Page 1091 – RTO Insider

June 4, 2020

ERCOT Briefs: Week of June 1, 2020

Austin Energy has officially notified ERCOT that it plans to permanently retire one of the two original gas-fired steam units at its Decker Lake generating facility, effective Oct. 31. The municipal utility filed a notification of suspension of operations on Monday.

The 315-MW Decker 1 unit began commercial operation in 1971 and is the oldest generating unit in Austin Energy’s fleet. Decker 2 went into service seven years later and has 420 MW of capacity.

According to the utility’s latest resource plan, approved in late March by the Austin City Council, Decker 2 will be retired following the 2021 summer peak. An Austin Energy spokesperson said both units are nearing the end of their normal life expectancies.

Four other gas turbines at the facility, with a combined capacity of 192 MW, will continue to operate.

ERCOT has projected reserve margins of 17.3% and 19.7% in 2021 and 2022, respectively. Those figures include Decker 2’s capacity.

2 Market Participants File Appeals with PUC

Two ERCOT market participants have filed appeals with the Public Utility Commission regarding last year’s resettlement of 21 operating days, necessitated by a series of software errors.

Monterey TX, a qualified scheduling entity (QSE), said it is seeking “financial and injunctive relief” over what it says are “improper” charges for point-to-point (PTP) congestion revenue rights obligations in excess of its not-to-exceed bid prices in September 2019. Monterey is asking that the PUC direct ERCOT to halt its “unlawful behaviors” and is seeking more than $89,400 and accrued interest in compensation (50881).

Independent power marketer DC Energy appealed ERCOT’s resettlement of certain PTP obligations at prices more than 1 cent/MWh above the company’s not-to-exceed bid prices. DC Energy is seeking “redress of the economic penalty” it suffered from resettlement “that would put it in the same position economically” if ERCOT had honored the terms of its not-to-exceed bid prices when it resettled the day-ahead market (50871).

Both companies said they attempted to resolve their disputes with ERCOT, eventually submitting requests for alternative dispute resolution proceedings. Those requests were dismissed in April.

ERCOT’s Board of Directors in December approved the price corrections for 21 operating days, dating back to September, after it determined that real-time prices were “significantly affected” by the software error. (See “Directors Approve Price Corrections for 21 Operating Days,” ERCOT Board of Directors Briefs: Dec. 10, 2019.)

ERCOT Adjusts to DG, DR Resources

ERCOT has published a backgrounder and an accompanying video on how distributed generation and demand response are used in its footprint. Both can be found on the grid operator’s Distributed Generation webpage.

Staff have been working to catalogue the various forms of DG and DR in the region, primarily utility-scale solar, commercial solar and batteries. ERCOT only has 2 MW of operational DG but has another 374 MW in its interconnection queue.

“All generation resources provide great value to the grid, and our goal is to ensure these newer resources can participate in the ERCOT market and help provide reliable electric service to Texans,” ERCOT Director of Grid Coordination Bill Blevins said in a statement.

ERCOT defines distributed generation as electrical generating facilities located at a customer’s point of delivery, of 10 MW or less and connected at a voltage less than or equal to 60 kV, which may be connected in parallel operation to the utility system.

DG that intends to be dispatched by ERCOT or provide ancillary services must register as a DG resource and undergo qualification testing. DG with installed capacity of more than 1 MW and capable of providing a net export of energy into the distribution system is required to be registered as a settlement-only distribution generator.

TAC Passes Revised ERS Change

The Technical Advisory Committee on Tuesday unanimously approved a change to how emergency response service resources return following recall.

The Nodal Protocol revision request (NPRR1006) returns 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 so that the TAC does not have to file an NPRR.

The vote was conducted by email after a previous version was rejected on May 27 in a similar email vote. Direct Energy offered revisions that removed a real-time deployment price adder from the original language. (See “Members Disagree over Change to ERS’ Return,” ERCOT Technical Advisory Committee Briefs: May 27, 2020.)

NPRR1006 passed by a 26-0 margin and now goes before the board during its June 9 teleconference. The measure failed 4-20, with two abstentions, the week before.

NPRR1066’s implementation is expected to cost between $140,000 and $180,000 and take up to nine months.

June 4, 2020

PJM TOs Outline End-of-life Tariff Amendments

Stakeholders challenged a proposal by transmission owners to amend the PJM Tariff regarding end-of-life (EOL) projects, accusing them of attempting to take power away from the RTO in the Regional Transmission Expansion Plan (RTEP) process.

The two-hour debate at the Transmission Owners Agreement-Administrative Committee (TOA-AC) on Monday came on the heels of a contentious vote at the Markets and Reliability Committee meeting May 28 in which a “joint stakeholders” proposal from American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others was narrowly defeated. (See PJM End-of-life Proposals Fail at MRC.)

Financial Traders Joined TOs in Opposition

The joint stakeholders proposal won 64% support in a sector-weighted vote in the MRC, just short of the two-thirds threshold required to send it to a final vote of the Members Committee.

A review of voting records indicates the TOs were aided in their opposition by financial traders within the Other Supplier (OS) sector. The OS voted 22-15 against the stakeholders’ proposal at the MRC, with eight members abstaining.

When supporters of the proposal sought to suspend PJM rules to bring the issue to a vote of the MC despite falling short in the MRC, the OS voted 21-14 against the move, with three abstentions.

The MC reported that 13 of 15 financial traders in the sector opposed suspending the rules, with one abstention. Ten of the companies that voted against the suspension are represented by attorney Ruta Skučas of Pierce Atwood. Had the joint stakeholders been able to flip four OS votes at the MRC, the measure would have passed.

In an interview, Skučas acknowledged casting the votes on her clients’ behalf but declined to say why the traders opposed the proposal or how the EOL issue affects them.

PJM end-of-life — Thirteen of 15 financial traders voted against considering the joint stakeholders’ end-of-life proposal at the Members Committee meeting May 28. Ten of those that voted “no” are represented by attorney Ruta Skučas. | *PJM*

“Part of this is being a member of a stakeholder body and working in coalitions and working in groups regardless of whether you’re directly affected,” she said.

Asked whether the traders had formed an alliance with the TOs, Skučas said, “I don’t want to go into specifics,” adding, “There are a number of TOs who engage in [financial transmission rights] trading.”

The traders could be calling in their chits soon, as PJM is planning to hire a consultant to recommend whether the RTO’s FTR and auction revenue rights (ARRs) markets should be changed to ensure more of the benefits go to load-serving entities rather than financial traders.

PJM’s draft of the proposed scope of work poses nine issues for the consultant to address, one-third of which question the current market’s balance between LSEs and other market players. Among the questions is whether “aspects of the current mechanism … result in profits to non-load-serving participants without commensurate or associated benefit to load.” (See PJM ARR/FTR Review Could Pit LSEs vs. Financial Traders.) The ARR/FTR Market Task Force is scheduled to meet June 17 to discuss the work scope.

M-3 Presentation

During the TOA-AC webinar Monday, Chad Heitmeyer, director of RTO policy for American Electric Power, gave a presentation on the TOs’ proposal to amend Attachment M-3 of the Tariff. Comments on the TOs’ proposal are due June 8, with the TOA-AC set to vote on it at its meeting June 10.

Heitmeyer’s presentation was similar to one he gave at a special meeting of the MRC on May 15. (See TOs Back PJM End-of-life Proposal.) He said PJM’s grid faces degraded performance and a heightened risk of failure as it nears obsolescence. The RTO has sai d two-thirds of all system assets are more than 40 years old, and more than one-third are more than 50 years old.

“It’s clear the system vital to our daily lives is aging,” Heitmeyer said.

The current M-3 process provides significant transparency, requiring stakeholder review of supplemental projects a minimum of three times prior to inclusion in the PJM plan, Heitmeyer said. He said the new language will increase transparency and improve planning coordination with PJM while honoring the TOs’ rights and responsibilities over asset management.

On May 7, the TOs gave notice that they were supporting the principles of a PJM EOL package and considering a Federal Power Act Section 205 filing to revise the Tariff to implement it. PJM’s proposal would require TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions. The RTO’s proposal also failed to win consensus, with a sector-weighted vote of 1.77 (36%) at the May 28 MRC meeting.

Heitmeyer’s presentation included the red line changes proposed by the TOs in the Tariff, which include new sections on procedures for identifying and planning EOL needs and the coordination of EOL planning with PJM.

Process Challenged

Before Heitmeyer started his presentation, Ed Tatum of AMP questioned the process by which the TOs decided to announce the potential Section 205 filing, saying he didn’t recall a vote at the TOA-AC. Tatum is a member of the TOA-AC through AMP Transmission.

Takis Laios of AEP, the outgoing chair of the TOA-AC, said a “supermajority” of the TOs had approached him and said they had the votes necessary for a Section 205 filing they wanted to take before stakeholders.

“It’s not the proper manner of acting for a select number of TOs to make unilateral decisions and couch it on behalf of the TOA-AC,” Tatum said.

Sharon Segner, vice president of LS Power, said the TOs’ proposed Tariff amendments could lead to “fairly significant” changes in the RTEP process and were “significantly more expansive” than the language in PJM’s proposal. She asked the TOs for a page-turn review of the proposed amendments.

FirstEnergy’s Jeff Stuchell, the incoming chair of the TOA-AC, said a page-turn of the amendments had not been planned because of the scheduled length of the meeting and the time involved in a full review.

Segner asked to review the first page of proposed definitions as an “interesting place to start,” pointing to the definition of an “Asset Management Project,” which is “any modification or replacement of a transmission owner’s transmission facilities that results in no more than an incidental increase in transmission capacity undertaken to perform maintenance, repair and replacement work, to address an EOL need, or to effect infrastructure security, system reliability and automation projects the transmission owner undertakes to maintain its existing electric transmission system and meet regulatory compliance requirements.”

Segner said the definition seemed similar to language contained in two CAISO orders FERC issued in September 2018 (EL17-45 and ER18-370), which she said did not define “asset management” or “incidental increase.”

The TOs would define “incidental increase” as “an increase in transmission capacity achieved by advancements in technology and/or replacements … which is not reasonably severable from an asset management project.”

Attorney Don Kaplan, representing the TOs, said the definitions were included in the proposed amendments because of stakeholder input and that the crafted language “broadly” defines asset management and incidental increase to comply with the California orders.

Kaplan said amending Attachment M-3 is permitted for the TOs if approved by FERC and that definitions can be codified given that they are consistent with applicable law.

“This is an expansion of stakeholder consultation and opportunity for input, which is not required by Order 890, and is beneficial to the planning process,” Kaplan said.

Segner asked Kaplan why the EOL projects wouldn’t be handled in the RTEP process versus Attachment M-3.

Kaplan said projects would be handled in the RTEP if they were expansions or enhancements and they were needed to address PJM planning criteria. He said the TOs’ focus was projects that are not needed to address PJM planning criteria.

Segner cited language giving the TOs responsibility for planning and constructing “any other transmission expansion or enhancement of transmission facilities that is not planned by PJM to address … planning criteria,” including NERC reliability standards, individual TO planning criteria, criteria to address economic constraints, “state agreement” projects or RTEP projects.

Segner said the proposed language seemed to reduce the types of projects that are regionally planned. “It looks like a [power] grab to me,” she said.

Kaplan said the first four categories are the only planning responsibilities that have already been transferred from the TOs to PJM. Kaplan said the last clause expands the coverage of Attachment M-3 to projects not delegated to PJM.

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.)