Page 1087 – RTO Insider

June 4, 2020

Heat Counteracts COVID-19 Impact on MISO Load

Unseasonably warm weather has nudged MISO load a little closer to normal this week, though RTO officials say demand is still being compressed by pandemic-related social distancing measures.

A heat wave pushed MISO’s peak load to nearly 100 GW, compared with peaks of about 73.5 GW in April and May.

“Our peak has been around 75 GW, and since we’ve seen warmer temperatures, our load jumped up 25,000 MW to about 100 GW, so things have been changing quickly,” MISO Executive Director of Real-Time Operations Rob Benbow said during a Reliability Subcommittee meeting Thursday.

Last June saw a peak of 107.8 GW late in the month, with loads averaging 77.8 GW, far below the 84.5-GW average in June 2018.

But Benbow said MISO load has not quite returned to normal.

“I think we’re still seeing some impacts of COVID on our load right now,” Benbow said.

MISO predicts a 125-GW summer peak, with 152 GW of capacity on hand to cover it before generation outages are factored in.

Director of Balancing and Interchange Operations Tag Short said MISO will probably have to declare an emergency this summer to access load-modifying resources to mitigate tight supply. (See MISO Preps for Balmy Summer with Pandemic Effects.)

“And, oh by the way, NOAA is forecasting a warmer-than-average summer for the entire footprint. Seems like that happens every year,” Short reported.

But Short said MISO’s summertime load predictions, first presented in April, don’t consider the pandemic continuing to shave some megawatts off load through the season. At last count, load was trending about 10% below average in May.

“Today, systemwide demand is slightly down because of the pandemic. In the case that energy usage does remain low, it may get us through July and August without a maximum generation alert,” Short said.

MISO load COVID-19 — MISO simulated average load compared to actual load May 23-29 | *MISO*

Some stakeholders chafed at MISO not factoring in the pandemic in its summer readiness presentations.

“When MISO makes these very public declarations, it has consequences. My executive is going to come to me asking for our preparations; my regulator is going to come to me asking for our plans. If this is really nothing more than Chicken Little saying, ‘the sky is falling,’ then it’s going to waste a lot of time,” Consumers Energy’s Kevin Van Oirschot said.

MISO also began to gradually phase in the return of its employees to work on Monday, Benbow said, allowing some non-operator positions to work on-site in its buildings on a voluntary basis.

Benbow said employees that wish to return must first answer screening questions via a phone app that instructs them on whether entering the office is advisable.

Employees must don a mask whenever they’re not at their personal workstations, Benbow said.

“We have seen a dozen people really come and go throughout the week. We didn’t expect a lot of people to return, and we’re still encouraging people to work from home,” Benbow said.

RSC Chair Bill SeDoris, of Northern Indiana Public Service Co., said his company has rolled out similar measures.

“It seems like this is going to be a common practice going forward for the foreseeable future,” SeDoris said.

Benbow said the mask mandate has become a common practice among other RTOs/ISOs.

COVID-19 testing for MISO control room operators is still being done locally with local health care providers, Benbow said, and not through any U.S. Department of Energy program. He added that not a single MISO operator has tested positive for the coronavirus to date.

MISO in May also conducted two hurricane drills with members, operating training team lead Jay Hermacinski said. He added that MISO redesigned its drills this year from the usual eight hours to four hours, as most drill responders worked from home.

The RTO will conduct two power system restoration drills in October, Hermacinski said, and it is devising two separate drill formats in case the pandemic continues into fall and operators aren’t allowed to congregate in training rooms.

Hermacinski said “conversations are being had” about how to make the drills effective if they’re conducted remotely.

Meanwhile, some of MISO’s interconnection queue customers now have more time to secure proof of land use for their generation projects. Wary of Contagion, MISO Bars Visitors for 2020.)

June 2, 2020

COVID-19, Hurricanes Among Biggest Summer Threats

Most regions are well prepared for the summer season, though the ongoing COVID-19 pandemic is a significant source of uncertainty, according to NERC’s 2020 Summer Reliability Assessment released Tuesday.

ERCOT Makes up Ground

NERC found that in nearly all areas the anticipated reserve margin for the June-September summer months “meets or surpasses” the reference margin level. The only exception is Texas, where the Electric Re l iability Council of Texas is projecting an anticipated reserve margin of 12.9%, above last year’s level of 8.5% but still short of its reference margin of 13.75%.

NERC summer threats — Summer 2020 anticipated/prospective reserve margins compared to reference margin level | *NERC*

Texas’ shortfall comes in spite of the region adding nearly 2 GW of new on-peak generation resources since last year, and ERCOT recalculating peak load to incorporate an expected drop in demand related to the pandemic. Echoing FER C’s 2020 Summer Energy Market and Reliability Assessment released last month, NERC warned that “operating mitigations and [Energy Emergency Alerts] may be needed [by ERCOT] to meet extreme demand or extreme resource derated conditions.” (See Emergency Measures Possible for ERCOT, FER C Warns.)

In a media call, NERC’s Mark Olson said that ERCOT was the only independent system operator that had updated its projected reserve margin to reflect the effects of the coronavirus on demand, although other regional organizations have acknowledged significant changes in demand linked to state and municipal shelter-in-place orders. Last month, the Northe a st Power Coordinating Council called the drop in demand a useful cushion against other potential COVID-19 impacts including workforce disruptions or interruptions to fuel supply. (See Sagging Demand Cushio n s NPCC’s Summer Outlook.)

“In general what you’re seeing is a conservative [demand] estimate across the power system, and I would not say that there’s a tighter condition [due to pandemic mitigation],” said Olson, NERC’s senior engineer and manager of reliability assessments.

Long Tail to COVID-19 Impacts

While resource adequacy is not threatened by the pandemic, system operators expect that COVID-19 will continue to impact their operations even as mitigation measures are relaxed by state and local governments. A major concern is that such relaxation could actually lead to “resurgence in virus activity” requiring sequestration of staffers at utilities, as well as among supporting services and supply chains for equipment and fuel.

This threat to staff availability, and mitigation measures to prevent it, has been the topic of considerable discussion, including in NERC’s Pandemic Preparedness and Operat i onal Assessment — Spring 2020 release in April as a “bridge” to the summer assessment. That assessment also warned of elevated risks of cyberattacks and potential issues with distributed energy resources. (See PPE, Testing Top Coronavirus Con c erns for NERC.)

The new report moves beyond the immediate threat to look at impacts with a longer horizon. Some of the utilities’ long-term worries are a direct outgrowth of steps put in place earlier this year to protect staff from the outbreak — specifically, delays in maintenance, installation of new generation and retirement of existing facilities that were previously planned for spring.

While NERC acknowledged in the report that these measures were necessary to reduce health risks to essential personnel and may have to be continued for an unknown amount of time, it warned that utilities must be prepared for “higher-than-expected forced outages” during peak demand periods. The organization considers this a likely enough risk that it plans to update its Generator Availability Data System to allow the collection of data on outages with pandemic-related causes for ease of future analysis.

Seasonal Risks Highlighted

The summer assessment also looked at concerns specific to the summer months, such as restrictions on the ability of utilities to provide mutual assistance during the 2020 Atlantic hurricane season, which is expected to be unusually active with up to 19 named storms and six major hurricanes. (See Pandemic Adds to 2020 Hurricane Season Chal l enges.) NERC urged system operators to refer to the Electric Subsector Coordinating Council’s outage response plan to ensure their strategies are consistent with expert recommendations.

Wildfires are another source of worry for the western U.S. and Canada. While national fire agencies predict normal or below-normal threats of fire in the early summer months, by July large parts of both countries — as well as Mexico — are projected to face above-normal fire risk. Utilities are warned to prepare for widespread outages, both as a result of the fires and preventative measures that could be needed.

“In parts of California … the public safety power shutoff programs are in place, which can help prevent ignitions from the power system,” Olson said. “But in implementing those, it is an issue for the reliability of the power system [that] may need to be taken down when these conditions arise.”

June 2, 2020

FERC OKs Tougher PJM Credit Rules

Companies seeking to participate in PJM’s markets must provide the RTO with more financial records, corporate information and details of prior defaults under rules effective June 1.

FERC approved the tougher rules May 27, turning aside a protest from Dominion Energy, which said the RTO’s proposal was ambiguous (ER20-1451).

The new requirements for managing market participants’ credit risks arose from the 2018 GreenHat Energy default in the financial transmission rights (FTR) market.

PJM will determine whether a company presents an “unreasonable credit risk” based on factors including a history of market manipulation, financial defaults or bankruptcies within the past five years. It also will consider market and financial risk factors such as low capitalization, future material financial liabilities and low credit scores.

To allow PJM to conduct ongoing risk evaluation, companies also must make annual officer certifications and notify the RTO of any “material adverse change in the financial condition of the participant or its guarantor.”

PJM Credit Rules — Annual ARR/FTR market timeline | *PJM*

The proposals won a 90% sector-weighted vote at the Members Committee in March and generally supportive comments from intervenors. (See PJM Members OK T i ghter Credit Rules.)

Dominion, the only intervenor to protest in the FERC docket, complained that PJM’s process for choosing when it uses external credit ratings and when it uses internal credit scores was vague and required clarification. It balked at giving PJM discretion to use its internal credit score even when external credit ratings are available, saying it will make it difficult for an applicant to determine how much credit PJM will extend it. It said PJM should only be permitted to use its internal credit score when an external credit rating is unavailable. Dominion also said PJM failed to clearly define the term “unreasonable credit risk.”

FERC approved PJM’s filing without revisions, saying, “It is impractical to enumerate all of the examples that constitute an unreasonable credit risk, as doing so may unnecessarily limit when an RTO can act to protect its wholesale markets and market participants to only those specified instances enumerated in the Tariff.

The commission said the new rules are consistent with Order No. 741, which allows RTOs discretion in requiring additional collateral in response to changed circumstances.

“It is common for financial institutions and large business organizations to utilize multi-dimensional credit scores and internal ratings of quantitative and qualitative factors as a way to standardize the evaluation of an entity’s credit risk. We also note that, previously, PJM was only able to rely on external credit ratings, which … do not reflect market or liquidity risk and can go stale quickly.

“With the ability to consider both external credit ratings and its internal credit score, PJM will have more insight and visibility into the credit risk posed by a particular applicant or market participant and can react quickly to minimize financial exposure,” the commission said.

The commission denied Dominion’s contention that PJM’s proposal is unreasonably vague, saying the RTO’s promise to provide entities with their internal credit score provides transparency while also reducing the opportunity for a market participant to deliberately influence its internal credit score.

Concurrence

Commissioners Richard Glick and James P. Danly concurred on the proposed changes, which they said were “at least as exacting” as rules the commission has approved for MISO and NYISO.

But in a joint statement, they said they were “somewhat uneasy” with the discretion given PJM in making creditworthiness decisions.

“These revisions represent an important first step in enhancing PJM’s credit risk evaluation process, but they are just that: a first step. Further changes should be considered, not only in PJM, but in all the organized markets,” they continued, referencing the Energy Trading Institute’s December petition seeking a technical conference on credit and risk management (AD2 0 -6). (See RTO Council Balks at Credit Rul e making.)

They urged their colleagues to join them in supporting the conference, saying it would be a “timely vehicle for the commission to engage in a much-needed discussion on these important issues.”

June 2, 2020

MISO Stakeholders Split on Seasonal RA Measures

Stakeholders are divided over whether MISO has conducted enough analysis to justify the possible adoption of seasonal capacity auctions and loss-of-load expectation (LOLE) studies.

The mixed opinions arose during a June 1 virtual workshop to discuss the next steps in MISO’s resource availability and need (RAN) project. In addition to a possible seasonal LOLE study and capacity auction, the RTO is also considering whether to use the RAN effort to define its own set of reliability requirements and design scarcity pricing that better reflects tight supply.

If it opts for any of those solutions, MISO hopes to make FERC filings in the middle of next year in order to introduce changes by early 2022.

“We’re on a pretty aggressive timeline, and one that needs your input,” MISO Director of Resource Adequacy Coordination Zakaria Joundi told stakeholders.

The RTO is currently drafting a whitepaper on the problem statement behind the next round of proposed RAN fixes. But some stakeholders argue that the RTO doesn’t need another self-published whitepaper — rather, it needs to solicit and include stakeholders’ input.

Madison Gas and Electric’s Megan Wisersky took issue with MISO consistently using the word “enhancement” in RAN solutions.

“You keep saying you’re making ‘enhancements.’ What you’re actually doing is reducing capacity accreditation. So it really doesn’t feel like ‘enhancement.’ It feels like private property is getting devalued over and over again,” Wisersky said, taking aim at MISO’s proposal to cut the capacity credits of load-modifying resources based on lead times and availability, a RAN proposal. (See MISO Delays New LMR Accreditation L aunch.)

“We’re seeing the risk move away from the summer peak,” Joundi said. “The current annual construct does not reflect a changing risk profile and evolving resource needs.”

More Analysis?

Customized Energy Solutions’ David Sapper asked for more analysis to prove that MISO really does face reliability risks outside of a summer peak.

WPPI Energy’s Steve Leovy said while he believes there is probably a loss of load risk in September, he doesn’t believe MISO has demonstrated a material risk outside of summer until it prepares a full LOLE analysis on par with those prepared for the Planning Resource Auction.

“That leaves a very real prospect that we could launch into a seasonal PRA … and it could just be a waste of everyone’s effort if you don’t have material risk outside of summer. There’s not been a showing that the annual construct is inadequate. If we see it, we’ll shut our mouths, but we don’t see it,” Leovy said.

“MISO staff points to conclusions. MISO staff says, ‘Okay, we’ve had emergencies outside of summer months, but there’s nothing more than that to prove we have a problem in the off-peak season,” the Coalition of MISO Transmission Customers’ Kevin Murray said.

MISO Seasonal RA Measures — Grant Wind Farm | *East Texas Electric Coop*

Minnesota Public Utilities Commission staff member Hwikwon Ham argued that MISO’s changing risk profile is clear in its renewable integration impact assessments, but he, too, pressed for a full LOLE study that could show risk beyond summer.

“I think we have an issue, but that issue isn’t properly translated into the LOLE study,” he said.

Ham also told MISO staff that it’s time to design a long-term solution and put an end to its incremental RAN solutions that focus on generator outage scheduling and LMR availability.

Consumers Energy’s Kevin Van Oirschot countered that incremental solutions pose the least risk of damage to the market.

Other stakeholders said MISO’s increasingly common maximum generation emergencies are justification enough for a seasonal parsing of reliability risks or capacity.

“Xcel Energy is ready to move forward,” Kari Hassler said of her company. “We believed that the current construct worked well … but times are changing, resources mixes are changing, operations are changing. The matching up of seasonal variations makes sense. We don’t need any more studies. We’ve been dragging this out for a year-and-a-half; we’re ready to move forward.”

Hassler argued that an LOLE study in search of non-summer risk has to be done “for the future, not for yesterday.” She said data used in such an analysis should be forward-looking, not historical. Multiple stakeholders said forward-looking data should include planned resources in the interconnection queue.

“We need to look at the future years rather than saying, ‘You need to show us evidence that relies on historical data.’ I think that’s the wrong argument,” Ham agreed.

“Even if we don’t have non-summer risk, we think there’s value in a seasonal construct. The seasonal capabilities of our resources are dramatically different,” WEC Energy Group’s Chris Plante said.

Gabel Associates’ Travis Stewart argued that MISO’s three dozen maximum generation emergency events and warnings since 2016 are justification enough for change.

“Such a frequency of emergency events doesn’t occur in any other RTO,” he said. “The time is ripe for change.”

Stewart said MISO should examine all capacity resource accreditations, not just LMRs.

MISO Executive Director of Market Strategy and Design Scott Wright said that the capacity the Planning Resource Auction clears and “what actually shows up” are two different things.

The RTO has said its current capacity accreditation processes don’t match up with actual capacity resource availability, don’t reflect resource availability in months outside of summer and don’t account for operational differences between capacity resources.

Multiple stakeholders on the call asked that MISO create reliability requirements before it begins tinkering further with capacity resource accreditation. Many worried aloud that the RTO might penalize necessary planned generation outages.

“Just saying, ‘Why aren’t you there?’ is short-sighted. There are legitimate reasons to be unavailable,” Northern Indiana Public Service Co.’s Bill SeDoris said.

Wright thanked stakeholders for their frankness during the workshop and said MISO staff will consider comments when making RAN proposals.

“We didn’t want to have 25 slides and have MISO speak. We wanted to hear you,” Wright said of the workshop format.

The RTO plans to hold more RAN workshops with stakeholders before settling on which future filings it may pursue.

June 2, 2020

$10M Deal Reached over MISO, PJM Pseudo-tie Fees

Five generators have struck a $10 million settlement with MISO and PJM over the RTOs’ past practice of double-charging pseudo-tied generation for congestion fees.

Under the settlement approved May 29 by FERC, the RTOs will refund a combined $10.3 million to five pseudo-tied generators. MISO will pay a total $8.47 million, while PJM will pay $1.83 million (ER20-1342).

Tilton Energy lodged a complaint in 2016 against the RTOs for assessing overlapping congestion charges on pseudo-tied resources. American Municipal Power, Northern Illinois Municipal Power Agency, Dynegy and Illinois Power Marketing soon followed with similar complaints. FERC consolidated the proceedings, and the commission ordered a refund hearing in the matter last May. (See Refund Hearing Ordered in Pseudo-Tie Complaint.)

MISO PJM Pseudo-tie Fees — | © *RTO Insider*

The RTOs introduced a temporary rebate program in 2017, then began including pseudo-ties in the day-ahead scheduling process in 2018 to end redundant congestion costs.

Dynegy will receive the largest refund, with almost $5.3 million from MISO and $1.1 million from PJM. American Municipal Power will receive the second highest with $1.9 million from MISO and a little more than $412,000 from PJM.

The three other generators’ refunds are well under $1 million apiece:

Northern Illinois Municipal Power Agency stands to receive $620,193 from MISO and $133,997 from PJM;
Illinois Municipal Electric Agency will receive $493,398 from MISO and $106,602 from PJM; and
Tilton Energy will be refunded $161,177 from MISO and $34,823 from PJM.

FERC said the settlement was fair, in the public interest and resolved all the pseudo-tied congestion fee disputes that it set for hearing last year.

June 2, 2020

NYISO Gets Extra Time to Fix Market Software

FERC on Monday granted NYISO eight extra months — until year-end — to fix a “misalignment” between its market software and its Tariff rules (ER20-1470).

Section 4.4.1.2.1 of the ISO’s Services Tariff allows generators that are committed day-ahead only for non-synchronous operating reserves to modify their minimum generation bids in real-time, but the ISO recently discovered that its software does not provide the flexibility intended by that provision.

NYISO explained that its software currently is preventing all generators, even those that only receive a day-ahead schedule for non-synchronous operating reserves, from modifying their minimum generation bids in real-time.

The ISO said it expects to deploy the necessary software improvements coincident with its broader software revisions to implement fast-start pricing reforms that the commission already accepted in a February order (ER20-659).

NYISO Market Software — NYISO reports 96.5% of RTD intervals had 1,800 MW or more of SENY 30-minute reserve procured. | *NYISO*

Granting the waiver “will allow NYISO to develop and implement software consistent with its business practices without the need to rush a software patch,” the commission said.

However, the waiver will be in effect for only the period necessary for NYISO to code software modifications, perform the necessary quality assurance testing and deploy the software consistent with its standard software development practices, the commission said.

NYISO also asked the commission to “excuse any instances of past non-compliance with the provision at issue,” adding that any such instances “cannot be corrected or reversed.”

“Upon consideration, we will exercise our discretion in addressing such matters and, given the facts and the record before us in this matter, we take no action with respect to the instances of NYISO’s past non-compliance,” the commission said.

June 2, 2020

FERC OKs Negotiated Rates for Champlain Hudson Project

FE R C has authorized the owners of the 1,000-MW Champlain Hudson Power Express (CHPE) project to charge negotiated transmission rates to carry Canadian hydropower to New York City.

The commission’s May 29 order also granted the project developer’s request for waiver of certain reporting requirements (ER20-1 2 14).

The $3 billion high-voltage direct current (HVDC) merchant transmission proposal has succeeded in allying two Democrats who have not always got along well — New York City Mayor Bill de Blasio and Gov. Andrew Cuomo, though each in his own way has championed clean energy. (See Cuomo Sets New York’s Gr e en Goals for 2020.)

CHPE is owned by TDI-USA Holdings (TDI), which is in turn majority-owned by the investment firm Blackstone Group. Despite controlling $571 billion in assets, Blackstone does not own or control any existing electric transmission or distribution facilities in the markets operated by NYISO or Hydro-Québec.

Champlain Hudson Project — Champlain Hudson Power Express project map | *Champlain Hudson Power Express*

Under commission precedent, merchant transmission projects differ from those of traditional public utilities in that the developers assume the full market risk of a project and have no captive customers from which to recover costs. Thus, the commission has allowed some such projects to be priced based on negotiated rates and has granted waivers of certain requirements.

FERC acknowledged CHPE’s commitment to turn over operational control of the project to NYISO, comply with all applicable reliability requirements and provide NYISO with all required information necessary for its regional transmission planning process pursuant to Order 1000. The commission also noted that CHPE will retain “an experienced third-party independent expert” to advise the company on its open solicitation and capacity allocation process in order to ensure that its solicitation process is not “unduly discriminatory and preferential.”

“We will, however, reserve judgment on whether the open solicitation and capacity allocation process once implemented are not unduly discriminatory, pending CHPE making a compliance filing within 30 days of the close of its open solicitation process,” the commission said.

The commission also granted CHPE’s request for waiver of Part 141 of the commission’s regulations, including the Form No. 1 annual reporting requirement for electric utilities, noting it has previously granted such waivers for other merchant transmission owners.

The commission also granted CHPE waiver of the full reporting requirements of Subparts B and C of Part 35 of FERC regulations, with the exception of sections 35.12(a), 35.13(b), 35.15 and 35.16.

Gov. Cuomo has recently spoken in favor of the CHPE project, prompting a swift protest from the Independent Power Producers of New York (IPPNY).

“This line is both unnecessary, given in-state developer demand, and provides no environmental benefit,” said IPPNY President and CEO Gavin J. Donohue in a st a tement.

IPPNY in January released a stu d y it commissioned from Energyzt showing that “the purchase of hydropower over CHPE will not result in reduced global emissions of carbon dioxide – and may even increase overall carbon emissions.”

“Spending more than $3 billion to support the profiteering of a Canadian company on a project that will not revitalize the state’s economy and will not actually provide an environmental benefit is a mistake,” Donohue said. “Expanding New York’s own renewable energy industry will allow for guaranteed emissions reductions while creating in-state jobs.”

June 2, 2020

IMM: ERCOT’s Shortage Pricing ‘Pivotal’

Shortage pricing played a crucial role in Texas wholesale market competitiveness last year, E R COT’s Independent Market Monitor said in its annual market rep o rt.

The report from Potomac Economics showed average real-time energy prices rose by 32% in 2019, despite a 23% reduction in natural gas prices. The Monitor attributed the increase to shortage pricing in August and September, when prices reached the offer cap of $9,000/MWh for more than two hours.

ERCOT Shortage Pricing — ERCOT’s average all-in price for electricity highlights August spike. | *ERCOT IMM*

“Shortage pricing is key in ERCOT’s energy-only market because it plays a pivotal role in facilitating long-term investment and retirement decisions,” the Monitor said, the idea being that high prices during energy shortages will incent new generation.

ERCOT entered last summer with a reserve margin of 8.6%, which is up to 12.6% this summer. The Monitor said only 4.5% of the grid’s generation was unavailable during summer peak conditions, similar to 2018 but lower than the 6% during 2016 and 2017.

“We attribute this increased availability to the effectiveness of the shortage price signals in motivating participants to increase maintenance and minimize outages during the summer peak,” the Monitor said.

The Texas Public Utility Commission in January modified ERCOT’s shortage pricing mechanism by altering the market’s operating reserve demand curve. The changes accounted for a nearly $7/MWh increase in average energy prices and a $1.9 to $2.1 billion increase in energy revenue.

The PUC has also approved the real-time co-optimization of energy and ancillary services, scheduled to be added to the market in 2024.

“This will significantly improve the real-time coordination of ERCOT’s resources, lower overall production costs and improve shortage pricing,” the Monitor said. “These improvements will be increasingly valuable as additional intermittent wind and solar resources enter the ERCOT market.”

In its report, the Monitor recommends key improvements to ERCOT’s pricing and dispatch processes:

Remove the “opt-out” option for resources receiving reliability unit commitment instructions.
Eliminate the 2% shift factor rule, and price all congestion regardless of its generation effect.
Modify the allocation of transmission costs by transitioning away from the four coincident peak (4CP) method.
Price ancillary services based on the shadow price of procuring each service.
Modify the reliability deployment adder and operating reserve adder to improve pricing during emergency response service deployments.
Implement a locational reliability deployment price adder.
Improve the mitigated offers for generating resources.
Implement transmission demand curves.

The Monitor retired six other recommendations no longer needed, including the inclusion of marginal losses in ERCOT’s LMPs. The PUC has concluded the incremental benefit of applying marginal losses was not worth the implementation cost and market disruption.

The market report was the first delivered under the guidance of Monitor Director Carrie Bivens, who promised a “timely and comprehensive” report when she was hired in April. (See Bivens St e ps in as New D i rector of ERCOT Monitor.)

June 1, 2020

UCS Analysis Knocks Coal Self-commitments

Coal plant self-commitments saddled Midwest electricity customers with $350 million in unnecessary costs in 2018, according to a new analysis from the Union of Concerned Scientists, which is calling on regulators to rein in the practice through investigations.

“Used, But How Useful?” concludes that individual ratepayers could have saved an average of $60 if the most efficient existing resources in MISO were deployed instead of coal self-scheduling in 2018.

“We found that not every coal plant in the Midwest operated uneconomically, but the utilities that did it the most drove down market prices, effectively squeezing out cleaner, cheaper sources such as wind and solar power,” Sandra Sattler, senior energy modeler at UCS, said in a press release.

UCS said savings from eliminating the self-dispatches could have more than doubled the amount MISO claimed it saved its members that year through efficient centralized dispatch. The RTO’s 2018 value proposition estimated its efficient energy dispatch saved members anywhere from $282 million to $312 million during the year.

“We decided that having a published report on which utilities were not acting in the public interest would be useful to regulators. We hope this will be a helpful tool for commissioners trying to tackle this problem,” UCS Climate and Energy Senior Energy Analyst Joe Daniel told RTO Insider.

This isn’t the first time UCS has publicly questioned the practice of vertically integrated utilities being allowed to operate units out of merit at times when their production costs exceed the wholesale market price. UCS pressed the issue last year at the National Association of Regulatory Utility Commissioners’ annual meeting. (See Enviros, States Question Coal Self-commitments.)

Daniel said the solution isn’t as simple as just abolishing must-run designations in MISO.

“There are plenty of power plants that use the must-run designation economically,” he said. “The uneconomic commitments will continue in another loophole unless state regulators come in and stop it.”

Daniel said a good first step for regulators is to open investigatory dockets into utilities that exhibit high costs.

“That way there’s a frank discussion between regulators, utilities and intervenors,” Daniel said. “The regulators have an obligation to disallow imprudent costs. … Running power plants that are expensive when there’s lower-cost energy available on the open market is imprudent. … If a commission would scrutinize and disallow tens of millions in imprudent costs, I am confident that the utility’s reaction would be to figure out how to solve the problem themselves. Smart utilities won’t let it get to that point. Smart utilities will see that commissions are taking things seriously and be proactive.”

When the Minnesota Public Utilities Commission opened a docket last year to investigate Xcel Energy’s self-scheduling of coal plants, Daniel said, the utility quickly proposed converting its coal plants to seasonal and economic use. Missouri and Indiana have also opened investigatory dockets into utility self-commitments. (See Ind. Regulators Scrutinize Duke Self-commitments.)

Biggest Offenders

According to the UCS report, Xcel subsidiary Northern States Power uneconomically ran its Allen S. King and Sherburne Country coal plants at a $56.9 million loss in 2018. If the utility had opted for more efficient generation in the MISO market, the average residential ratepayer could have saved $54 that year, UCS said.

UCS named Cleco Power the worst offender, saying it uneconomically generated electricity from its Dolet Hills and Brame Energy Center coal plants at a $123.3 million loss in 2018, costing Louisiana ratepayers an average of $184 over the year compared with more economic electricity available in the market.

Dolet Hills co-owners Cleco and Southwestern Electric Power Co. have indicated they may retire the plant as early as 2021. Earlier this year, the utilities agreed to retire the plant by 2026 as part of a deal reached with the Sierra Club. The conservation group has claimed that closing the plant would save ratepayers more than $60 million per year.

UCS Coal Self-commitments — Dolet Hills power plant | *Cleco Power*

Cleco spokesperson Jennifer Cahill pointed out that the company and SWEPCO pledged beginning last year to only operate Dolet Hills in the demand-heavy summer months, or when requested by MISO.

“Furthermore, Cleco Power intends to seek regulatory approval to retire the Dolet Hills Power Station and the nearby mine that supplies the plant with coal. The closing dates for the power station and mine will be subject to discussions with stakeholders, including the Louisiana Public Service Commission and regional transmission organizations,” Cahill said in an email to RTO Insider.

DTE Energy’s five coal plants uneconomically generated power at a $94.7 million loss in 2018, costing individual ratepayers an extra $61, UCS also reported.

UCS said MISO’s greatest potential for savings “generally appear where the worst actors operated: Xcel Energy in Zone 1, Cleco in Zone 9, and DTE and Consumers Energy in Zone 7.”

The report also said coal self-commitments in MISO suppressed market clearing prices by 2.4% — or 63 cents/MWh — in 2018. The group also noted the self-commitments suppress independent power producers’ revenue in “all MISO transmission zones.”

“By exploiting gaps in regulatory oversight and loopholes in wholesale market rules, rate-regulated utilities are cutting ahead in the merit-order line. Rate regulation, coupled with a lack of scrutiny when it comes to cost recovery, has enabled these utilities to lose money in the market without incurring actual losses on their balance sheets,” UCS wrote, adding that in many parts of the U.S., the cost to buy and burn coal “exceeds the market price in most hours of the year.”

Self-commitment ‘Loopholes’

UCS said it makes economic sense for coal plants to respond to market price signals and begin operating more infrequently, allowing lower-cost natural gas and renewables to fill the gap. But the group characterized existing state regulatory frameworks and rate cases as “loopholes” that allow unchecked self-commitment decisions to persist.

“It is doubtful that changes to this practice will materialize if regulated utilities are continually allowed to recover fuel costs, without scrutiny or incentives to improve operations,” UCS said. “Utilities will throw up strawman excuses for why their coal plants are so uneconomic, but it is not incumbent on the regulator to innovate on behalf of the utility. Rather, utility companies are obligated to come up with a solution, and regulators should either approve or disapprove of the companies’ proposals.”

Daniel said residential ratepayer costs are more important than ever, with many staying at home more often because of the ongoing coronavirus pandemic.

And he said new resource additions to achieve UCS’ saving estimates are unnecessary.

“You could safely operate the grid with lower-cost existing resources that already exist. You should use what you have as efficiently as possible. And that’s not what happening. Utilities are preferentially selecting coal-powered plants at the expense of customers,” Daniel said.

To arrive at the millions in potential savings, UCS used modeling software that accounts for MISO system limitations, transmission constraints and power plants’ ramping times and capabilities, Daniel said.

He acknowledged that MISO aggregates the number of uneconomic coal commitments in its footprint but doesn’t call out specific generators or utilities like UCS’ latest analysis.

“What really differentiates this research is we used a production cost model and the same software MISO does to come up with these numbers,” Daniel said.

June 1, 2020

ERCOT Technical Advisory Committee Briefs: May 27, 2020

Given the continued uncertainty of future in-person meetings, ERCOT stakeholders last week endorsed several bylaw amendments and rule changes to improve electronic meetings and votes.

As if to hammer the point home, the changes were among 15 voting items in an email vote that did not become official for two days. ERCOT rules currently require two full business days to allow stakeholders to return their votes.

Vickie Leady, ERCOT’s assistant general counsel, told the Technical Advisory Committee on Wednesday that the grid operator’s bylaws “never contemplated a situation with the scale and duration” in which stakeholders “could not safely convene together in one place.”

“It’s creating a risk to ERCOT,” Leady said.

ERCOT closed its facilities to most outside visitors and canceled in-person meetings in early March. Meetings have been conducted virtually ever since.

Legal staff proposed widening the definition of “urgent matters” to include when it would be “difficult or impossible” for a quorum of directors or subcommittee members to physically convene in one location. The changes would allow teleconference meetings and actions that, if otherwise delayed, “may result in operational (including, but not limited to those activities and functions affecting the ERCOT market or system), regulatory, legal, organizational or governance risk.”

Staff made other changes to the bylaws to closely align with the Texas Open Meetings Act and Texas Business Organizations Code’s teleconference technology methods.

The changes will now go before the Board of Directors during its June 9 teleconference. If approved, the board would issue a call on June 10 for a special meeting to vote on the bylaw changes by July 2. The changes would then be filed with the Texas Public Utility Commission by July 31 for its approval.

The TAC also approved several changes to its rules allowing for roll call votes. Chair Bob Helton, with ENGIE, said the committee would be using consent agendas to compensate for the extra time taken by email votes.

Corpus Christi Tx Project Gets OK

The TAC unanimously approved a $219 million transmission project, previously approved by the Regional Planning Group, that addresses more than 1 GW of future industrial load growth on the north shore of Corpus Christi Bay expected by 2024.

As recommended by staff following an independent review of AEP Texas’ proposal, the Corpus Christi North Shore RPG Project will comprise 36 miles of 345-kV lines, 8 miles of new and upgraded 138-kV lines, two new 345-kV substations and three 345/138-kV transformers.

LNG plants account for more than half of the additional load. Cheniere Energy has developed an LNG export terminal in Corpus Christi’s harbor. Two trains are currently in operation, with a third planned to come online in the first half of 2021.

ERCOT’s review concluded that its recommended option does not cause new or additional congestion. Staff determined the 138-kV upgrade met economic planning criteria and added it to the project.

AEP’s Richard Ross said the company “supports and is comfortable at this point in time” with ERCOT’s recommendation.

ERS Payments up 1.6% to $48.2M

Staff shared ERCOT’s annual report on its emergency response service but received no questions from members. The report is required annually by the PUC (27706).

According to the report, demand response and behind-the-meter generation received $48.2 million in capacity payments during the program year for curtailing load or sending power to the grid, a 1.6% increase from the $47.5 million for the previous time period.

ERCOT deployed ERS twice last year during August’s two energy emergency alerts. The two deployments lasted a total of 95 minutes.

Members Disagree over Change to ERS’ Return

The TAC on Friday took up a second email vote to consider the only Nodal Protocol revision request (NPRR1006) that did not clear the email vote.

In a vote that closes at 5 p.m. Tuesday, committee members will weigh NPRR1006’s approval as amended by comments from Direct Energy.

The NPRR had received only four votes (Lower Colorado River Authority, South Texas Electric Cooperative, Exelon and Reliant Energy Retail Services), with 20 members opposing and two abstaining.

The change would return ERS resources in a linear curve over a four-and-a-half-hour period following recall, instead of 10 hours. It also changes the process for annually updating the parameter by removing a real-time deployment price adder from the real-time ancillary service imbalance payment or charge.

Direct Energy expressed concern over the unintended consequences of the price adder’s elimination from the equation. The company urged interested parties to file their proposed changes in a separate NPRR “to facilitate the quick movement of the original intent of this NPRR through the approval process.”

Direct Energy’s Sandy Morris said stakeholders have not had the time or analysis to understand the full implications of the proposed change. Should the matter be separated, she wrote, “it could possibly continue through the proper channels of analysis and debate and still be implemented at the same time as … NPRR1006.”

The committee’s email vote unanimously approved eight other NPRRs, a change to the Nodal Operating Guide, an Other Binding Document revision request (OBDRR) and two system change requests (SCRs):

NPRR 933: adds specific timing requirements for retail electric providers and non-opt-in entities to notify ERCOT of the DR and price-response programs they offer to customers, the level of participation in those programs and the deployment events associated with those programs.
NPRR9 75: clarifies that load forecast models will be used to select the seven-day load forecast based on expected weather and requires ERCOT operations to explain its selection, improving transparency for market participants.
NPRR9 87: includes the contribution of energy storage resources (ESRs) to physical responsive capability and real-time online reserve capacity in the ancillary service imbalance calculation.
NPRR9 8 9: establishes ESRs’ technical requirements for voltage support service (including reactive power capability) and primary frequency response.
NPRR 1018: clarifies several provisions regarding the termination and suspension of a qualified scheduling entity (QSE) and the ability of a load-serving entity or resource entity to act as a “virtual” or “emergency” QSE.
NPRR1019: addresses switchable generation resources (SWGRs) moving from a non-ERCOT control area to the ERCOT control area by creating a proxy energy offer curve with a price floor of $4,500/MWh for each RUC-committed SWGR and including a lost revenue cost component to the switchable generation cost guarantee.
NPRR10 21: shortens the default uplift invoice’s issuance timeline from 180 days to 90 days and allows ERCOT to use the best available settlement data when calculating each counterparty’s share of the default uplift.
NPRR 1022: modifies how QSEs and congestion revenue right account holders (CRRAHs) submit banking information changes to ERCOT by removing the ability to submit the information with a Notice of Change of Information via email or fax. The NPRR creates a new form, Notice of Change of Banking Information, that a QSE/CRRAH must execute and submit through the market information system’s certified area.
N OGR R 204: together with NPRR989, codifies concepts described in the Battery Energy Storage Task Force key topics and concepts No. 4 (KTC-4) and establishes ESR technical requirements.
OBDRR017: aligns language within the operating reserve demand curve’s methodology for calculating the real-time reserve price adder with protocol revisions under NPRR987 and changes the real-time operating reserve calculation to consider an ESR’s state of charge when calculating the resource’s contribution to the online operating reserves.
SC R 807: increases the CRRAHs’ total CRR transaction limit by 33% to 400,000 market transactions during CRR auctions.
SC R 809: updates the validation rules imposed on ERCOT’s external telemetry and used in the resource limit calculator.