RTO’s solicitation, which called for addressing an N-1 115-kV line overload and three N-1-1 345-kV line overloads. It also sought a dynamic reactive device (DRD) to aid in system restoration.
The utilities will install one 11.9-ohm, 345-kV series reactor on each of the two 345-kV Woburn-to-North Cambridge cables at the North Cambridge substation. A normally closed bypass breaker will be installed in parallel with each series reactor and opened only when there is a need to switch in one or both of the reactors.
They also will install a direct transfer trip scheme on the 394 line in response to the contingency causing the 115-kV K 163 line overload and install a +/-167-MVAR static synchronous compensator at the 345-kV Tewksbury substation.
Kniska said the RTO’s steady-state analysis found the BAOS solved the thermal needs and did not introduce any new thermal or voltage violations. The short-circuit analysis found all area circuit breaker duties were within their limits, and the DRD was found to meet the needs for reactive injections.
“The reactors have a bypass breaker to allow operators the flexibility to open and close them … as they see [is needed] for either operational flexibility or maintenance,” Kniska said.
One stakeholder asked about the rules for the operator to determine the need for deploying the breakers. “Are we in an N-1 condition and you open the breaker because you’re afraid of an N-1-1 occurring?”
“I don’t have the details on … how the operators will use them,” Kniska responded. “Obviously, from our needs assessment, this is for N-1-1. If you have the first contingency out, they will need to be in to protect the second contingency.”
Kniska said the proposed plan application study will include a transfer analysis “to determine if there’s any adverse impact on any of the operating conditions, including the interface import capability into Boston.”
Eversource and National Grid told the PAC in June they would reduce their return on equity by 25 basis points if they exceed the $48.6 million cost cap by more than 5%, with additional 25-point reductions for each incremental 5% overrun.
The project is expected to be in service in October 2023.
3 Tx Projects Canceled in Revised SEMA/RI 2029 Needs Assessment
ISO-NE will cancel three transmission projects because of reduced load expectations in the revised Southeast Massachusetts/Rhode Island (SEMA/RI) 2029 Needs Assessment.
The RTO’s Kaushal Kumar said the needs assessment was revised to determine if projects that have not started construction are still needed in light of the decrease in forecasted loads and other changes in study assumptions since the SEMA/RI 2026 Solutions Study.
Of the 15 projects from the SEMA/RI 2026 Solutions Study that have not started construction, 11 were confirmed as still needed and will be retained.
Canceled are:
Project 1733: Separate the 325/344 double-circuit tower lines, from West Medway to West Walpole (Estimated project cost: $17.9 million; spending to date: $1.1 million).
Project 1719: Install a 45-MVAR capacitor bank at the Berry Street substation ($5.0 million; $1.5 million).
Project 1723: Reconductor the L14 and M13 lines from the Bell Rock substation to Bates Tap ($38.7 million; $2.6 million).
A project to replace the 345/115-kV Kent County T3 transformer (Project 1724) also was determined to no longer be needed, but “the decision was made [that] this project will move forward,” Kumar said, because of the age of the current transformer and because $3 million of the $5.9 million cost has already been spent.
The existing transformer, which was installed in 1971, is the last remaining 345-kV transformer of its kind in National Grid’s fleet and has a higher-than-normal potential for failure, Kumar said.
Kumar said short-circuit levels have increased to 40 kA on the 115-kV system at the Kent County station, largely because of two new autotransformers. Similar units have failed in recent years because of short-circuit events outside of the transformer protection scheme, he added.
National Grid had put the project on hold late last year. Its new in-service date is March 2022.
Comments on the revised study will be accepted until Sept. 11.
Eversource Outlines $38M Line Rebuild
Eversource will spend $38 million to replace conductors and wood poles on its 10.3-mile 115-kV line between Harwinton and Watertown, Conn. (Line 1191).
Constructed in 1933 as two parallel 27.6-kV lines, the span was bundled and reconfigured to a single 115-kV line in 1957.
Eversource’s Christopher Soderman said the utility will reconductor the line and replace 96 wood H-frames and one lattice tower with new single-circuit weathering steel monopole structures. Four structures will be removed to optimize the line, Soderman said.
Eversource Energy will spend $38 million to replace conductors and wood poles on its 10.3-mile, 115-kV line between Harwinton and Watertown, Conn. | Eversource Energy
Soderman said the existing 2/0 copper conductor and 3/8-inch Copperweld shield wires are obsolete and prone to failure because of thermal rating degradation and degradation from environmental factors.
He said 2/0 copper conductor is no longer used for transmission, and hardware for it is not readily available, requiring “non-traditional” repair methods.
In addition, about 30% of the existing poles show evidence of woodpecker damage, rot, decay, splits or cracked arms, he said.
The in-service date is the second quarter of 2022.
