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November 14, 2024

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FERC OKs Changes to MISO Retirement Studies

FERC on Friday ruled that MISO generation owners must now give a year’s advance notice to the grid operator before they can retire or suspend resources.

The commission approved MISO’s request to double  the amount of time it has historically required GOs to submit the notices under Attachment Y of the tariff, effective Monday (ER23-630). 

The RTO’s requirement that notices be submitted four full quarterly study periods in advance is just one piece of a more rigorous generation-retirement proposal. The grid operator will now conduct retirement reliability studies in batches on a quarterly basis and include extra analysis of thermal, voltage, stability and import limitations. Staff will also halve the time, from 75 to 150 calendar days, that they’ve allotted themselves to notify GOs whether their resources are needed for reliability purposes. (See MISO to File More Stringent Generator Retirement Study Process.)

MISO said it needs the additional notice to better analyze an anticipated slew of retirement requests. FERC agreed.

“As MISO explains, it expects to continue receiving a substantial amount of Attachment Y notices for generator suspensions and retirements,” the commission wrote. “We find that the revisions will enhance the study process by allowing MISO more time to conduct the Attachment Y study that is needed to assess whether the reliability of the MISO transmission system is impacted by specific unit suspensions and retirements.”

FERC’s order also stimulated debate over whether the RTO should share some details of the confidential retirement notices it receives.

The footprint’s industrial customers asked FERC to require more transparency from MISO about its members’ retirement plans, saying the grid operator is “falling short of promoting full and robust transparency that enables forward market signals regarding generation suspensions and retirements for resource adequacy and transmission planning.”

The RTO should immediately and publicly disclose Attachment Y notices it receives so utilities can make timely plans for new generation or demand management, the customers said. FERC said the request was beyond the scope of the proceeding.

Commissioner Allison Clements said though she ultimately agreed with the decision, the secrecy surrounding MISO generation retirements might need some loosening. She said the extended-notice requirement could lead to GOs keeping their suspension and retirement plans under wraps longer.

“Transparency in this context requires a balance between generation owners’ desire for confidentiality and the consumer benefits of earlier notice to allow market forces and planning processes to efficiently respond to generation supply changes,” she wrote. “However, I am not convinced that MISO’s current confidentiality provisions strike that balance appropriately.”

Clements encouraged MISO and its stakeholders to discuss whether “more timely public notice of forthcoming suspensions and retirements is feasible.”

“The primary basis for MISO’s proposal in this proceeding is that the number of generator suspension and retirement requests has substantially increased in recent years, and MISO expects that trend to continue. This means that potential negative effects of insufficient transparency will only grow as the fleet transition continues,” she said.

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RF Panelists: Executive Buy-in Key to CIP Success

Electricity industry leaders are still not taking their critical infrastructure protection (CIP) compliance programs as seriously as they should, speakers at a webinar hosted by ReliabilityFirst warned Monday.

“Every entity I’ve seen since I started working as a CIP auditor back in 2009 … claims to have executive support for their CIP program. And mostly that’s true — but what does support mean?” Lew Folkerth, RF’s principal reliability consultant for external affairs, said at the regional entity’s monthly Technical Talk.

In most cases, he said, “it means that they get some money [and] some people for it, and that’s about as far as it goes. The truly great entities have executives that become directly involved in the CIP and O&P [Operations and Planning] compliance programs.”

As an example of healthy management buy-in, Folkerth described a company he encountered where the CEO had weekly meetings with the CIP team “during a particularly rough period,” and “responded immediately and effectively” when the team described their needs.

Zack Brinkman (ReliabilityFirst) Content.jpgZack Brinkman, ReliabilityFirst | ReliabilityFirst

Zack Brinkman, RF’s manager of CIP compliance monitoring, seconded Folkerth’s sentiments, adding that having access to top executives is “just the beginning.” Beyond paying attention to the CIP team, leadership must speak up for the team within the organization to ensure that staff from other departments take their recommendations seriously, he said.

“You really want to look at executive engagement [and] executive involvement … to have a successful program. You need ownership and accountability,” Brinkman said. “NERC’s CIP [standards touch] all sorts of different departments within an organization, and one of the things we’ve seen here and in the past is … that executive support is really key to trying to break down those silos.”

The discussion also touched on practical tips for making the best impression during CIP compliance audits. Robert Vaughn, a CIP auditor with SERC Reliability, said his top recommendation to electric utilities is to ensure they have as much documentation for their CIP program and potential issues as possible. Vaughn jokingly called documentation “auditor kryptonite,” explaining that “with good documentation, we don’t ask questions; good documentation explains itself.”

“It’s like a good recipe,” he continued. “You don’t have to list every single thing in it, but you want something that is repeatable. You want to be able to produce the same thing over and over again. … I can understand that I won’t know how to do it how entity X does it, but your documentation should carry me 60 to 70% of the way down that road.”

Full documentation can also ensure that entities aren’t too reliant on individuals and their memories, Vaughn told listeners. He recalled visiting a utility whose compliance regime documentation listed three tests that were performed regularly, then speaking with the compliance manager who told him of three more tests that he performed often but did not record. In this situation, Vaughn warned, an unexpected absence by the responsible person could lead to required tasks not being done, or not being done in time.

“You don’t want a situation where Bert and Pete win the lotto and don’t come back from lunch, and nobody can do their” jobs, Vaughn said. “That’s the problem we run into a lot of times; I have … a big flowchart that has a person’s name in [it], and we’re like, what happens if [he] takes a vacation? [They say], ‘Oh, it’s never come up before.’ … That’s not a good process. … You want something that is specific, generic [and] that can survive the test of time.”

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PJM Weighs Options for Winter Storm Elliott Follow-up

PJM last week updated stakeholders on its progress in collecting up to $2 billion in non-performance penalties from capacity sellers who did not meet their obligations during Winter Storm Elliott.

In a filing submitted to FERC Feb. 2, PJM sought approval for a tariff amendment that would allow those charged with capacity performance (CP) penalties to elect to extend their billing period up to nine months when the charges are levied near the end of a delivery year (ER23-1038).

Under current practice, PJM typically takes three months to send out penalty notices after a performance assessment event (PAI) in which generators do not meet their capacity obligations. The penalties must then be paid by the end of the delivery year.

The Winter Storm Elliott PAI event, which occurred at the end of 2022, would leave generators about three months to make the payments, exacerbating concerns that the scale of the penalties could lead to defaults. (See PJM Gas Generator Failures Eyed in Elliott Storm Review.)

PJM’s proposal would allow for the RTO to extend the billing period when the timing of the determination of the charges would leave fewer than six months to make payments, with the tradeoff of any payments made in the next delivery year being subject to interest at the FERC prevailing rate.

Since both options carry downsides, neither is being considered the default and PJM is asking those assessed penalties to notify staff of which billing timeline they are opting for by March 17, PJM CFO Lisa Drauschak said during a Feb. 8 presentation to the Market Implementation Committee. The RTO’s FERC filing requests an order by April 4 to potentially allow for the new system to be put in place before stakeholders elect their timelines.

Drauschak said PJM hopes that extending the time for making payments will maximize the RTO’s ability to collect non-performance charges while reducing the reliability risk from a significant number of resources defaulting and leaving the capacity market.

PJM released preliminary unit-specific data on CP charges and bonuses to relevant generators on Friday; however, Drauschak said the RTO does not usually publicly release preliminary aggregate figures.

Constellation’s Jason Barker said he was disappointed that PJM has yet to release a more refined estimate of the total expected penalties, adding that he’s unconvinced by PJM’s argument that it hasn’t been past practice given the magnitude of the emergency.

PJM Changes Data Collection System

PJM is allowing generation owners to revise their ticket submissions in its eDART outage reporting tool, which the RTO’s Dan Bennet said is used to derive CP performance data and the scale of any non-performance charges applicable for a given resource. Bennett presented to the Operating Committee on Feb. 9.

“We rarely make retroactive ticket changes, but given the nature of this event, … we wanted to make sure the data was accurate,” he said.

After reviewing data submitted to eDART and NERC’s Generating Availability Data System (GADS), the RTO and its Independent Market Monitor have found a wider difference than expected. While some discrepancy is to be expected given the real-time nature of eDART and the more precise data entered into GADS after an event, the usage of eDART data in determining performance charges makes accuracy crucial.

Calpine’s David “Scarp” Scarpignato said that in the heat of events, generation operators often enter data at control centers rather than at the individual units and tend to be more conservative in representing their outages to ensure compliance.

Several stakeholders reported having trouble with updating their eDART data; PJM recommended that anyone running into issues reach out to its staff and the Monitor.

PJM has also opened a new SharePoint site to submit unit-specific inquiries and documentation regarding performance during the 277 PAIs over Dec. 23-24. PJM’s Melissa Pilong recommended that submissions be made prior to March 6 to give PJM time to respond prior to the start of the billing period.

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PJM MIC Briefs: Feb. 8, 2023

Vote on Multi-schedule Modeling of Combined Cycle Units Deferred

VALLEY FORGE, Pa. — The PJM Market Implementation Committee deferred a vote on adopting a problem statement and issue charge to discuss combined cycle modeling in the market clearing engine (MCE).

Following a lengthy back-and-forth on how broad the scope of the issue charge should be, PJM revised its proposed framework for the process.

The use of multi-schedule modeling for combined cycle is being considered as MCE software provider General Electric collects design preferences from PJM while building its Next Generation Markets Systems (nGEM).

Much of the discussion has focused on what types of schedules and selection methodologies should be considered in scope. PJM had initially presented a narrower issue charge that would have limited the scope to the “schedule selection process for commitment and dispatch for day-ahead and real-time energy market for all resource types outside of the MCE.” (See “Feedback on Issue Charge, Problem Statement for Combined Cycle Modeling,” PJM MIC Briefs: Dec. 7, 2022.)

After several stakeholders expressed concern that the issue charge was too narrowly focused on a specific solution rather than an issue, and Deputy Monitor Catherine Tyler presented an issue charge with a broader approach, PJM agreed to include a handful of items to be in scope.

Tyler said that of the six options that PJM had identified in its white paper as solutions to the issues, PJM had attempted to define four options as out of scope and therefore not part of the discussion.

PJM opposed the Monitor’s proposal to include additional education in the issue charge, and stakeholders ultimately voted, with 60.8% in support, to defer adoption of the problem statement and issue charge to the MIC’s March meeting to allow for more time to review the revisions.

In a white paper that PJM’s Keyur Patel presented to the MIC, PJM stated that applying multiconfiguration modeling to its enhanced combined cycle model would allow for the MCE to capture the characteristics of individual resources and improve their dispatching. The number of configurations and schedules combined cycle units can present could lead to exponentially increasing times for the engine to complete optimization calculations.

PJM believes the best solution would be to adopt a design that would only enter one schedule to the MCE for commitment, according to the white paper. In seeking to limit the scope, the paper said that PJM is seeking to resolve the calculation issue while minimizing the impact to the current market rule.

Patel also said PJM is on a time crunch to reach a solution by the third quarter, when GE is set to begin incorporating the RTO’s guidance into a new software package.

Tyler argued that PJM’s preferred solution of using a specific and flawed predefined formula for schedule selection would weaken market power mitigation rules and fail to address issues with their implementation that the IMM has identified for many years.

Stakeholders Consider Recognition of Local Impacts to Net CONE

PJM presented a first read of the updated default gross cost of new entry (CONE) and avoidable cost rate (ACR) figures it is proposing through its quadrennial review. The new parameters will be used for the 2026/27 delivery year.

All resource types, except storage, would see their gross CONE figures increase, largely because of the Inflation Reduction Act’s changes to the investment tax credit (ITC) and new reference resources used for combined cycle and onshore wind resources.

The main changes to gross ACRs proposed are the addition of steam oil and gas as a new resource type, additional data from the Nuclear Energy Institute on nuclear costs, and refined property tax and insurance costs. Single-unit nuclear generators were the only resource type to see a decrease in default ACR.

Gas resources would see the largest increase under the new numbers, with combined cycle units increasing to $540/MW-day of nameplate output from the 2022/23 gross CONE of $320, a nearly 69% increase. Combustion turbines would go up to $427/MW-day from $294, a 45.2% increase.

Local Considerations for Net CONE

Stakeholders also discussed their interests and goals as they consider whether to allow PJM to include state and local issues in the formation of net CONE.

The items added to the interest identification matrix include ensuring that the net CONE established for an area reflects the most environmentally restricted asset life; avoiding substantial changes to the methodology of setting the end figure without considering the impact to the variable resource requirement (VRR) curve; and ensuring that the role of net CONE and the VRR curve are consistent with state policies that impact the parameters.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said he supports having an estimate of the CONE for constrained locational deliverability areas (LDAs) in instances where there are environmental restrictions such as legislation or regulations reducing the asset life.

“The reason this issue has been brought up is because of what’s been going on in Illinois and potentially in New Jersey,” he said. “Clearly they’re moving in the direction of a much cleaner fleet, and that eventually could have implications.”

First Read of PJM Proposal on Co-located Load

PJM presented a proposal to define market rules for load behind a generator’s meter months after the MIC rejected two competing proposals from the Monitor and Constellation Energy and Brookfield Renewable Partners. (See “Limited Support for Co-located Load Proposals,” PJM MIC Briefs: Dec. 7, 2022.)

The previous discourse around the proposals centered on their treatment of co-located load that is not directly interconnected with the wider PJM grid and whether the generator should be permitted to retain its capacity interconnection rights (CIRs) for the portion of its output that serves that load.

Constellation argued that when the behind-the-meter load is highly interruptible and the generator can quickly shift its output back to the grid to fill its capacity obligations, it should be permitted to retain its CIRs.

During a first read of the RTO’s proposal Wednesday, PJM’s Lisa Morelli said generators would be able to retain their CIRs under such an arrangement, but the generator would be subject to ancillary services charges, such as black start, regulation and reserves, for the load. Even without a direct connection to the grid, Morelli said it’s PJM’s belief that the load indirectly benefits from those ancillary services through the generator.

PJM’s Tim Horger said that if a generator and co-located load would not be able to operate independently of the grid, it is reliant on the grid and should have to pay the charges.

Constellation’s Jason Barker said the company is opposed to the proposal, saying it effectively requires host generators to pay for ancillary services that PJM attributes to retail load, who are not PJM members.

Adrien Ford, of the Old Dominion Electric Cooperative, said she is opposed to allowing generators with co-located load to retain the output earmarked for the load and said PJM is trying to draw parallels between co-located load and behind-the-meter generation. She also said there has not been adequate weigh-in on whether co-located load is under FERC or state jurisdiction.

Monitor Joe Bowring indicated his surprise that PJM was now taking the initiative to support Constellation’s proposal, given that it had received no stakeholder support in the RTO’s poll and, he argued, would undermine markets.

No Consensus on Changes to MSOC

Stakeholders were divided on changes that could be made to the marker seller offer cap for the 2025/26 Base Residual Auction to reflect the impact of December’s Winter Storm Elliott. Much of the discourse was in line with the discussion at the Resource Adequacy Senior Task Force’s Jan. 31 meeting, with stakeholders stating that they want additional information about how the 277 performance assessment zones on Dec. 23 and 24 will affect units’ Capacity Performance quantified risk (CPQR) and related parameters. (See PJM Stakeholders Discuss Capacity Market Changes After Winter Storm.)

Jeff Whitehead of GT Power Group said market sellers currently have no insight on how their unit-specific offer caps will be evaluated by the Monitor and PJM. Without a firm understanding of what the status quo looks like, he said it is difficult for stakeholders to start working on solutions.

Bowring said it is fairly simple to include the data from the storm into the IMM’s assessment of their risk, but that risk will vary widely for individual generators, preventing him from speaking in general terms. He encouraged generators to reach out to the Monitor for unit-specific information, but he said no generators had contacted it yet.

Bowring said that for some units, the impact of Elliott would be to reduce their CPQR risk, while for poorly performing resources, the impact would the opposite. “On average, the impact of Elliott on CPQR risk is relatively small. This is the first significant event since the introduction of the Capacity Performance market design.”

PJM’s Dave Anders said implementing changes in time for the 2025/26 BRA, scheduled for June, would have to follow a tight timeline with two possible pathways: delaying the auction, or keeping the bid and clearing timing and seeking FERC approval to alter the pre-auction timeline. Wrapping up Wednesday’s discussion, Anders said he had not heard a preference for either option.

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PJM PC/TEAC Briefs: Feb. 7, 2023

Planning Committee

Update on 2022 Cost Allocation 

VALLEY FORGE, Pa. — An error in the power flow case for several generators caused minor impacts to the 2022 annual cost allocations and zonal charges for the units, according to a presentation PJM’s Grace Niu gave at the Feb. 7 Planning Committee meeting (ER22-702).

The error affected zonal allocations for 28 projects in 14 regions, with changes being below $1 million for all but three. Baltimore Gas and Electric saw its charges drop by $5.56 million, while APS increased by $1.66 million and Dominion went up by $2.62 million. Liu said the next steps are a FERC filing to make adjustments to the tariff to avoid similar incidents in the future.

Stakeholders Approve New TO/TOP Matrix

Stakeholders endorsed proposed revisions to the Transmission Owner/Transmission Operator (TO/TOP) Matrix, which defines the tasks TOs and PJM are accountable for to comply with NERC reliability standards. Gizella Mali, TO/TOP Matrix Subcommittee chair, said the changes do not add any new standards or remove any retired standards and contain only minor revisions identified in the subcommittee’s review.

The changes include updated document titles, versions and sections, as well as hyperlinks to reference tabs.

Transmission Expansion Advisory Committee

Dozens of Transmission Projects Canceled with Beaver Valley Extension

PJM’s Phil Yum reviewed the baseline impact of First Energy’s March 2020 announcement that it will no longer deactivate its Beaver Valley Nuclear Power Station, a two-unit 1,872-MW generator in Shippingport, Pa. (See Beaver Valley Nuclear Plant to Stay Open.)

Dozens of transmission upgrades had been identified in PJM’s Regional Transmission Expansion Plans (RTEP) since the company’s 2018 announcement that it intended to deactivate three of its nuclear facilities, including Beaver Valley. First Energy has also canceled the deactivation requests for the other two generators identified, Davis Besse and Perry Nuclear Generating Station.

The reinstatement of Beaver Valley has led PJM to cancel 22 baseline upgrades in the APS zone, four in the American Transmission Systems Inc. zone and five in the Penelec zone.

PJM Reviews Baseline Project Proposals

Dominion proposed two solutions totaling $17.8 million to address an overload identified at its 230/115-kV Bremo transformer in the 2027 RTEP light load case. PJM’s preferred solution is to rebuild the Bremo-Fork Union 230-kV line with double circuit structures, achieving a summer rating of 1,573 MVA and disconnecting the line between the Bear Garden substation and Bremo to extending the line 1.6 miles to instead terminate at the Fork Union. The $10.09 million proposal comes with a projected in-service date of Nov. 1, 2027.

The proposal includes the potential to retire the Bremo substation and reterminate all its lines at Fork Union if there is sufficient headroom in the future. Dominion’s second proposed solution would be to retire the Bremo substation now, relocate its lines to Fork Union and install three additional transformers at the substation at a $35.17 million cost.

Dominion also proposed a $7.71 million solution to a 300-MW load drop violation identified at its Evergreen Mills substation. The project would cut the Brambleton-to-Poland Road 230-kV line into two new lines that would run between the three substations, with Evergreen Mills in the middle. Approximately 0.59 miles of new line would be required to cut-in Evergreen Mills, with a total cost of $7.71 million. The project has an estimated in-service date of June 1, 2027.

Supplemental Projects

American Electric Power proposed a $154.53 million supplemental project to rebuild 46.1 miles of 345-kV line with deteriorating wood H-frame structures, some of which have broken in the past and caused conductors to fall to the ground. The faltering equipment is along AEP’s 51.1-mile Conesville-Bixby line in Ohio and is a major source of transmission into the greater Columbus area, making deactivation unviable.

Degrading of the laminated crossarms is a particular concern, with inspections showing decay and rot in the wood. AEP said there are few ways of identifying decay before it causes a loss of functionality and that, paired with the prevalence of delaminated crossarms on the line, many of the failures have “historically been catastrophic in nature.” The Conesville-Bixby line is the only in AEP’s eastern footprint that continues to rely on laminated wood.

Dominion presented two supplemental projects totaling $138 million to resolve two thermal violations at its Bristers substation in Virginia and on the line to the Nokesville substation. The first proposal would reconductor about 9.2 miles of the line between the two substations with higher capacity equipment to achieve a minimum normal summer conductor rating of 1,573 MVA at a $23 million cost, according to the company’s presentation to the TEAC.

The second half of their proposal is to install two 1,400-MVA 500/230-kV transformers and accompanying equipment at the Vint Hill substation and expand the site to the north to provide adequate space for the equipment. Dominion would also cut and loop Vint Hill into the 500-kV lines between the Loudoun substation and the Meadowbrook and Morrisville substations, as well as cut and loop the Rollins Ford-Remington CT 230-kV line to Vint Hill. The work comes with an estimated $115 million cost.

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Market Monitor Pans ERCOT Market Redesign

ERCOT’s Independent Market Monitor continues to criticize Texas regulators’ preferred market redesign, saying the proposal is a “less effective and efficient means” to manage the market’s generation fleet.

During a hearing before the state Senate’s Business and Commerce Committee Feb. 7, Potomac Economics’ Carrie Bivens said the IMM does not support the performance credit mechanism (PCM) that the Public Utility Commission agreed to last month. (See Texas PUC Submits Reliability Plan to Legislature.)

The PCM rewards generators in ERCOT’s energy-only market with credits based on their performance during a determined number of scarcity hours. Those credits must either be bought by load-serving entities or exchanged between them and generators in a voluntary forward market.

Bivens said the IMM believes that recent modifications to the ISO’s operating reserve demand curve after the deadly 2021 winter storm provide “more than sufficient price signals” to retain market resources. She told lawmakers the PCM is a “novel concept” that will likely result in unintended consequences because of its design “challenges.”

“Our evaluation of the concept is that it decreases the efficiency of the energy market,” Bivens said. “In our opinion, if it’s designed appropriately, the most likely result is that performance credits will clear at zero and not add any benefits, since we’re already meeting the reliability standard. Otherwise, it may disrupt and distort the market leading to inefficient outcomes at increased costs.”

Jose Menendez 2022-03-02 (RTO Insider LLC) FI.jpgSen. Jose Menendez | © RTO Insider LLC

Sen. Jose Menendez (D) asked Bivens who would bear the costs of implementing the market mechanism. Energy and Environmental Economics (E3), a consulting firm hired last year by the PUC to review various proposed market revisions, put the implementation cost at $460 million.

“It shifts the risks from generators on to the load, and so it most benefits generators,” said Bivens, who has said the $460 million would be a minimum estimate for incremental costs.

She said the IMM has not performed its own analysis of the PCM’s costs, saying there are still several outstanding factors that “frustrate the ability” to derive an accurate cost estimate.

“Most particular is how the demand curve is going to be formulated. That is going to be a huge contributor to how much these items are going to cost,” Bivens said. “The reason I say that’s the minimum is because a model such as E3’s is going to assume perfect decisions, perfect capacity, no overbuild, no underbuild, no market-power abuse. You know, perfect information by all the participants, and that doesn’t exist in the real world.”

E3 has said the credits could cost retailers $5.7 billion a year, but that could be “significantly” offset by an overall decrease in energy costs.

Bivens agreed with Menendez that it is inaccurate to say no new thermal generation has recently been built, as Sen. Robert Nichols (R) said during an opening history lesson on ERCOT’s market development.

“We’re continuing to lose dispatchable power,” Nichols said. “No one is building anything new.”

The IMM noted in comments to the PUC that since 2014 the market has added about 7 GW of thermal generation — all natural gas, just the fuel type lawmakers asked for with legislation after the winter storm.

Asked by Menendez about the possibility of self-dealing among the so-called gentailers (companies with both generation and retail affiliates), Bivens said the IMM will work with the PUC to address market-power concerns, should the credit mechanism move forward.

Price manipulation is a concern “in every market, such as this one, in which there’s a concentration of supply,” she said.

Bivens was part of a three-person panel that also included PUC Chair Peter Lake and E3’s Zach Ming. Lake and Ming spent much of their time defending the PCM as Bivens sat silently for more than four hours.

“I’ve been very impressed with just your steadfastness,” Sen. Phil King (R) told her.

Senators questioned Lake and Ming on how the PUC’s proposal would incent the dispatchable generation they and other lawmakers requested during the 2021 legislative session. As the committee’s own press release put it, the PCM “was met with skepticism by members.”

“This is the first of its kind. We’ve seen the first of its kind before. Sometimes it works; sometimes it doesn’t,” Sen. Lois Kolkhorst (R) said. “We cannot miss on this. It’s critical.”

“If this PCM plan is adopted, will these new plants ever come online?” Sen. Brian Birdwell (R) asked Lake.

“We know market forces work,” Lake responded.

ERCOT Dispatchable Generation (Potomac Economics) Alt FI.jpgERCOT has added about 7GW of dispatchable generation, all gas, since 2014. | Potomac Economics

 

Asked whether the PUC could promise more reliability, Lake said, “Our goal was to provide you all the broad definition of the best reliability service that we could identify as a result of our analysis, and we recognize that there are a lot of technical questions yet to be answered.”

Lake told the committee he would put further planning on hold while they think things over.

As the hearing ended, an anonymous market participant who goes by the Twitter handle “King of Power,” tweeted that the “least bad option politically” would be for Texas to subsidize loans to new gas generators. That would be just fine with Lt. Gov. Dan Patrick, who presides over the Senate. On Monday, Patrick listed “adding new natural gas plants” as one of his top priorities for the session; he has threatened special sessions if he doesn’t get his way.

The tweet continued: “Lt. Gov and company get new gas plants, PCM is killed, [energy-only] market is intact, and senators can say they leveled playing field vs [environmental, social, and governance investing].”

Sen. King conducted the hearing after the committee’s chair, Sen. Charles Schwertner (R), spent the previous night in the Travis County Jail after being arrested for driving while intoxicated.

“The chair, as you know, is not going to be able to be with us today,” King said as he opened the hearing.

In a statement, Patrick said he will wait on the final outcome of Schwertner’s legal case before making a further statement. However, some have speculated this could cost the senator his chairmanship. Schwertner has been a vocal critic of the PCM, calling it a “costly and complex proposal that is unlikely to deliver the dispatchable generation resources that Texas needs.”

It’s not the first time Schwertner has found himself in hot water. He was investigated in 2018 for sending sexually-explicit text messages to a University of Texas graduate student. The inquiry ended when it determined that it was “plausible” that a third party had sent the messages.

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West, Southeast Need Tx Planners, Report Says

The non-CAISO West and the Southeast U.S. need independent regional transmission planning entities even if the entities are not RTOs, a report released Thursday by Clean Energy Buyers Institute and Grid Strategies contends.  

In contrast to much of the nation, the regions are not part of RTOs or ISOs that perform transmission planning and depend largely on individual utilities to propose projects, the research group and consulting firm noted.  

“Customers in two-thirds of the country rely on independent, trusted, expert transmission planners to achieve greater reliability and cost-savings,” Grid Strategies President Rob Gramlich said in a news release accompanying the report. “Western and Southeastern customers deserve the same benefits.”

The report says RTOs would provide the greatest benefits but that other types of organizations could do important jobs.  

In the West, “little regional planning takes place” outside CAISO, it notes. “The FERC 1000 Regional Planning Entities are Northern Grid, WestConnect and CAISO. Northern Grid and WestConnect tend to simply roll up the plans submitted by each utility.”

One entity that could provide some RTO-like services is WECC, the reliability organization for the Western Interconnection, CEBI and Grid Strategies suggested.

“Currently, the Western Electric Coordinating Council does not manage transmission planning, but it is well positioned to play a greater role,” their report says. “The entity covers the whole Western region, plus western Canadian provinces and a small part of Mexico, and has some independence from the utilities. WECC or another regional planning entity could begin performing technical studies of transmission needs and options that would be valuable for stakeholders.”

In the Southeast, three entities — Southeast Regional Transmission Planning, South Carolina Regional Transmission Planning and Florida Reliability Coordinating Council — nominally are responsible for transmission planning, but “like the West, these entities simply aggregate the utilities’ individual plans and periodically brief stakeholders without seeking input or sharing sufficient data, methods or assumptions to enable an assessment of the projects,” it says.

The Eastern Interconnect Planning Collaborative, which “covers the entire Eastern Interconnect and can evaluate interregional as well as regional opportunities,” could take on additional responsibilities, CEBI and Grid Strategies said. “This process is broad and inclusive and strives to plan backbone transmission facilities that enable interconnection-wide energy outlet and bulk transfers of power.”

FERC has encouraged the formation of RTOs such as PJM, MISO and SPP. “However, none of the relevant FERC orders (2000, 890 and 1000) require that planning functions be performed by an RTO,” the report says.

Independent transmission monitors (ITMs) have been proposed as a means of increasing transparency and oversight in regional planning, it notes.

During an Oct. 6 FERC technical conference on transmission planning, state regulators and consumer advocates urged FERC to order the creation of ITMs and to take other measures to increase oversight of transmission owners’ planning and spending. Witnesses representing transmission owners strongly opposed the ITM concept. (See States Urge More Transparency on Tx Planning, Independent Monitors.)

“The ITM has not been formally proposed by FERC at this point, and there are different versions of what it would do,” the report notes. “At a minimum, an ITM could provide information to market participants about transmission needs and opportunities, while complying with [FERC] Critical Energy Infrastructure Information requirements.”

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NYISO Operating Committee Briefs: Feb. 13, 2023

January Operations Report

NYISO on Monday updated the Operating Committee on January operations performance and how the early-February cold snap event impacted the grid.

ISO Vice President of Operations Aaron Markham said peak load for the month occurred on Jan. 31, at 20,641 MW, lower than the 22,004-MW peak load for the winter and far below the record of 25,738 MW, set in January 2014.

The cold weather event, which occurred Feb. 3 to 4, did not drop temperatures as much as during the December winter storm, but it caused roughly 2,000 MW of day-ahead-committed generation to become unavailable in real time.

Markham told stakeholders that a full operations report on the February cold weather event would be shared in March.

Emergency Operations

Stakeholders approved manual updates for manual emergency operations.

The manual provides rules and regulations that NYISO and market participants must follow in the event of a power system disturbance to both prevent further disruption and restore normal operations as soon as possible. The revisions include removing references of shift supervisor throughout, updating indexed tables and clarifying contingencies for non-NYISO controlled facilities.

FERC Interconnection Waivers

NYISO attorney Sara Keegan told stakeholders that 22 generation projects requested interconnection waivers from FERC to participate in the forthcoming 2023 Class Year study, but only 13 waivers were granted.

FERC granted eight waivers on Thursday and five more on Friday. (See related story, FERC Grants Interconnection Waivers to 8 NY Renewable Projects.)

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NYISO’s Bouchez Begins New Job as Consumer Liaison

NYISO announced on Thursday that Nicole Bouchez had begun working in her new position as senior principal economist and consumer interest liaison for market structures.

The ISO first announced the promotion last month to the Business Issues Committee. (See “Bouchez Named Consumer Liaison,” NYISO Business Issues Committee Briefs: Jan. 18, 2023.)

Bouchez has been with NYISO since 2003 and served as principal economist since 2011. In her new role, she will inform the consumer sector about changes in the wholesale energy markets and their implications, as well as serve as a coordinator for the ISO’s consumer-related initiatives, such as analyzing market developments or design changes.

“I am looking forward to working with the end-use consumers to provide valuable insights and information about market design changes,” Bouchez said in a statement. “This is an exciting time of change in the electric industry, and providing timely information is an important part of a successful transition.”

In an email to RTO Insider, Bouchez said she is “most excited about providing useful information about changes in the wholesale markets.”

NYISO CEO Rich Dewey commended Bouchez in a statement, saying “the expertise and experience that Nicole provides to our market teams and stakeholders is second to none,” and that the ISO “will continue to rely upon Nicole’s knowledge and guidance on changes in the markets.”

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NEPOOL MC Gives OK to Inventoried Energy Program Tweaks

The NEPOOL Markets Committee last week signed off on changes to the Inventoried Energy Program that are intended to get the winter reliability program back in line with global energy markets.

If approved by the full Participants Committee at its next meeting, the changes will incorporate an indexed forward rate to automatically adjust to changes in gas market prices ahead of next winter.

The tariff changes also alter the program’s gas contracting eligibility provisions, an effort to help increase the amount of inventoried energy brought to the region for the next few winters.

In approving the changes, the committee also rejected an amendment from Generation Bridge, which owns four natural gas units in Connecticut. The company wanted ISO-NE to change the maximum amount of stored fuel to be counted in the program from 72 hours to 120 hours.

Changing to 120 hours, Generation Bridge argued, would increase incentives to fill large tanks or arrange for more LNG in preparation for extended cold snaps. And it would improve the likelihood that units with oil capability but no capacity supply obligation would be available in the coming winters, the company said.

The committee, however, ultimately rejected that proposal.

Drilling down on DAS

The MC also continued to discuss ISO-NE’s proposed framework for a day-ahead ancillary services (DAS) market, diving into eligibility for the “flexible response services” (FRS) and energy imbalance reserves (EIRs) that will make up the core of the market.

Energy sources eligible for FRS will have to be dispatchable and located physically within ISO-NE (so no imports or virtual resources would be eligible). They would have to be unconstrained by transmission, not part of first-contingency supply loss and sustainable for a minimum of an hour.

EIR resources would also have to be physical supply resources located within the bounds of ISO-NE and either committed in the energy market already or a fast-start resource.

The committee also discussed settlement rules for the DAS market, which would be “largely unchanged from those proposed during Energy Security Improvements discussions in 2019-2020.”