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November 18, 2024

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BPA Weathers Early Disruptions in Western EIM

The Bonneville Power Administration experienced two major “price excursion” events in the Western EIM within two weeks of joining the market on May 3, agency staff recounted Thursday. 

“This transition [into the WEIM] has not been without trial and tribulation,” Mark Symonds, BPA director of commercial operations, said during an agency workshop to discuss WEIM implementation issues.

In the first event, occurring May 8, an “external technical issue” caused the BPA’s territory to separate from CAISO’s WEIM for more than four hours. BPA attributed the market disruption to the expiration of a third-party software vendor’s digital certificate, which prevented energy transfer schedule tags — or e-tags — from flowing into the market system. 

As a result, inaccurate base schedules were submitted to the market, producing “unusual dispatches” and extremely high and low prices, Elsa Chang, BPA’s EIM program manager, told stakeholders during the workshop.

The May 8 issue started at about 9:30 a.m. PT, and WEIM prices in the BPA balancing authority area dropped deeply into negative territory at about 10:45 a.m., then rebounded to over CAISO’s $1,000/MWh energy bid cap just before 2 p.m. What followed was a series of wild fluctuations between those two levels, with prices topping $1,000/MWh and then dipping below the bid floor of $155/MWh. No other adjacent BAAs participating in the WEIM experienced similar price excursions.

After prices broke $1,000/MWh, BPA isolated itself from the market at 1:50 p.m. and remained separated until 4:10 p.m., Chang said.

“Once our vendor got notified, this issue was resolved quickly,” and BPA re-entered the market, she said.

Chang explained that market participants will not be billed or paid at the extreme prices that occurred during the episode. Instead, the event triggered CAISO’s administrative pricing, which in this circumstance is based on the last available prices before the disruption (hour ending 11 a.m.): $54/MWh for the 15-minute market and $42/MWh for real-time deliveries.

“We had exited operationally from the dispatches in the EIM, but that does not mean that we exited from the settlement provisions, which is why the CAISO utilizes this repricing methodology consistent with their tariff,” Symonds said in response to a stakeholder question. “Those prices have been established by the ISO and are flowing through the initial settlement statements received by all participating entities in the EIM.”

Donations Sought

The second price excursion event occurred May 18 after a small plane crashed near the Pacific AC Intertie, causing a curtailment of transmission schedules that cut transmission capacity for about 700 MW of BPA’s scheduled generation. 

The result was a temporary surplus of generation in the BPA BAA before the agency could decrease output from its resources. In the interim, BPA was compelled to increase its dispatch into the WEIM and export more power through the market, causing BPA’s WEIM prices to decline to below -$500/MWh for three five-minute intervals.

Symonds said a final verdict on the extreme negative prices was still pending in CAISO’s price validation process. 

“There are multiple reasons for which CAISO can and does routinely make price corrections. … At last check, they had not yet made their determination on this [event], and this particular trade date has not yet been settled,” he said.

Symonds cited both events in an appeal for regional stakeholders to “donate” unused transmission capacity to the WEIM to facilitate more transfers into and out of the BPA system, which will help avoid further price excursions. While BPA’s prices have tracked with those of other WEIM participants, “we appreciate that additional transmission can always help,” he said.

Symonds said also that additional transmission donations could assist with the more challenging conditions expected this summer.  

“When there are high load events, particularly in the south, for example, there may be benefits of additional export capability to bring Northwest generation down to California, or in other events where we may be seeking to find additional loads for generation out of the Northwest, it can be helpful to also have export capability,” he said.

On the flip side, referring to the record-smashing heat wave the Northwest experienced in June 2021, Symonds said, “It would be good to have that import capability as well.”

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MISO to Limit Market Error Resettlement Times

MISO intends to adjust the time it allows itself to retroactively correct market-pricing errors, stakeholders learned during a Market Subcommittee meeting Thursday.

The RTO’s markets can experience two types of pricing errors: implementation errors and continuing errors. Market-implementation errors are meant to be remedied near the operating day, with corrections made in time to be used in settlements. Continuing errors, on the other hand, are those discovered after settlement and could require up to two years of resettlements “from the date of MISO’s formal acknowledgement.”

MISO will seek FERC permission to impose a two-week limit on implementation errors and a one-year resettlement timeframe for continuing errors that begins ticking when the grid operator acknowledges the error in writing. Staff’s Daric Moenter said the RTO intends to file tariff changes in the third quarter for commission approval.

Under the proposal, implementation errors will be “identified, investigated and corrected” within two weeks. If they’re not discovered in time to be remedied within the two-week window, they will be subject to corrective settlements through the continuing error process, provided the pricing error meets a threshold of $100,000 or 0.5% of gross market activity per affected operating day.

“The recommended changes ensure that price accuracy is as important as certainty and permanency,” Moenter said.

Laura Rauch, senior director of transmission planning, said MISO is trying to strike a balance between correcting significant pricing errors and not spending “thousands to chase pennies.”

As an example, she said it would take millions of dollars of staff hours to make corrections two years back in addressing a daily settlement error.

Moenter said staff hope to avoid spending “an ordinate amount of staff time” on insignificant pricing errors. He said going back two years to reprice errors in the day-ahead and real-time systems can quickly become burdensome.

WPPI Energy’s Valy Goepfrich said she didn’t see any problems with the existing repricing policy and said she didn’t understand why MISO proposed the changes.

Stakeholders have said that during messy weather events, MISO employees probably don’t have time within the two weeks to review pricing and apply substitution logic to correct errors before they’re settled.

“Everything isn’t always clean and tidy here, and we’ve seen that,” Xcel Energy’s Kari Hassler pointed out in April.

Moenter asked for stakeholder feedback on the repricing proposal through June 10.

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MISO Curbing Use of Emergency Commitment Statuses

CARMEL, Ind. — MISO said it will limit when some resources can use an emergency commitment status outside of emergency conditions, hoping to prod a more available resource fleet.

The restriction is poised to mostly affect units designated to meet the grid operator’s resource adequacy requirements. Currently, such resources can use an emergency commitment status in the energy markets, making their entire output unavailable unless there’s a generation emergency. The emergency commitments don’t affect the resources’ capacity credits. (See MISO Moves to Restrict Emergency Commitments.)

MISO market design adviser Dustin Grethen said the proposal will allow the RTO’s operators to deploy units designated for resource adequacy requirements in anticipation of tight conditions, much like MISO’s registered load-modifying resources.

“Operators are counting every megawatt when they are tracking a potential shortfall of needed capacity,” Grethen said during a Resource Adequacy Subcommittee meeting Wednesday.

MISO reported that during the 2020-21 planning year, approximately 22 GW of resources used the emergency-only commitment status about 20% of the time.

Grethen said MISO will allow emergency commitment status’s use under four conditions. He said the grid operator is proposing three conditions where a unit can use the status without first seeking permission from the Independent Market Monitor:

  • when the unit is at its permit limit, where its top range can only be accessed in a declared emergency;
  • when the unit is experiencing a “severe” energy limit, such as a fuel shortage, that keeps the unit from responding to capacity emergency conditions; or
  • in situations where operating the unit would go against “good utility practice” because the unit risks damage if it operates under high temperatures, high pressure or vibrations, or leaks or cracks in equipment.

MISO is also proposing a “catch-all” condition, where a unit can use the status if it consults with and receives permission from the IMM ahead of time, or while a limiting factor is occurring.

Grethen said MISO wanted a “catch-all” category because the three conditions won’t likely cover all scenarios where a unit needs to use the emergency commitment status.

Stakeholders have said that a unit sometimes uses an emergency-only status for inspections, tours, testing, quick maintenance or because of emissions limits.

MISO wants the changes enacted in time for the 2024-25 planning year.

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ERCOT Technical Advisory Committee Briefs: May 25, 2022

Stakeholders, Staff Try for Consensus on Gen Outage Approvals

ERCOT stakeholders and staff are continuing to hash out their differences and reach a consensus over the grid operator’s methodology for approving and denying planned generation maintenance outages.

Staff said they will review comments from stakeholders on the maximum daily resource planned outage capacity (MDRPOC) calculation, the key feature in ERCOT’s plan to evaluate outage requests. They plan to bring the revised methodology to the Board of Directors for its approval during its June 21 meeting.

In the meantime, staff agreed to hold a workshop on the MDRPOC calculation and to give the Technical Advisory Committee a chance to consolidate the three sets of comments generation members provided. They have said ERCOT’s goal is to allow as much capacity and flexibility as possible for planned outages while maintaining reliability.

The complex calculation takes installed thermal resources’ seasonal capacity, installed intermittent renewable resources’ capacity and other available capacity, and adds them together. It then subtracts from that targeted reserve capacity, forecasted reduction from price-responsive demand and other inputs.

Staff said using planned outages from last year, the highest since 2019, the proposed methodology’s calculated maximum outage capacity provides at least 20% additional margin for through 2026. They said the MDRPOC would require some outages to be moved earlier in the spring and later in the fall.

Woody Rickerson, ERCOT vice president of system planning and weatherization, said staff compared the calculation with what has been used in the past as an aggregate for the fleet and found the new methodology allows 10 to 15% more outages.

“I think that the methodology is such that there are some places that can be adjusted,” he said. “If we started having a number of planned outages that can’t be fit, then we can look at some of these dials.”

Staff have agreed to stakeholders’ request to regularly review the methodology and provide annual updates to TAC. They offered to track the number of outages denied for being over the MDRPOC but said it would be too time-consuming to post inputs used to calculate the cap, noting that the process will be automated.

“For any given point in time, we could do ad hoc reports,” Rickerson said. “Setting up something that shows every hour for five years is a bigger project and takes more time. This whole process is meant to be adjusted.”

The board in April granted staff’s appeal of a revised nodal protocol revision request (NPRR1108) that gives the grid operator the authority to review, coordinate and approve or deny all planned generation maintenance outages. Stakeholders earlier rejected staff’s version of the measure, unanimously approving an NPRR as amended by several joint commentators. (See ERCOT Board of Directors Briefs: April 28, 2022.)

Staff drafted NPRR1108 to meet the requirements of legislation passed last year in the wake of the February winter storm that led to the near collapse of the Texas Interconnection. Senate Bill 3 included a provision that the grid operator “shall review, coordinate and approve or deny requests by providers of electric generation service … for a planned power outage during any season and for any period of time.”

ERCOT’s Credit Limits Align with Others

ERCOT staff told the committee that the grid operator’s unsecured credit limits process aligns with those of the six other U.S. grid operators. They limit counterparties to a $50 million cap in unsecured credit, as does ERCOT, with the total amount of outstanding unsecured credit ranging from approximately $100 million to $1.75 billion. ERCOT currently has about $1.4 billion in outstanding unsecured credit.

The ERCOT board requested the information after tabling NPRR1112 in April. The revision request lowers the unsecured credit limits to $30 million and was approved by TAC in April over staff’s objections. ERCOT then appealed the decision to the board.

Director John Swainson said during the April meeting that TAC’s argument “should raise a level of doubt in the board about the wisdom of proceeding” with the approach.

“We’re not going there to propose anything other than providing information they wanted,” ERCOT’s Mark Ruane said. “If the board feels it’s appropriate, we are certainly at any time willing to discuss looking at the credit rules as they currently stand.”

A 2013 decision by the Commodity Futures Trading Commission exempted grid operators from some legislative provisions. It disallowed the use of unsecured credit to cover credit exposure from financial transmission rights and reduced caps on unsecured credit limits to no more than $50 million per counterparty.

TAC Vice Chair Bob Helton, with Engie North America, said he will work with ERCOT staff to ensure the committee has an advocate for its position when the issue comes up again before the board.

Members to Work on Board Relationship

TAC’s leadership is working with ERCOT staff to set up a work session, tentatively scheduled for June 14, to consolidate around new processes for interacting with the grid operator’s new board.

Helton said he and Chair Clif Lange, who was absent from the TAC meeting, have had several discussions with the new board members that he termed “very positive.”

“It was apparent that the board was trying to indicate they completely see the need for the stakeholder process and TAC, and that they want to take full advantage as they can … of the talent and the knowledge of the stakeholder process and TAC,” Helton said. “We felt really pretty good about that coming out of” the meetings.

He said there is no plan to have the committee report to the board’s new Reliability and Markets committee, but that TAC will need to decide how it communicates with both the full board and the new committee. TAC members also plan to review the appeals process at the board and develop a way to consider revision requests requested by the Public Utility Commission on a separate track, Helton said.

The board wants TAC to comprise members that “have the ability to make the decisions and move things forward,” he said, “rather than having to take things back to their company all the time.”

“You don’t need to be an officer of the company,” Helton said, referring to an issue first raised last summer. (See ERCOT Technical Advisory Committee Briefs: July 28, 2021.)

Helton and Lange plan to take the work session’s results back to the full TAC for its June 29 meeting. They face a July 11 deadline to get their information back to the board.

$1.2M to be Uplifted to Market

Staff told the committee that more than $1.2 million in nonemergency short pays from the 2021 winter storm won’t be covered by securitization and will have to be recovered by an uplift to the market. ERCOT was to begin invoicing the funds on Friday and will begin distributing the funds to short-paid entities during the next several weeks.

Retailer Entrust Energy, which went into bankruptcy last year, owes the bulk of the $1.2 million.

ERCOT issued a market notice May 20 with the estimated cumulative aggregate short-paid amount at $2.3 billion. Much of that is owed by Brazos Electric Power Cooperative, currently in bankruptcy proceedings over the nearly $1.9 billion it owes the market.

TAC Honors Uvalde Shooting Victims

Helton asked for a moment of silence for those who died in the mass shooting the day before the meeting in Uvalde, only 160 miles away from ERCOT’s Austin headquarters.

“We live in a cruel world, an unsafe world, an unforgiving world,” he said. “I can’t imagine as a parent going through that … having to go through the tragedy of the loss of a child.”

Disconnected Load Still to be Served

The committee unanimously approved NPRR1100, which clarifies that a generation or energy storage resource (ESR) may serve customer load when the customer and the resource are both disconnected from the system because of a transmission or distribution outage. It is limited to configurations where the resource and customer load are using privately owned transmission and distribution infrastructure during a private microgrid island operation. The NPRR recharacterizes the load from wholesale storage (WSL) to non-WSL on an operating day basis as necessary to ensure the ESR load not eligible for WSL treatment is not provided WSL treatment.

The measure was voted on separately from the combination ballot, which also passed unanimously. The combo ballot included five other NPRRs and single changes to the Nodal Operating Guide revision (NOGRR) and the Planning Guide (PGRR):

    • NPRR1110: modifies the black start service (BSS) confidential information, contract period and backup fuel requirements; increases the BSS procurement period from two to four years; and adds an on-site 72-hour priority fuel requirement that can be waived in whole or in part to procure a sufficient number or preferred combination of resources.
    • NPRR1119: deletes extraneous protocol language that should have been removed as part of NPRR978.
    • NPRR1121: automates the market notice used in the exceptional fuel cost submission process to notify market participants when the costs have been submitted for the operating day.
    • NPRR1129: allows ERCOT to post on its website a list of electric service identifiers for transmission-voltage customer opt-outs from the securitization of $2.1 billion for load-serving entities’ extraordinary costs incurred during the 2021 winter storm.
    • NPRR1130: extends the sunset date for weatherization inspection fees from Sept. 1, 2022, to July 31, 2023.
    • NOGRR240: establishes frequency and voltage ride-through requirements for new DC ties interconnecting with ERCOT after Jan. 1, 2021, and the ties that will be modified.
    • PGRR100: revises the annual planning model base case update frequency from triannual to biannual, aligning it with the Steady-State Working Group’s plan to adjust its current case-building schedule to a biannual basis.

The ballot’s passage also approved the Large Flexible Load Task Force’s charter and leadership. Bill Blevins, ERCOT director of grid coordination, will chair the group, and consultant Bob Wittmeyer, who primarily represents municipalities and cooperatives, will serve as vice chair.

The task force is developing policy recommendations for integrating large flexible loads into the ERCOT system. It met May 24 to discuss interconnection issues and divvy up work assignments.

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MISO Makes Business Case on Long-range Transmission Plan

MISO members began an email vote last week on whether to recommend MISO’s $10 billion long-range transmission plan to the Board of Directors as staff made final pitches for the project portfolio.

The members’ advisory vote was originally slated to take place during a special Planning Advisory Committee (PAC) teleconference Friday, but some requested voting by email.

Voting will conclude June 6. The $10.3 billion, 345-kV package will then advance to the board’s System Planning Committee for its consideration. The full board will hold a final vote on the portfolio in July.

Presenting the long-range transmission plan’s (LRTP) business case to board members on Thursday, Vice President of System Planning Jennifer Curran said the plan is “critical” to MISO serving load as the footprint transitions to a new resource mix.

Curran called the initial search for long-range projects “one of the most if not the most complicated studies” MISO has ever undertaken. She said staff have been studying the transmission “in earnest” since 2020.

“That seems like a long time, but it’s really quick considering the amount of transmission analysis and the magnitude of it. … It’s been a lot in a short amount of time,” she said.

Curran said the package is MISO’s “least-regrets” assembly of projects based on a “conservative view” of members’ clean energy and decarbonization goals. She said staff will soon begin studying the LRTP’s second phase of possible projects “because the world continues to change aggressively.” That portfolio will contemplate a more rapid resource evolution and could yield projects with higher voltages than 345 kV.

MISO plans to continue monthly stakeholder workshops to discuss the second batch of LRTP solutions.

The RTO said its first portfolio will mitigate future excessive loading on existing lines and prevent possible voltage collapse across the Midwest. It anticipates the LRTP portfolio will yield anywhere from $23 billion to about $52 billion in financial benefits over 20 to 40 years of the projects, a 2.6:1 overall benefit-to-cost ratio. The grid operator estimates Midwestern cost-allocation zones will see cost-to-benefit ratios ranging from 2.1:1 to 3.2:1.

Long-range transmission plan (MISO) Content.jpgMISO’s benefit estimates for the first cycle of its long-range transmission plan | MISO

During the PAC teleconference, Clean Grid Alliance’s Natalie McIntire said MISO’s benefit estimates are cautious and said there are likely more unquantified benefits, especially reliability improvements.

The RTO has reduced the portfolio’s costs to $10.32 billion from $10.38 billion. It expects the 20- to 40-year present value of the projects’ total revenue requirement to range from $14.2 billion to $16.9 billion.

“Some of the projects increased in cost, some decreased in cost,” Jarred Miland, senior manager of transmission planning coordination, said. He said the portfolio is targeted to be in service by 2030, but that final in-service dates and costs are still subject to change.

MISO’s Joe Reddoch said staff will monitor long-term inflation trends and update cost projects if inflation materially affects construction costs.

Making Use of Existing Routes

Aubrey Johnson, the grid operator’s vice president of system planning and competitive transmission, said about 90% of the first LRTP portfolio will use existing and adjacent rights of way, or “yellow fields.” He said the planning team paid careful attention to where transmission lines could use existing rights of way.

“We think this will be a significant contributor to the speed of the regulatory process,” he said.

Director Nancy Lange, a former Minnesota commissioner, asked whether MISO expects any of the projects to be delayed or rejected by state regulators.

Johnson said though all state regulatory processes are different, using existing transmission routes should maximize the projects’ prospects.

MISO President Clair Moeller said states realized that the grid operator’s last long-range transmission projects in 2011 worked as a portfolio and were “quite responsive” to the proposal. He acknowledged that the Cardinal-Hickory Creek line remains in legal limbo a decade later over a planned river crossing route in Wisconsin. (See Enviro Groups Push Wis. DNR to Scrutinize Cardinal-Hickory Creek Line.)

However, Minnesota Public Utilities Commission staffer Hwikwon Ham warned during an earlier Market Subcommittee meeting last week that the first LRTP portfolio could temporarily increase the already high congestion levels because construction will be carried out very close to existing lines in the footprint.

OMS Hears Different Benefits Perspective

The Organization of MISO States recently hired an engineering firm to conduct an independent review of the LRTP, which the firm called a “comprehensive assessment.”

RLC Engineering’s Rick Conant said during an April OMS board meeting that the first cycle of projects doesn’t resolve all of MISO’s overloading issues. He said more thermal fixes would likely arrive with the second cycle of long-range projects.

However, RLC said it arrived at a 1.4:1 B/C ratio for the first group of projects, smaller than MISO’s overall projection of 2.6:1. The firm’s Waine Whittier said despite the findings, the projects still are beneficial to pursue.

OMS has not made the RLC study public, though its members have discussed the results in open meetings.

Competitive Bidding Question Remains Open

MISO will release a draft list of long-range facilities that will be considered for competitive bidding by June 1. Johnson said staff are still analyzing “the competitive landscape.”

Also last week, the RTO made a FERC filing to change its competitive transmission process to exclude “short segments and conductor-only” work from competitive bidding eligibility (ER22-1955). Brian Pedersen, senior manager of competitive transmission administration, said some smaller projects will be necessary to accommodate the long-range projects and “are not best suited for competition.”

Some members said they were taken by surprise that MISO would file the tariff changes without first consulting the stakeholder community.

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NYISO Monitor Proposes Capacity Pricing Overhaul

NYISO’s Market Monitoring Unit is recommending a new capacity market pricing structure that it says would lower costs and improve incentives for market participants making long-term investments.

Presenting highlights of the Monitor’s 2021 State of the Market Report to the Management Committee on Wednesday, Potomac Economics’ Pallas LeeVanSchaick said that the current processes for setting the installed reserve margin (IRM) and locational capacity requirement (LCR) “aren’t well coordinated with each other.”

“It is not possible for the NYISO to address the concerns discussed above in a piecemeal fashion,” the report says.

It proposes to institute an overhauled capacity market pricing structure, dubbed locational marginal pricing of capacity (C-LMP).

The market has just four fixed pricing regions, so when transmission constraints arise within one, it can lead to inefficient results. For example, in recent years the Monitor has observed bottlenecks going into Western New York capacity zones from Central New York zones, and from Staten Island into the rest of New York City, that are not represented by the current capacity zone configuration, the report said.

“We’ve seen that the lack of a treatment of constraints upstate has accentuated some of the fluctuations in the IRM and LCRs,” LeeVanSchaick said. In addition, “the LCR optimizer has a flawed objective function. … It’s not only that it doesn’t find an efficient solution; it’s also problematic because there are aspects of it [overly sensitive to small changes in inputs] that contribute to more volatility in the requirements.”

These constraints can be a barrier to entry for new resources, which are required to pay for transmission upgrades to receive capacity rights if they are not fully deliverable throughout their entire capacity region. Offshore wind and battery projects in Long Island were recently assigned costly deliverability upgrades that are not required of incumbents that are limited by the same constraints, the report said.

Potential New Entry and Retirement Trends (Potomac Economics) Content.jpgPotential new entries include intermittent renewables principally motivated by REC solicitations and potential retirements include a number of dual fuel peaking units leaving through 2025. | Potomac Economics

The report says C-LMP would:

  • “produce more granular prices that are better aligned with NYISO’s planning criteria;
  • be more adaptable to changes in resource mix and transmission flows;
  • remove unnecessary barriers to new entry in the interconnection process;
  • be less burdensome for the ISO to administer; and
  • reduce the overall costs of maintaining reliability.”

“There are some emerging concerns that we see with potential new entry and retirements,” LeeVanSchaick said. “On the new entry side, of course, it’s a lot of intermittent renewables that are principally motivated by [renewable energy credit] solicitations, and on the potential retirement side you have of course Indian Point 3 in 2021. But then you’ve also got a number of dual-fuel peaking units leaving as well through 2025.”

Price Trends

All In Price Trends (Potomac Economics) Content.jpgAll in price trends | Potomac Economics

LeeVanSchaick also discussed pricing trends over the last few years. Gas prices are clearly driving energy prices, but they are not the single biggest factor, he said.

“We saw a big increase from 2020 to 2021, not only [because of] gas prices but certainly the Indian Point nuke retirements that are ongoing,” LeeVanSchaick said. “Between those two years it certainly is contributing to the higher prices in Eastern New York. We [also] saw more planned and forced transmission outages in 2021.” Last year also saw extra high levels of forced transmission outages into Long Island.

“Lastly we saw the return to normal consumption patterns, or more normal, in 2021 than they were in 2020 from COVID,” LeeVanSchaick said. “We saw higher gas prices, higher electric demand [and a] very large reduction in capacity prices in New York City.”

EAS Market Recommendations

The Monitor also recommended changes to the energy and ancillary services markets, including to compensate reserve providers that increase transfer capability by allowing use of higher line ratings; increase the reserve demand curve for statewide requirements to reduce out-of-market actions and reflect risk to load; eliminate offline fast-start pricing, which undermines incentives for flexible resources; and model transient voltage recovery (TVR) constraints on the East End of Long Island in the energy market.

Increased penetration of intermittent or variable generation will accentuate the need for these changes, the report says, and the evolving resource mix will increase the need for longer lead time reserves to address net load forecast uncertainty.

“This is potentially reserves that don’t have to be 10 or 30 minutes; they can be potentially just available in an hour, two hours, three hours or four hours; but it would be in a time frame that would allow the NYISO to meet what are going to be increasing requirements for reserves to deal with that load forecast uncertainty,” LeeVanSchaick said.

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Climate Change Impacting Northwest Streamflows, Hydro Planning

Climate change will have a mixed impact on hydroelectric output in the Pacific Northwest, resulting in wetter winters and springs and drier summers, according to the Bonneville Power Administration.

The changing weather patterns are altering the way the federal power marketing agency plans for the future, prompting it to shorten its look-back period for developing long-term forecasts, Erik Pytlak, BPA’s lead meteorologist, said last week.

“BPA has been looking at climate change for over a decade now, and we have been anticipating for some time that, as the climate continued to gradually warm, what would start happening eventually is it would start impacting our streamflows,” Pytlak said during a WECC summer readiness workshop May 24.

The agency has performed two studies showing that — unlike in the Southwest — the Pacific Northwest will not experience a decrease in streamflow volumes if climate change continues.

“The entire WECC tends to get lumped in as the same climate response, and that’s just not the case. … We have a very varied climate in the West, and so with climate change the responses are going to be different as well as you go from north to south,” Pytlak said.

Pytlak pointed out that the PRISM Climate Group at Oregon State University, which updates its 30-year weather data set every 10 years, recently dropped the relatively cool 1980s and added the warmer 2010s. The group’s data shows that much of the country has warmed 0.5 degrees to 1.5 degrees Fahrenheit in the last 10 years.

PRISM data also indicates that the Northwest’s “precipitation signal” has been different from the rest of the West.

“In the last 10 years or so, while the Southwest on an annual basis has gotten drier, the Pacific Northwest has actually gotten a little wetter. And in the key snowpack areas, it is actually notably wetter, particularly in the Cascades of Washington, parts of Montana and British Columbia,” Pytlak said.

Joint climate models produced by BPA, the U.S. Army Corps of Engineers and the federal Bureau of Reclamation show winters in the Northwest getting wetter over the next 20 to 30 years, with the most increased precipitation farther north in Canada, he added.

An Era of ‘Non-stationarity’

BPA predicts that the most “profound change” will be seen in the region’s streamflows, with higher fall, winter and early spring flows by the 2030s, and peak runoff coming earlier in the spring. The latter assumption is based on the fact that peak spring runoff has already shifted to several days earlier since the 1980s — a “statistically significant” amount, according to Pytlak. The agency also sees the likelihood for more extreme flood events in the colder months. 

Stream flows in June, normally a peak period in the Northwest, are likely to decline, followed by a longer period of lower summer flows as the region’s already dry summers become hotter and drier and electricity use increases because of cooling demand.

“We have seen a slight decrease in summer flows that is not statistically significant yet, but it is close, and you can kind of guess that, if these [climate-driven] things continue, and that shift does continue to occur, that statistical significance will show up here relatively soon,” Pytlak said.

The region’s climate is now in an era of “non-stationarity,” according to Pytlak, “where the past does not necessarily predict the future” with respect to weather. 

In response, BPA has already adopted a shorter period-of-record for the ensemble streamflow projection runs it uses for its medium-term planning, switching from 1948-2015 to 1981-2018. It has also updated the long-term temperature data it uses to forecast loads, moving from 1970-2005 to 2005-2019.

For future long-term planning, BPA is proposing to base its stream flow assumptions for hydroelectric forecasts on only the most recent 30 years of data (1989-2018), rather than looking back over the last 90 years.

As a result, BPA planners will expect to have more generation available from December to March — a period of potentially decreasing demand caused by warmer conditions — and less available from July to September, when demand is expected to rise. 

“What the most recent 30 years [of data] is starting to show, if we were to switch to that, it should help us keep up with what the climate projections are showing over the next 30 years, which is an increasing amount of water in the wintertime and early spring, which should equate to more generation. But the trade-off is a longer period of low summer flows in that July and August period, which means lower potential with generation going forward,” Pytlak said.

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Texas RE Knocks AEP for Communication Breakdown

FERC on Friday approved the Texas Reliability Entity’s settlement with American Electric Power (NASDAQ:AEP) for communication lapses during a 2018 load loss incident.

The agreement was the only violation filed in NERC’s public spreadsheet notice of penalty for April (NP22-24), though the organization also filed a separate non-public spreadsheet NOP in the same docket, its normal practice when dealing with violations of the Critical Infrastructure Protection standards. FERC said in Friday’s filing that it will not further review the settlements, leaving their judgments intact.

Texas RE’s settlement with AEP concerns requirement R8 of NERC reliability standard TOP-001-3 (Transmission operations), which mandates that a transmission operator inform its reliability coordinator, relevant balancing authorities, and other TOPs of “operations that result in, or could result in, an emergency.” Transmission Operators must be able to show that they have done so using operator logs, voice recordings, transcripts, electronic communications, or other evidence.

The regional entity discovered potential issues with TOP-001-3 during a compliance audit in 2019. Initially auditors attributed the noncompliance to requirement R1, but after further investigation determined that the utility was in violation of R8.

System Already Under Strain

The issue began on March 20, 2018. At the time several transmission lines serving the Del Rio, San Angelo and Mesa Verde area were out of service for planned construction and maintenance. AEP had also suffered a forced outage on another transmission line, meaning that only two 138-kV lines were available to serve the area that morning.

Beginning shortly before 11 a.m., AEP’s RC noticed several thermal limit exceedances in its real-time contingency analysis (RTCA). A generation solution was not available because the wind generation in the area was declining. AEP, the RC, and a neighboring TOP spent the next few hours trying to address the exceedances by bringing transmission facilities back online, while AEP also worked to raise voltage by activating a number of capacitor banks.

During these activities, AEP was also conducting its own RTCA in parallel to the RC’s. This is not required by NERC’s standards, but AEP does it voluntarily “as an additional check on its system,” NERC said. According to Texas RE, AEP’s RTCA “began to indicate a consistent, non-converged solution” around 12:20 p.m., but it failed to communicate this information to the RC during any of their subsequent calls at 12:26, 2:08, and 2:24 p.m. At 2:33, smoke from a grass fire led to a “local voltage collapse” and caused the loss of about 140 MW of load.

Texas RE said this failure to communicate AEP’s RTCA results to the RC constituted a breach of the standard, since it deprived the RC of “complete operation about the actual operations” of the utility’s system, though the RE acknowledged that the communication failure was not a cause of the underlying incident. It blamed the violation on inadequate processes and training: While AEP had protocols in place for communicating RTCA results to the RC, there was no specific procedure for operators to do so.

Although AEP’s violation occurred during a load loss event, Texas RE declined to press for a monetary penalty against the utility, saying that the communication breakdown did not specifically cause the loss of load. The RE also observed that AEP’s RTCA was voluntary and that the load loss would still have occurred if it hadn’t run the RTCA.

Texas RE noted that AEP has engaged in mitigating activities as well, including updating its processes to account for communicating issues with its RTCA to the RC and adding time requirements for doing so, along with training relevant staff on the new requirements. In addition, the utility conducted an extent of condition review of its protocols for communication with the RC that detected no further potential violations. The RE verified the mitigation steps were completed in January 2021.

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Michigan House OKs Nuclear Feasibility Study

LANSING, Mich. — Legislation requiring a study on the future feasibility of nuclear power in Michigan is in the Senate after being approved on a 85-20 bipartisan vote in the House.

The bill (HB 6019) was assigned to the Senate Energy and Technology Committee May 24 but has not been scheduled for a committee meeting.  A spokesperson for bill sponsor Rep. Graham Filler (R) said he had not been able to speak with Committee Chair Sen. Dan Lauwers (R) about the bill. Lauwers could not be reached for comment.

The measure moved as Entergy Nuclear (NYSE:ETR) shut down the Palisades nuclear plant May 20 after 50 years of operations. Entergy has agreed to sell the plant to Holtec Decommissioning International.

Last month, Gov. Gretchen Whitmer (D) called for the use of federal funds to help keep the plant in Covert Township, on the shores of Lake Michigan, open. (See Federal Aid Likely Too Late to Save Palisades, Diablo Canyon Nukes.)

Michigan Public Service Commissioner Katherine Peretick told Bridge Michigan that the state is in serious discussions with a company interested in buying Palisades and continuing to run the plant. She would not identify the company. She said such an agreement would be “a huge deal for the state.”

HB 6019 requires the PSC to hire a firm to assess the state for the possibility of adding nuclear power facilities and to report back in 18 months. The report would look at potential environmental affects, land siting issues, workforce training, the possibility of small modular reactors, workforce education and training, potential job creation, environmental justice issues, and the effect on state tax revenue.

The PSC has not taken a formal position on the bill. But a commission spokesperson said PSC chair Dan Scripps has said the commission will undertake the study if the legislature appropriates funds for the review.

In introducing the bill, Filler said Russia’s invasion of Ukraine proved to him the necessity that the U.S. and Michigan be energy self-sufficient.

Filler also said when he announced the bill that nuclear technology now allows for smaller reactors and more safety features and Michigan should investigate whether those are right for the state.

Palisades’ closure will make it more difficult for the state to meet its goal of becoming carbon neutral by 2050 by eliminating one of the state’s largest sources of clean electricity.

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FERC OKs New Queue Priority for MISO, SPP Seams Studies

FERC on Friday approved MISO’s and SPP’s plan to assign a new prioritization of projects to study in their respective interconnection queues.

The new priority will employ a “first-ready, first-served” approach in which the RTOs study the projects that are primed for interconnection first, rather than based upon the order in which they entered the queue (ER22-1533).

FERC said the new arrangement will provide more certainty by establishing a rank when the projects pass the queues’ first decision points instead of when they submit an interconnection request (SPP) or when they pay study fees (MISO).

The commission said the queues’ first decision-point deadlines are an appropriate touchstone because they’re “a point in time after most delays in the interconnection study processes occur.” The new priority should “reduce the possibility that lower-queued cycles or clusters will not have affected systems information from higher-queued cycles or clusters when major commercial decisions are made,” FERC said.  

The priority will be used for the RTOs’ system impact studies, affected system studies, and cost assignments for network upgrades. The grid operators study each other’s nearby IC generation projects for potential effects that might require transmission upgrades in their footprints. MISO and SPP assign network upgrades costs identified in interconnection studies based on queue priority.

The grid operators said their ongoing joint targeted interconnection queue (JTIQ) transmission planning study compelled them to reexamine queue priority to ensure higher-queued generation projects aren’t holding up more prepared but lower-queued projects. (See Midwest Energy Policy Series Addresses JTIQ Projects.)

The new approach is effective with the 2020 cycle of MISO interconnection requests and the 2017 cluster of SPP requests.

The RTOs said their current practice “can lead to situations where interconnection customers are required to make significant commercial decisions about the viability of their projects without knowing what network upgrade costs they will be assigned after projects with higher queue priority have been studied.”

EDF Renewables supported the change, saying that it is “often faced with having to execute a generator interconnection agreement 12 to 18 months prior to receiving final affected system cost responsibility.”

Invenergy said the new prioritization will improve cost certainty for IC customers but said the effective date leaves out customers that entered the MISO queue in 2018 and 2019 and are still awaiting SPP study results. (See CGA Requests MISO Help for Late-stage Interconnection Projects.)

But FERC said the “proposed transition point appropriately respects the expectations of existing interconnection customers while improving the affected system study process for new interconnection customers.” It declined Invenergy’s request to include the 2018 and 2019 MISO queue cycles in the new ranking.  

The change comes as MISO and SPP are proposing to do away with their affected system study process and instead conduct more frequent interregional studies like the JTIQ to get more generation online near their seams. (See SPP, MISO Propose Scrapping Affected System Studies.)