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July 30, 2024

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PJM OC Briefs: Oct. 5, 2023

Generators Cite Reasons for Low Synch Reserve Response Rate

VALLEY FORGE, Pa. — PJM presented feedback it received from synchronized reserve resources that have come up short in their response to reserve deployments since October 2022, when PJM implemented a market overhaul that was followed by a drop in reserve response rates. (See Synchronized Reserve Pricing Falls in PJM Markets After Overhaul.)

Resources responding to outreach from PJM and the Independent Market Monitor attributed portions of their shortfall to delayed, insufficient or incorrect action at their market operation centers. Factors included missing an all-call signal; not understanding how to respond to a spin event; and incorrect parameters, such as ramp rate, being reported in Markets Gateway.

Some generation owners said they had been operating under the Intelligent Reserve Deployment (IRD) rules that PJM had proposed, but which ultimately were rejected by FERC in August 2022. The IRD proposal would have included a level of reserves being requested from generators; however, the status quo requires that resources provide their full reserve obligation unless directed to do otherwise.

PJM sought to address the diminished response rate by increasing the synchronized reserve requirement by 30% in May, overriding a Markets and Reliability Committee (MRC) vote that rejected the increase. It also proposed to create the Reserve Certainty Senior Task Force to discuss changes to several components of the reserve market and how it operates. The task force has its first meeting on Oct. 10. (See “PJM Issue Charge on Reserve Certainty Approved,” PJM MRC/MC Briefs: Sept. 20, 2023.)

The RTO has published an FAQ and guidance for synchronized reserve resources to improve resource owners’ understanding of how the market functions and their obligations during a spin event.

PJM’s Melissa Pilong told the OC that close to 100 resources responded to the outreach, accounting for approximately 75% of the shortfall by megawatts over the past year. She said PJM’s goal is to find solutions that can allow the reliability requirement to be reduced back to 100% of the single largest contingency.

Stakeholders Endorse Outage Coordination Manual Revisions

The OC endorsed conforming revisions to Manual 38 to codify the outage coordination package the committee approved in June. (See PJM OC Briefs: June 8, 2023.)

The package adds coordination between utilities and PJM to identify potential extended outages, evaluate their impact and expand the outage information released by the RTO. The manual language will be considered by the MRC during its Oct. 25 meeting.

A competing proposal from the Monitor, which received 17% support in June, sought to increase transparency about late outages and impacts on transmission congestion.

PJM Proposes Quick Fix for Transmission Cut-in Process

PJM presented a quick fix proposal to allow the RTO to delay the end time of a cut-in ticket by one day if information regarding one of the “critical cut-in tasks” has not been supplied and extending the outage is not expected to pose reliability concerns. PJM will coordinate with the transmission owner to obtain the missing information prior to the line being energized.

The quick fix process allowed PJM to bring a problem statement and issue charge concurrently with a proposed solution. The OC is set to vote on the proposal Nov. 2, followed by the MRC on Nov. 15. If approved, the change would be effective upon MRC endorsement.

PJM’s Dean Manno told the OC that a one-day delay is being sought as review of the information can be done in that time once it’s received.

PJM Presents Recommended Winter Weekly Reserve Target Values

PJM’s Patricio Rocha-Garrido presented the recommended winter weekly reserve targets (WWRT) values for the 2023/24 winter, which call for a higher level of reserves for each month compared with last winter. The WWRT is used to inform the scheduling of planned outages during the winter to minimize the potential for maintenance to cause a higher loss of load expectation.

The recommended maximum monthly available reserves figure is 28% for December, 30% for January and 25% for February. The values for last winter were 21% for December, 27% for January and 23% for February.

Garrido said this year’s analysis included a higher forced outage rate in the historical data owing to inclusion of extreme weather during the 2014 polar vortex and the December 2022 winter storm. PJM historically had not included the polar vortex data in its analysis, but reversed that based on its experience during Winter Storm Elliott.

The WWRT is one of the three values produced through the annual Reserve Requirement Study. The Planning Committee voted on Tuesday to endorse PJM’s recommended installed reserve margin (IRM) and forecast pool requirement figures, both of which would increase the reserves PJM aims to procure for the 2027/28 delivery year. (See “First Read of 2023 RRS Values,” PJM MRC/MC Briefs: Sept. 20, 2023.)

Quick Fix for Public Conservation Request Guidelines Proposed

PJM proposed changes to its public notifications seeking reductions in electric consumption during emergency conditions to specify that the request is being made of all consumers, not just residential load, and to aim to better integrate the notification process into other emergency procedures. Additional ways that consumers can conserve energy also are included in the proposed language.

The proposed manual revisions also detail PJM’s reporting requirements to the Department of Energy, NERC and RF or SERC when a conservation request is made.

The revisions will be considered by the OC and MRC during their November meetings.

Periodic Review Revisions to Several Manuals Discussed

    • Stakeholders endorsed revisions to Manual 3A intended to clarify PJM’s quarterly data collection process for identifying outages that don’t yet have a network model ticket. The language also aims to clarify definitions of monitored priorities.
    • Revisions to Manual 3 seek to add detail around the documentation of stability limits and would add references to generation interconnection agreements when discussing interconnection service agreements.
    • The periodic review of Manual 10 led to recommended revisions clarifying that, when reporting outages in eDART, non-capacity resources should report their full nameplate capability unless physically derated.
    • PJM proposed revisions to Manual 14D requiring that all generation resources prepare for cold weather operations and expanded the guidance it provides for its cold weather checklist. The recommendations for combustion turbine operators encourage proactive action to avoid unexpected icing that could occur due to proximity to sources of warm, moist air such as rivers or cooling tower plumes. The proposal also includes recommendations for ensuring de-icing capabilities are prepared for wind turbines, liquid-cooled inverters have anti-freezing capabilities and designating a “freeze protection operator” to plan preventative measures for critical equipment.
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MISO Explains How August Max Gen Event Didn’t Trigger Emergency Pricing

CARMEL, Ind. — MISO last week expounded on why its late August maximum generation emergency wasn’t met with prices dictated by its emergency offer floors.

The RTO shared more of the data it collected on the event during its Oct. 3-5 Markets Week. Over those meetings, stakeholders warned the low prices could discourage market participants from voluntary actions to manage dire circumstances.

MISO dipped into its emergency procedures Aug. 24 to activate emergency pricing. Its early morning analysis showed that footprint-wide capacity would fall about 2.8 GW short of demand by the day’s peak. (See MISO: Could Have Employed Wait-and-see Approach for August Emergency.)

Although MISO enacted its second emergency offer floor at $1,411.74/MWh in this case, it ultimately didn’t use the threshold in locational marginal prices, MISO staff said. Aside from a brief spike to about $1,300/MWh around 5:20 p.m. ET, extended locational marginal prices mostly stayed below $200/MWh.

When MISO applies an emergency offer floor, it doesn’t automatically mean MISO will set locational marginal prices on emergency pricing. MISO’s pricing engine can run optimizations that dodge emergency pricing when emergency resources are readied but ultimately unnecessary to ease system strain.

Some stakeholders said members need more visibility into MISO’s price formation to know in real time when emergency pricing is being used. They said emergency resources are expensive to bring online and were forced to take relatively low locational marginal pricing Aug. 24.

On Aug. 24, MISO said it “consistently” imported power from Manitoba Hydro and PJM with a maximum value of nearly 8.5 GW. It also said market participants voluntarily self-scheduled up to 3 GW of load modifying resources in the afternoon peak hours, even though MISO didn’t order them.

Market participants’ amount of self-scheduled load-modifying resources Aug. 24 | MISO

Travis Stewart, representing the Coalition of Midwest Power Producers, said the nonemergency pricing over Aug. 24 will make market participants think twice about making themselves available in future emergency conditions.

“I think you’re hitting at the heart of the conversation we’re going to be having: what effect these voluntary actions have and what they should be compensated,” MISO’s Tim Aliff said during an Oct. 5 Market Subcommittee meeting.

MISO Independent Market Monitor David Patton said he doesn’t agree with creating an expectation that voluntary load reductions made ahead of an event should receive emergency pricing. He said MISO should put out its best information available, leaving LMRs to “make their own decision on what prices will be.”

“Even when we forecast conditions to be tight, there’s a possibility that prices might not go that high,” Patton said.

Patton said he’d like to see MISO commit turbines with 30-minute startup times closer to when they’re needed, not several hours ahead of time. MISO committed about 25 GW of combustion turbines in its day-ahead market for Aug. 24. In addition, it sent dispatch instructions in real time to another 1.5 GW of small combustion turbines to manage risk.

But Patton did say he respected MISO’s decision to cancel generation commitments when it became clear they were unnecessary.

“We haven’t seen MISO cancelling commitments at this rate ever. It saved customers about $1.6 million” in revenue sufficiency guarantee payments, Patton said.

MidAmerican Energy Co.’s Dennis Kimm said committing gas units “just in time” in the summer makes sense because gas operators are prepared. However, he said that philosophy shouldn’t apply to stressful operations in the winter. He said gas units should be committed ahead of time in the colder months to make sure they can secure fuel supplies.

“We knew this day was not going to be pretty,” MISO’s John Harmon said at an Oct. 3 Reliability Subcommittee. He said a pre-dawn load check registered higher than forecasted and MISO at the time was expecting an additional 3 GW of generation losses and derates over the day.

By midmorning, however, MISO’s in-house meteorologist noticed an isentropic lift weather pattern that had clouds covering major load centers and dampening demand.

A day earlier, MISO’s 125 GW of actual peak demand fell short of its 128-GW forecast.

Harmon said MISO dealt with heat-related system stressors for the majority of August.

“This part of August was the fifth heat wave, heat dome, heat spell of the summer,” Harmon said, adding that MISO operators until then had prepared for and tracked heat for much of the summer.

MISO merges 10 separate weather forecasts to predict conditions. Harmon said MISO wasn’t the only grid operator to encounter load forecasting challenges that day.

“Things changed in a fascinating way that generated a lot of questions,” Harmon said. He said accurately predicting cloud cover over load centers in the footprint like Detroit, Minneapolis and New Orleans remains difficult.

“We did what we could to cancel some of those starts due to the drastic change in our reserve margin,” Harmon said.

Harmon said conditions improved throughout the day and the emergency declaration lured in more imports, so MISO didn’t need to dispatch emergency capacity. Harmon said obligations were met by non-emergency resources in MISO’s pricing engine despite the emergency offer floor.

DTE Energy’s Mike Samson said MISO may be declaring emergencies too early and might want to wait until later in the operating day when it becomes clear actions are necessary.

Harmon said the other side of that argument is, “if you knew it, why didn’t you tell us?” But he said MISO could have more conversations on how best to approach early warnings.

Aliff said MISO has become more proactive over the years as emergency conditions emerge.

“I’ve been at MISO 22 years, and I remember the days at MISO where we made declarations minutes before an event,” he said.

Aliff said all told, MISO followed the procedures outlined in its tariff, which directs MISO to declare an emergency if it foresees a “significant operating reserve shortage” in its real-time reliability assessment commitment.

Harmon said MISO is investigating how wind forecasts, expected imports and voluntary load reductions can evolve going into an event. He said MISO is looking for ways to improve and takes stakeholders’ views seriously after these events.

MISO has taken to commemorating extreme weather emergencies with “flair” pins on lanyards for MISO staff. Harmon predicted the late August event might earn him a new pin in the shape of a thermometer bulb.

Relatedly, MISO continues working on what it deems its “uncertainty management” project to better quantify system unknowns. As part of that, MISO is building a new risk prediction model that will allow MISO to use a dynamic reserve requirement based on a daily risk profile.

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MISO Defers Unpopular Capacity Accreditation Filing, Remains Committed to Design

CARMEL, Ind. — MISO said it will push back a contentious filing for a new, marginal approach to capacity accreditation into early next year.

MISO originally was trying to file for FERC permission for the new accreditation by year’s end. But persistent stakeholder opposition means the RTO will wait and hold more public discussions to sell stakeholders on its proposal.

MISO maintains a direct loss-of-load-style accreditation will directly link generators’ accreditation to their contribution during risky periods.

The direct loss of load approach is set to replace MISO’s current use of unforced capacity values in accreditation and will be based on a combination of individual past performance and a class average performance during risky hours for different types of generation. Most MISO resources will see their capacity values decrease under the new method. (See MISO Strengthens Resolve on Marginal Capacity Accreditation, Stakeholders Displeased.)

MISO hopes to use the new accreditation by the 2028/29 planning year.

Speaking during an Oct. 4 Resource Adequacy Subcommittee, MISO’s Davey Lopez said MISO now will use an expanded set of hours in the accreditation beyond the loss of load hours MISO’s annual study produces. The grid operator also will use all the hours when generation supply comes within 3% of load to base accreditation values on.

Lopez said that even using the expanded set of sample hours, the direct-loss-of-load-expectation accreditation will naturally produce more volatile accredited values year over year. But he also said the accreditation will solve some of the “disconnect” between capacity values and actual generator performance in the system’s riskiest periods.

Still, stakeholders continue to push MISO to use even more sample hours in the accreditation process, insisting the 3% margin expansion produces an accreditation that uses too few hours. However, Lopez said MISO will not increase the 3% reserve margin threshold further. He said including hours where MISO comes within 5% or 10% of load would defeat the purpose of what MISO’s accreditation is trying to accomplish.

“You would continue to further deviate from where the risk in the model is. You’re effectively approaching [unforced capacity] at that point,” Lopez said.

Stakeholders continue to call MISO’s class average accreditation values mysterious and said understanding how MISO arrived at them is difficult.

“I don’t know how any members will meet their fiduciary responsibility ensuring their customers and their shareholders that they’re going to get the value they need,” Customized Energy Solutions’ David Sapper said.

MidAmerican Energy’s Dehn Stevens requested MISO delay its planned implementation beyond 2028. He predicted the “shock of resource planners not being able to get new resources online” would offset accreditation losses and pointed out that regulatory approvals for new generation are lengthy.

MISO Independent Market Monitor David Patton recently said a marginal accreditation style is necessary to reflect the diminishing reliability value of intermittent renewables as more are added to the system. He said MISO could have as much as 30 GW of solar power in its fleet by 2030.

“I recognize that marginal accreditation is extremely unpopular, particularly with the environmental community because it results in lower accreditation for most intermittent renewables. But it also would result in lower accreditation for other types of units,” Patton explained at a Gulf Coast Power Association Virtual Forum on Sept 15.

Notably, MISO’s gas unit class average accreditation drops from the current 84% accreditation in winter to 70% and from 88% in spring to 72% under the new accreditation. Coal unit class average accreditation also drops similarly in winter and spring.

Patton said as MISO’s reliability risk shifts to wintertime in the coming years, MISO could dole out smaller capacity values to gas units in winter to reflect gas pipeline issues and the reliability issues that play out when gas-only units have difficulties securing nonfirm gas.

He said the new accreditation will be applied to all resources in a “non-discriminatory fashion.”

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NEPOOL Participants Committee Briefs: Oct. 5, 2023

Energy market value was up $14 million in September compared to August as natural gas prices increased by 18%, ISO-NE COO Vamsi Chadalavada told the NEPOOL Participants Committee (PC) on Thursday. Market value remained low relative to 2022 and was down $368 million from September 2022.

Between 5 and 6 p.m. Sept. 7, the system hit its highest peak load so far this year, at about 24,000 MW. No emergency procedures were triggered by the event.

Annual Work Plan

Chadalavada also detailed ISO-NE’s 2024 annual work plan, outlining some of their major initiatives for the coming year.

He said the RTO’s “anchor projects” for the year will be:

Concerning the changes for transmission investments, Chadalavada said the process will work to allow for more public policy investments that anticipate load growth and resource development.

“The process would enable conversion of longer-term public policy transmission studies, like the 2050 Transmission Study Solutions, into developable projects,” Chadalavada said. He added that stakeholder discussions are expected to begin in the fourth quarter of this year, with a potential FERC filing at some point in the first half of 2024.

New Gas Reliability Study

ISO-NE said the Northeast Power Coordinating Council is proposing a Northeast gas reliability study, which will focus on the ability of the gas network to support the grid. The study will look at the dynamic response of the gas system, including whether the system will be able to support the ramping that will be needed in the future.

“In a future grid, the electricity supply and demand will be much more dynamic, and the study is expected to look at how the gas system reacts to that variability coming from the electric system,” a spokesperson for ISO-NE told RTO Insider in an email.

ISO-NE CEO Gordon van Welie told the PC that NYISO and the Northeast Gas Association likely will be involved, along with Richard Levitan of Levitan & Associates.

The study will model the loss of certain resource types, as well as the performance of the gas system under extreme weather events, van Welie said.

ISO-NE Budget Passes

The committee voted to support ISO-NE’s proposed 2024 operating budget and capital budget, as well as the 2024 NESCOE budget.

ISO-NE has requested a 21.5% increase in the overall budget for the coming year, which the RTO has said will help prepare for the energy transition and retain the workforce. (See ISO-NE Proposes 21.5% Budget Increase for 2024.)

The budget includes a placeholder for a position focused on environmental policy and community engagement, following the requests from all non-New Hampshire New England states for an executive-level environmental justice position. (See States Call for an Executive-level EJ Position at ISO-NE.)

“A successful clean energy transition cannot happen without community engagement and a meaningful role for EJ communities in helping to shape decisions that impact wholesale power and transmission rates and affect how the benefits and burdens of our electric system are apportioned,” the states wrote in their request for the position.

Donald Kreis, New Hampshire’s consumer advocate, declined to sign the request. In a letter to the editor of the Keene Sentinel, Kreis wrote, “the money would be better spent on a position or two that would help the region’s ratepayer advocates rein in runaway spending on transmission projects … and blunt the eternal efforts by generation owners to jigger the ISO New England wholesale market rules to enrich electricity magnates, unfairly, at ratepayer expense.”

NEPOOL Requests Extra Time for Order 2023

On Monday prior to the meeting, NEPOOL requested a 45-day extension on FERC Order 2023 to allow for more stakeholder input (RM22-14).

“With compliance filings due on December 5, 2023, there is insufficient time for proposed revisions to be adequately presented by ISO-NE, fully reviewed and discussed by the Transmission Committee, and voted on by the NEPOOL Participants Committee,” NEPOOL wrote. “If the commission does not grant the requested extension, ISO-NE and the commission will lose the benefit of informed discussion through a complete stakeholder process and the opportunity to refine the compliance package before the filing deadline.”

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Transmission Expansion Runs into an Old Debate: Planning vs. Markets

Hardly a week passes without some organization releasing a study touting the benefits of a huge and rapid expansion of the transmission grid.

Indeed, the idea that the grid needs a rapid expansion to tap renewable resources and decarbonize is an article of faith in the power industry. But opposition to it is not limited to climate-science doubters and fossil fuel interests. (See Counterflow: Big Transmission — Still Not the Right Stuff.)

Both PJM Independent Market Monitor Joe Bowring and Potomac Economics President David Patton, whose firm provides market monitoring for four ISOs and RTOs, have pushed back on the need to rapidly expand the grid.

“Obviously, I’m an economist, and I believe in energy markets,” Patton said. “And the thing about transmission when you’re planning, and then building transmission and guaranteeing cost recovery, is, it’s all happening outside the market.”

While both energy economists agreed that the transmission and distribution systems require central planning, they said it is far from a perfect process and can interfere with cheaper solutions produced by the markets.

Monitoring Analytics President Joe Bowring | © RTO Insider LLC

“One of the tensions that’s always existed in the PJM market from the very beginning is the tension between competitive generation and non-competitive transmission,” Bowring said. “Generation and transmission do compete at the margin. Transmission can replace generation and vice versa.”

The market monitors are not alone in this position. Vistra Energy, which owns 37,000 MW of generation and serves millions of customers over other firms’ wires, has said the same thing. Vistra told FERC in comments on its still-pending regional planning Notice of Proposed Rulemaking (RM21-17) that the idea that all renewables should be located in resource-rich areas is “too simplistic.”

“It may be more efficient to locate a new resource in a less resource-rich area where interconnection costs are lower,” Vistra said. “The net levelized margin of the resource — including environmental attribute revenues, wholesale market revenue, land cost and net network upgrade costs — will drive efficient development. Ignoring the network upgrade costs ignores a potentially important part of the project economics picture and thus risks increasing overall costs to ratepayers.”

While Vistra has an interest in protecting its fossil fuel generation’s market share, it is not averse to the clean transition. This year, it purchased Energy Harbor’s three nuclear plants, giving it 3,400 MW of carbon-free generation. (See Vistra Pays More than $3 Billion for Energy Harbor.)

FERC Transmission Planning NOPR

FERC’s planning NOPR does not direct the agency to build out all the transmission possible, said Grid Strategies President Rob Gramlich, who has long advocated for grid expansion to address climate change.

“It says: Do an analysis that evaluates the trade-off between one approach that has a lot of remote cheap generation with transmission lines, and another option, that’s more local generation with less spending on transmission — and find the sweet spot between those,” Gramlich said.

Rob Gramlich, Grid Strategies | © RTO Insider LLC

Bowring does not sound so different when it comes to planning, saying it needs to be done centrally and rationally, accounting for the locations of load growth and the locations of generation. Where he splits with Gramlich is on how much the cost of interconnecting new resources should be socialized. Bowring says making developers pay for their interconnection gives them the incentive to locate in the right place, rather than requiring customers to subsidize their choice of location.

Burying our heads in the sand about the realities of the future resource mix and adding transmission in small increments will only increase the costs of the networked grid needed to ensure a technologically and regionally diverse portfolio that ensures reliable service 8,760 hours a year, Gramlich said.

“We just have to get away from this system of planning and network through the interconnection process. That doesn’t work in any network in any part of our economy,” he said.

CAISO’s proposal to plan around zones with available transmission capacity now, or under construction — where some areas will be cheaper for interconnection customers than others — is a good example of how things should work, Gramlich said. (See CAISO Proposal Seeks to Address Interconnection Backlog.)

As a supporter of markets, Bowring has doubts about central planning generally, noting that PJM’s regional process has gotten it wrong in the past. He cites the example of the Potomac Appalachian Transmission Highline (PATH).

The $2.1 billion, 765-kV “coal by wire” PATH project was approved by PJM in 2007 to run from a coal generator in St. Albans, W.Va., to New Market in Frederick County, Md. By 2011, however, PJM said the need for the line had moved several years beyond 2015 because of reduced load growth following the Great Recession. After ordering transmission owners to suspend work on the line pending a more complete analysis of all upgrades in its regional transmission plan, the PJM Board of Managers terminated it in 2012.

“Reality keeps changing. We don’t know what the technology is going to look like 20 years from now,” Bowring said. “Do we really want to spend billions of dollars right now on transmission lines based on assumptions about what the technology is going to look like and the level and location of loads?”

Gramlich rejects the notion that the grid would be overbuilt by utilities zealously seeking to expand their rate bases. He said utilities lack the incentives to construct the kind of large regional and interregional lines that may be subject to competition, instead favoring local facilities they can build with little oversight.

In many cases, utilities will look at major transmission as bringing in low-cost, cheaper generation that is going to compete with their own and they will try to actively block its development, he added.

PJM has seen a lot of spending on local transmission projects in recent years, a fact that has come up repeatedly in the debate around FERC’s proposed reforms to planning and cost allocation. In September, the Ohio Consumers’ Counsel filed a complaint with FERC that said utilities in that state alone have planned for $6 billion in local projects since 2017.

No Regrets?

One idea the two market monitors pushed back against was that rarely is a transmission line built that winds up being regretted. While any transmission will be used when it is built and lead to lower congestion on the system, sometimes it is not the best choice.

“The goal is not just to eliminate congestion, it’s to eliminate congestion that has costs higher than the cost of building transmission to eliminate it,” Patton said. “And in some cases, there are other solutions that are much cheaper than transmission that the markets will facilitate.”

MISO IMM David Patton | © RTO Insider LLC

Storage, for instance, can deal with congestion either by co-locating with renewable energy or by being built by itself elsewhere on the grid. And while storage might be the best option, overzealous transmission construction outside the market could cause battery developers to abandon such projects, Patton said.

Bowring does not think congestion is a useful metric to justify building transmission, a point his firm, Monitoring Analytics, has made in its state of the market reports. Congestion is ephemeral and locational, and it changes all the time, Bowring said.

“Congestion is not a reason to build transmission,” Bowring added. “Congestion is just the difference between what load pays and generation receives. … So, congestion is zero sum already; it’s not really a metric for anything. If the [financial transmission rights] market worked as intended, load would be repaid 100% of congestion.”

Former FERC Chair Richard Glick said some of the leadership at ISO/RTOs is on board with expanding the grid, noting that MISO CEO John Bear has been advocating for years for transmission expansion to connect renewables. The queues are dominated by renewable energy projects, or hybrid projects where renewables are paired with storage. (See LBNL: Interconnection Queues Grew 40% in 2022.)

“When someone like John Bear from MISO says we desperately need this transmission buildout to keep the lights on, I believe him,” Glick said. “You don’t want to overbuild. But I would say that the consequences of underbuilding are a lot worse than the consequences of overbuilding.”

MISO is home to some of the best wind in the country, but those resources are far from major cities. In contrast, the renewables in PJM tend to be closer to load and therefore require less incremental transmission than in other regions of the country, Bowring said. The one exception to that in PJM is offshore wind.

“I don’t understand why anyone believes that copper plating PJM, or any area, is the solution to adding renewables,” Bowring said.

California used to think it could rely largely on in-state renewable energy to meet its policy goals. But while there are plenty of resources that will continue to be connected locally, policymakers have moved on from that narrow view as the share of renewables has grown, Gramlich said.

“If you do the math, it turns out that Idaho wind and Wyoming wind, and Salton Sea geothermal, New Mexico solar and wind — those complement the resources we have in state. And if you take into account the value of those, and the cost of transmission, it turns out, those are beneficial for California consumers,” Gramlich said. “So, then CPUC has directed utilities to buy power from those areas and the California ISO is tasked with figuring out the transmission to those areas. That’s the way to do it. In MISO, it’s a similar analytical exercise.”

That way of thinking is not isolated to California. Vermont PUC Commissioner Riley Allen, who sits on the FERC-State Task Force on transmission, said in an interview that while local issues like job creation are important, getting the best, most efficient mix of resources should guide transmission planning.

“The economics favor locating capacity and resources where it is inexpensive, and exploiting those opportunities sensibly, while recognizing that these resources are also going to be weather dependent and … using the grid as a mechanism that helps to ensure that no one location is dependent on resources from just one area, it adds an element of diversity that is hard to achieve otherwise,” he said.

While adding renewables to the grid will require some transmission, Patton argued that economics should guide its development more than a centralized plan.

“If we get more and more renewables, and they cause more and more congestion, we should continue to evaluate transmission the same way, which is, you know, is it cost effective to build transmission?” Patton said. “And when the answer is yes, we should build it and then the answer is no, or there’s some lower cost solution, we should not build it.”

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Counterflow: More Stuff That Ain’t So

The misinformation in our industry is pervasive. Daily headlines are loaded with stuff from reports, studies and news releases that just ain’t so.

Let me give an example of a recent Moody’s report on transmission.[1] (See Moody’s: Permitting Process Holding Transmission Back, Risking Reliability.)

Moody’s bases its case for investment in transmission in part on aged infrastructure causing reliability and other problems. Let’s check out its claims.

Transmission Outage Events

Exhibit 1 from its report is reprinted here, with Moody’s saying that transmission outage events have more than doubled between 2009-2014 and 2015-2021.

Citing NERC data, Moody’s claimed transmission outage events ‘have increased dramatically since 2014 primarily due to an increase in extreme weather.’ | Moody’s

This is not valid analysis. Starting in 2015, NERC expanded the facilities subject to reporting from 200 kV and above, to 100 kV and above.[2] The number of facilities (elements) subject to reporting increased from 7,098 to 23,835, and the number of subject circuit miles increased from 181,427 to 454,316.[3] So the increase in reported outages has everything to do with a larger number of subject facilities and circuit miles, and nothing to do with transmission system reliability.

NERC provides the trend in transmission system reliability in the chart reprinted here, saying that: “The Bulk Electric System (BES) transmission system continues to demonstrate significantly improved reliability for the fifth year in a row.”[4]

Congestion

Congestion is the additional cost of dispatching higher cost generation due to a transmission constraint. Moody’s says that congestion costs in the Mid-Atlantic region surged from $528.7 million in 2020 to $995.3 million in 2021, surpassing “energy costs.”

NERC reported that transmission system reliability, as measured by overall transmission outage severity (TOS), has improved continuously over the past five years. | NERC

The increase in congestion costs from 2020 to 2021 had everything to do with increases in fossil fuel costs (energy clearing prices increased from $21.77/MWh to $39.78/MWh largely due to higher fuel and emission costs)[5] — nothing to do with transmission system inadequacies.

As for the claim that congestion costs of $995.3 million exceeded energy costs, energy costs were $30.5 billion in 2021.[6] So congestion costs were a minor 3% of energy costs, hardly more than energy costs. And customers were shielded against much of those relatively minor congestion costs through financial transmission rights.[7]

Moody’s sources its invalid congestion claims to DOE’s draft “National Transmission Needs Study,” so let me address a couple more misjudgments that appear there.[8] DOE says the “transmission constraint shadow price” almost doubled from 2020 to 2021. This simply reflects higher fuel prices. How do we know that? Because the frequency of transmission constraints actually declined from 117,867 to 102,529.[9]

Then DOE says that in 2021 the “transmission price component” was more than the “capacity price component” for the first time since 2007, which isn’t exactly true, but in any event would suggest transmission system spending is going up – a non sequitur for any claim of growing transmission inadequacy.

Transmission Facilities’ Life Expectancy

Moody’s says that transmission lines and transformers are mostly beyond their life expectancies.

Regarding its claim that transmission lines have a life expectancy of 50 years, the reality for transmission lines is 80+ years[10] to “essentially forever.”[11]

Regarding its claim that transformers have a life expectancy of 25 years, the cited authority states that this is based on continuous loading at the rated (maximum) capacity,[12] which simply does not happen. The reality is that transformers on average last much longer than that.[13]

BTW, the most important reliability element for transformers is that we maintain an inventory available to replace transformers as failures occur. (Hint to RTOs and TOs: Any transformers retired before failure should be kept in reserve for this purpose.)

Texas

Moody’s is right about one thing: Interregional transmission ties into Texas would have avoided vast costs and outages during Winter Storm Uri (not to mention saved lives).

But as I have written before, that problem has to do with Texas’ self-imposed isolation because of its (groundless) concern about losing Texas’ independence.[14] Nothing to do with transmission system inadequacies.

Bottom Line

We should keep the current condition of the transmission system — which is generally sound — separate from the need to expand the system for the energy transition. I’ve had a few thoughts on the latter for anyone interested.[15]

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

[1] https://www.moodys.com/research/Regulated-Electric-and-Gas-Utilities-US-Transmission-investment-opportunities-abound-Sector-In-Depth–PBC_1377533.

[2] https://www.energy.gov/oe/articles/annual-us-transmission-data-review-2015, page 3 and footnote 6.

[3] https://www.nerc.com/pa/RAPA/tads/SiteAssets/TADS_Dashboard_Supporting_Data.xlsx, columns under “Inventory Counts.”

[4] https://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/NERC_SOR_2023_Overview.pdf, page 11.

[5] https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2021/2021-som-pjm-vol1.pdf, page 1.

[6] https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2021/2021-som-pjm-vol1.pdf, page 18, Table 8.

[7] https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2021/2021-som-pjm-vol1.pdf, page 72.

[8] https://www.energy.gov/sites/default/files/2023-02/022423-DRAFTNeedsStudyforPublicComment.pdf, page 64.

[9] https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2021/2021-som-pjm-sec3.pdf, page 175, Table 3-54.

[10] https://www.xcelenergy.com/staticfiles/xe/Corporate/Corporate%20PDFs/OverheadVsUnderground_FactSheet.pdf

[11] https://engineering.mit.edu/engage/ask-an-engineer/how-do-electricity-transmission-lines-withstand-a-lifetime-of-exposure-to-the-elements/; https://www.tdworld.com/intelligent-undergrounding/article/21215620/overhead-or-underground-transmission-that-is-still-the-question.

[12] https://www.electricaltechnology.org/2019/12/average-life-expectancy-transformer.html

[13] https://teamuis.com/2021/01/07/how-long-does-a-power-transformer-last-forever/

[14] https://www.energy-counsel.com/docs/a-modest-proposal.pdf

[15] https://energy-counsel.com/wp-content/uploads/2023/02/Big-Transmision-Still-Not-the-Right-Stuff.pdf; https://energy-counsel.com/wp-content/uploads/2022/04/Stop-the-Insanity.pdf.

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ERCOT Prepared for Eclipse, Loss of Solar

ERCOT says it expects normal grid conditions during Saturday’s solar eclipse when solar resources, the grid operator’s workhorses this past summer during tight afternoon hours, will see their output reduced.

Staff have been looking ahead for months to an annular solar eclipse that will cross ERCOT’s region between 10:15 a.m. and 1:45 p.m. (CT). They say a maximum coverage of sun ranging from 76% to 90% will affect solar farms, with “clear-sky capability” reduced to at least 13% during the eclipse’s peak at 11:50 a.m.

The eclipse will traverse Texas diagonally, from the state’s northwest corner to the Gulf Coast. Its path includes San Antonio, Corpus Christi, several smaller cities and swaths of barren land with solar farms.

ERCOT has more than 17 GW of utility-scale installed solar capacity that has accounted for as much as a third of the grid’s fuel mix (April) and produced a record 13.7 GW of energy (Sept. 1). It has been credited with filling production gaps during a summer that saw the grid operator set multiple demand records. (See ERCOT Sets New Demand Mark, Will be Short-lived.)

The ISO has been working with solar forecast vendors to ensure the models account for the eclipse. It said it will prepare the system as necessary to meet the down and up solar ramps and use ancillary services for additional balancing needs.

An annular solar eclipse occurs when the Moon, at or near its farthest point from Earth, passes between our planet and the sun. Because the moon does not cover the sun’s entire disc, sunlight surrounds the moon’s shadow and creates a “ring of fire” effect.

The event is a prelude to next year’s total solar eclipse on April 8. That eclipse will cross over Texas from Mexico and continue into Canada and will be the last eclipse visible in the continental U.S. until 2044.

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California Considers Plan to Update Low-carbon Fuel Standard

California regulators are considering a package of changes to the state’s low-carbon fuel standard, including measures to shore up prices of LCFS credits as fuel producers continue to generate excess credits.

The California Air Resources Board (CARB) is weighing the possibility of a one-time “stepdown” of the carbon intensity (CI) target, a move that could increase the demand for credits.

In addition, the agency is looking at a so-called auto-acceleration mechanism that would further decrease the CI target when certain market conditions are met.

CARB has been presenting the proposed changes to stakeholders during a series of recent workshops, and the CARB board received an update on the proposals last week.

The idea behind the proposed changes is to create a “steady price signal” for LCFS credits to spur ongoing investment in low-carbon fuels.

The LCFS is based on the carbon intensity score of transportation fuels used in the state, which reflects the greenhouse gas emissions of a fuel throughout its lifecycle.

The LCFS sets a CI target that decreases each year. Fuels that exceed the CI target generate a deficit, which fuel producers must offset by acquiring credits. The credits come from fuels whose CI is below the target.

In 2021 and 2022, the LCFS program “overperformed,” as the carbon intensity of transportation fuels, on a composite level, dropped below annual LCFS targets.

That has led to suggestions that CARB set more aggressive CI targets, which would help the state meet its carbon reduction goals.

3Degrees, a climate consulting firm, has urged CARB to roll out a lower CI target starting Jan. 1, 2024.

“We are concerned that multiple millions of credits are projected to be added to the credit bank in 2023, and a significant CI reduction is needed for 2024 in order to absorb these credits and maintain a robust market that incentivizes deep transportation sector decarbonization in line with midcentury targets,” Maya Kelty, 3Degrees’ senior director of regulatory affairs, said in a letter to CARB.

Working out Details

CARB hasn’t yet released a formal rulemaking package for the proposed LCFS changes, and many details still must be worked out regarding how CI targets would be adjusted.

The magnitude of a one-time stepdown in the CI target hasn’t been decided. The stepdown, planned for 2025, would be an additional decrease in the CI target on top of the annual decreases already scheduled in the LCFS program.

CARB also is working out what would trigger an auto-acceleration mechanism to reduce CI targets. One idea is to trigger the mechanism when the ratio of credit price to credit bank size hits a certain number; another concept would rely on the ratio of total credits to total deficits.

CARB wants an auto-acceleration mechanism to be based on “well-defined, publicly available market metrics.”

Stakeholders who support an auto-acceleration mechanism include Neste US, a producer of renewable diesel.

“The record high credit bank and unexpected rapid increases in the credit bank have been key reasons for increasing unpredictability of the market and the price,” wrote Oscar Garcia, West Coast regulatory affairs manager for Neste US.

The Union of Concerned Scientists, however, said an auto-acceleration mechanism isn’t the proper solution. Jeremy Martin, a senior scientist in UCS’ clean transportation program, said the main cause of recently falling LCFS credit prices has been the surge in the use of lipid-based renewable diesel in California. Renewable diesel is made from fats and oils, such as canola oil or soybean oil.

“With [Renewable Fuel Standard and federal] tax credits, renewable diesel became an inexpensive source of LCFS compliance and flooded the market,” undermining credit prices, Martin said in written comments. He called for capping LCFS compliance from lipid-based fuels.

Other commenters raised concerns that higher credit prices resulting from a stringent CI target would be passed along to consumers of gasoline, who over time are more likely to be low-income drivers who can’t afford an EV.

Other Changes Proposed

The current LCFS regulation reduces CI targets each year through 2030, with a 20% statewide reduction by 2030 from a 2010 baseline. Proposed changes would implement further reductions from 2030 to 2045.

Another proposed change would add aviation fuel to the fuels covered by the LCFS. Jet fuel currently is exempted from generating CI deficits.

Other changes under consideration would offer LCFS credits for refueling infrastructure for medium- and heavy-duty zero-emission trucks. LCFS has supported light-duty ZEV refueling infrastructure since 2019.

CARB staff expect to release a formal LCFS rulemaking package this year, which would be followed by a 45-day comment period. The regulations would go to the CARB board for a vote early next year and potentially take effect in 2024.

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NYSERDA Can’t Meet Deadline to Design New REC Plan

The New York State Energy Research and Development Authority needs more time to draw up the renewable energy certificate program for two major transmission projects.

The agency on Wednesday asked the state Department of Public Service for a one-year extension of the deadline to create the Tier 4 REC implementation plan.

The Public Service Commission on April 14, 2022, approved contracts for Champlain Hudson Power Express and Clean Path New York and gave NYSERDA 180 days to draft the implementation plan for RECs for those projects (15-E-0302). A few days short of the deadline in October 2022, NYSERDA asked for a one-year extension because of the complexity of the issues, and DPS granted it.

A few days short of the deadline this month, NYSERDA is asking for another 12 months, again citing the complexity of the task before it, the newness of the concepts, the number of factors beyond its direct control and the sheer number of stakeholders collaborating on the effort.

NYSERDA lists seven focus points in its most recent letter, compared with only six last year:

    • reviewing Tier 1 and Tier 4 shared resources contract alignment;
    • assessing Tier 4 requirements for delivery verification, contract compliance and conformity with existing processes;
    • evaluating systematic functionality that may be required in the New York Generation Attribute Tracking System and other enterprise systems for REC accounting, verification and settlement;
    • preparing Supplier Greenhouse Gas Baseline accounting standards;
    • assessing methods to verify demand response savings;
    • establishing voluntary Tier 4 REC sales and settlement processes; and
    • monitoring NYISO rulemaking relevant to internal controllable line operations and imported generation.

In its request, NYSERDA points out the two Tier 4 projects are not expected to come online until 2026 and 2027, which allows time for thoughtful and considered planning.

Champlain Hudson is a 340-mile underground/underwater HVDC line under construction that would import electricity from Quebec hydropower plants. Clean Path is an $11 billion suite that includes 1,800 MW of new solar generation, 2,000 MW of new wind power and a 175-mile underground HVDC line.

Both projects are intended to bring emissions-free electricity to New York City, where mandated retirements of fossil-fueled generation are setting up a potential reliability margin deficit as soon as 2025.

NYSERDA’s request comes as inflation and interest rate hikes roil the entire financial structure of renewable energy development in New York.

In June, developers with contracts for 4.23 GW of offshore wind nameplate capacity — 97% of the state’s offshore pipeline — told the DPS they might not be able to move forward without substantially higher offshore wind RECs. Developers of 91 onshore projects totaling 13.5 GW made the same case to DPS. Collectively the projects are a critical component of New York’s statutory goal of achieving 70% renewable power by 2030.

In late August, NYSERDA told the PSC it endorses some form of inflation adjustments as necessary to carry out the clean energy transition in New York.

As this was unfolding, Champlain Hudson and Clean Path made their own requests to the PSC. Clean Path in June wrote that it needed to be included in any inflation adjustments for Tier 1 RECs, as all 23 generation projects in its portfolio hold Tier 1 RECs or are eligible for them.

Champlain Hudson in August wrote that basic issues of fairness dictated it get the same increases granted to any other project, as its costs have increased just like theirs.

The PSC has not ruled on any of these requests yet.

Tier 4 is approaching its third birthday: The PSC created it on Oct. 15, 2020, through an order modifying the Clean Energy Standard. NYSERDA’s Tier 4 REC solicitation yielded 33 bids from seven sources. Clean Path and Champlain Hudson were ranked first and second, respectively, among the responses.

The two projects are predicted to reduce greenhouse gas emissions by 77 million metric tons over 15 years. The first-year impact on ratepayer bills has been estimated as an increase of 3 to 5.7% per month.

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ERCOT Searching for 3 GW of Winter Capacity

AUSTIN, Texas — ERCOT surprised the market this week when it said it plans to increase operating reserves by requesting an additional 3,000 MW of capacity to shore up the grid for the upcoming winter.

In a market notice issued Monday afternoon, the grid operator said its first monthly resource adequacy assessment indicates that if it experiences severe weather this winter similar to Winter Storm Elliott last December, it would face an “elevated” risk of entering into an energy emergency alert (EEA) during its projected peak demand. It said that risk, a 19.9% probability, exceeds NERC’s acceptable elevated risk threshold of 10%.

ERCOT said significant peak load growth since last winter, recent and proposed retirements of dispatchable generation and extreme weather events during the past few winters led to issuing a request for proposals. A list of dispatchable resources that it said could be “potentially” eligible to offer capacity and respond to the RFP included mothballed and seasonally mothballed dispatchable resources (as of Dec. 1) and dispatchable resources that have been decommissioned since December 2020.

Dispatchable resources currently in the interconnection queue that feasibly could be accelerated into commercial operations by Jan. 4 also could be eligible, ERCOT said. Resources have until Nov. 6 to respond to the RFP. Awards for three-month contracts (December-February) will be announced Nov. 23.

Speaking at the Gulf Coast Power Association’s Annual Fall Conference on Tuesday, ERCOT CEO Pablo Vegas expressed hope that some resources that have indicated they will be mothballed or enter seasonal operations “could stick around for this winter and help out with potentially managing an extreme weather event.”

ERCOT CEO Pablo Vegas | © RTO Insider LLC

“We want to try to get the risk of an EEA condition down below 10%,” Vegas said.

All but four of the 20 resources listed in the market notice would provide no more than 78 MW of winter sustained capability. Three of the four largest — CPS Energy’s two coal-fired units at the J.T. Deely plant and Austin Energy’s Decker Creek Unit 2 steam generator, each providing 420 to 428 MW of capacity — were decommissioned in 2018 and 2022, respectively.

“We are not considering bringing Deely Units 1 and 2 out of retirement. We made a commitment to our community that those would be retired,” CPS spokesperson Dana Sotoodeh said in an email.

An Austin Energy spokesman said there are no plans to bring Decker 2 out of retirement.

The fourth, a 292-MW gas unit outside Corpus Christi, has been approved by ERCOT to indefinitely suspend operations on Nov. 24. (See “ERCOT Evaluating RMR Options,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)

Stoic Energy’s Doug Lewin referred to the units as “zombie power plants” and said ERCOT was trying to “bring [them] back to life.”

Another market insider, who goes by ERCOT Traders Anon on X (formerly known as Twitter), said ERCOT’s action is a capacity auction with two months’ lead time. They said this presents a gaming opportunity to marginal units that can “mothball and wait for an out-of-market RFP prior to a peak season.”

“What a mess. Nothing good will come from this,” they posted.

The news caused some GCPA speakers to scramble in revising their discussion points. Dan Jones, a retired ERCOT staffer who still consults with the grid operator, added a new question to the resource adequacy panel that he moderated.

“I just think it was a lot of surprise, really, to see the magnitude of the notice. Everyone else in the hall was pretty surprised,” he said.

ERCOT COO Woody Rickerson said the 19.9% risk of emergency conditions was an increase from last year’s 7% and “not acceptable.”

“It’s too high,” he said. “That 3,000 MW is enough to reduce the probability of going into EEA.”

Asked by an audience member about the probability of getting the RFP’s full 3,000 MW, Rickerson said, “I think that’s a really big question that’s going to get answered in the next couple of months.

“This is also a way of testing what the market is capable of,” he added. “What is out there? And what will the cost be? Just because we’re asking for up to 3,000 MW doesn’t mean that we will have signed contracts. We may not get that much, or it may be too expensive. I think this exercise will help educate us as to what the market is capable of providing.”