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August 4, 2024

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ERCOT Board of Directors Briefs: June 19-20, 2023

AUSTIN, Texas — ERCOT said last week it is reviewing the electric-industry-related legislation that passed during the Texas Legislature’s recently completed biennial session to determine what changes are required and their effect on grid operations.

CEO Pablo Vegas told the Board of Directors Tuesday that the legislative session was “intense” given the number of electric-related bills that were taken up and the “disparate opinions on how to address really the core issues of market redesign.” He promised a full report in September.

The 88th Legislature saw 257 bills filed touching on energy, ERCOT or the Public Utility Commission. Two years ago, after the deadly 2021 winter storm that nearly took out the Texas grid, legislators filed 311 bills. In the four sessions before Winter Storm Uri, an average of 100 similar bills were filed.

“Our team is currently working on analyzing the effect of all the provisions that have passed in the legislature,” Vegas said. “We will be communicating more as we assess along with the [PUC] the best approach for complying with the new changes in legislation.”

A sunset bill (House Bill 1500) that maintains operations at ERCOT, the PUC and the Office of Public Utility for another six years included several market redesign elements. Chief among those were several provisions adding guardrails to the PUC’s proposed performance credit mechanism (PCM) that rewards generators with credits for reliable performance during a predetermined number of scarcity hours. (See Texas PUC Submits Reliability Plan to Legislature.)

The measure caps the net cost to the ERCOT market at $1 billion (less the cost of bridge solutions), adds penalties for generators that don’t meet performance obligations and requires that bridge solutions to the PCM be rolled back.

HB1500 also requires ERCOT to add an uncertainty ancillary service product called dispatchable reliability reserve service (DRRS). Based on historical variations in availability for each season, the DRRS’ criteria require participants to be online and dispatchable for less than two hours after being deployed and to run for at least four hours. The intent is to reduce ERCOT’s reliance on reliability unit commitments, which have soared under the grid operator’s conservative operations posture.

The ISO could also have to deal with Senate Bill 2627, which creates a low-interest loan program with $5 billion set aside by lawmakers for primarily new gas generation in ERCOT. Loans and completion bonuses would be disbursed through the Texas Energy Fund, which must first be approved by voters in November.

Board OKs 27% Increase in Admin Fee

The board accepted the Finance and Audit Committee’s recommendations to increase ERCOT’s system administration fee for the first time since 2016 and to approve the 2024-25 biennial budget.

The admin fee will be raised from $0.555/MWh to $0.710/MWh, a 27.9% increase. Much of that difference will be passed on by retailers to ratepayers. Consumer advocates don’t oppose the increase, saying it was long overdue and will help pay for the real-time co-optimization (RTC) project that is expected to save billions.

The budget will provide ERCOT with $424.03 million and $426.99 million in 2024 and 2025, respectively, for operating expenses, project spending and debt service obligations.

Both measures will be filed with the PUC for its approval.

According to a 2018 Independent Market Monitor report, the market tool would result in a $1.6 billion reduction in annual total energy costs, or about a $4/MWh price reduction. The report also found reliability would be improved by reduced overloading of transmission constraints and less use of the regulation-up ancillary service equating to $4.3 million. Another $400 million would have been saved by reducing congestion costs and ancillary service costs.

Staff told the Reliability and Markets (R&M) Committee June 19 that it will cost about $50 million to complete the RTC project, which was put on hold after the 2021 winter storm. They said RTC’s complex implementation has made it difficult to find the timing and resources for delivery, but that they are ready to resume work on July 1 with an eye on completing the project in 2026.

Most other grid operators already use the RTC tool, which dispatches energy and ancillary services every five minutes. ERCOT says RTC will produce energy from cheaper resources, with more expensive resources shifting to the ancillary market.

In discussing ERCOT’s technology stack with the R&M, Vegas said RTC and the PCM, “potentially,” are among the near-term major projects.

New Ancillary Service Deployed

Staff told the board that the ISO has added and deployed in June its first ancillary service in more than 20 years with ERCOT contingency reserve service (ECRS). The product provides the system with additional capacity that can ramp in 10 minutes to respond to short-term net load ramps.

Vegas said ECRS is necessary because load and generation are constantly changing because of daily load patterns and instantaneous load variation, changes in variable generation and units tripping offline.

ECRS procurements began June 10 with “minimal hiccups,” Vegas said. It was first deployed June 14, and then again June 16 and 18 for between five and 25 minutes in amounts between 200 and 600 MW. ERCOT procures about 2 GW of ECRS per hour at an average price of $25.26/MWh.

“It’s working exactly as we had hoped,” Vegas said. “It’s become a new tool in our suite of operational flexibility products. We’ve got a broader suite of tools now that we can use to help deal with changes in load changes in supply and to be able to respond very quickly to market conditions as they evolve.”

ERCOT Mulling Coming EPA Regs

ERCOT general counsel Chad Seely briefed the board on EPA’s Good Neighbor Plan, which requires nitrogen oxide emission reductions from power plants and industrial facilities, and four other pending regulations that could affect the state’s dispatchable resources.

Texas is among 23 states that, under the plan, must meet the Clean Air Act’s “good neighbor” requirements by reducing pollution that contributes to problems attaining and maintaining EPA’s health-based air quality standard for ground-level ozone in downwind states. (See EPA Good Neighbor Plan Expected to Accelerate Coal Plant Retirements.)

The plan was to be effective Aug. 4. Texas, after earlier being granted a stay of  EPA’s disapproval of its state implementation plan by the 5th U.S. Circuit Court of Appeals, filed a lawsuit June 7 with the same court that challenges the good neighbor plan.

“The EPA right now is coming out with a lot of rules over the near-term and long-term could have a significant impact on our dispatchable resources,” Seely told the board.

ERCOT’s Chad Seely briefs the Board of Directors on upcoming EPA regulations. | © RTO Insider LLC

He said EPA’s most significant rule is the proposed greenhouse gas rule that would require new carbon dioxide restrictions for some coal and gas units by 2030. Several parties have asked for an extension of the Aug. 4 comment deadline; Seely said he expects EPA to grant that request.

In the meantime, ERCOT is evaluating the reliability effect on the thermal generation fleet. Seely said the ISO is collaborating with the PUC, the Attorney General’s office, and the Texas Commission on Environmental Quality.

“But most importantly, we have to engage the generators to understand what the direct impact is,” Seely said. “They were very instrumental in giving us feedback that ultimately rolled into our assessments … so it’s critically important as we continue to move forward and evaluate these regulations that we have the partnership with the generators to continue to work with ERCOT. They are really in the best position to tell us what that overall impact is.”

Seely reminded the board and stakeholders that the greenhouse rule is still in the formal rulemaking process. He said while the final outcome is unknown, he does not see any obstacles “in the path of any generation facility.”

“We don’t know what challenges may occur” when the final rule is published, he said. “I assume every investor is looking at what the potential environmental restrictions will be going forward with these proposals.”

“If you’re an investor thinking about putting capital into a project like this, a rule like this causes regulatory uncertainty,” cautioned board Vice Chair Bill Flores. “I think it will be exceptionally damaging to potential construction of possible units. This is scary.”

Other proposed EPA regulations include:

  • The Texas Regional Haze Federal Implementation Plan that would establish new limits on sulfur dioxide and particulate matter emissions for a dozen primarily coal-fired generating units;
  • Revisions to the Mercury and Air Toxics Standards Rule that further restrict mercury and “filterable particulate matter” emissions from coal- and oil-fired generating units; and
  • A tailpipe rule that would further reduce greenhouse gas and other emissions from light, medium and heavy-duty vehicles.

Directors Approve 12 Rule Changes

The board unanimously approved 12 protocol and guide changes. Three measures, with dissenting votes during the stakeholder process, were approved separately, including a nodal protocol revision request (NPRR1169) that expands the qualifications for generation resource that may be a firm-fuel supply service (FFSS) resource or an alternate.

The Technical Advisory Committee approved NPRR1169 in May but took it up again during a special June 6 call after the PUC called for additional discussion. (See ERCOT TAC Endorses Agreement on ‘Exceptional’ Fuel Costs.)

The R&M approved the measure after adding ERCOT comments that define an FFSS qualifying pipeline as one excluding intrastate gas utility pipelines that serve customers with a higher protection under the Texas Railroad Commission’s curtailment rule than electric generation facilities. The rule assigns a higher priority to human needs customers and local distribution systems that serve human needs customers.

The directors approved seven other NPRRs, two revisions to the nodal operating guide (NOGRRs) and single changes to the retail market guide (RMGRR) and the verifiable cost manual:

  • NPRR1143: allows ERCOT to give charging instructions to energy storage resources during a Level 3 energy emergency alert.
  • NPRR1161, NOGRR246: clarifies that intermittent renewable resources that remain synchronized to ERCOT, but are unable to provide reactive power when not providing real power, do not have to notify ERCOT other than their real-time telemetered status.
  • NPRR1166: changes the expiration date for DC ties’ schedule information protected status from 60 days after the applicable operating day to the date on which ERCOT files the report with the PUC, as required by transmission export rates’ rules related to energy imports and exports over the ties.
  • NPRR1167: improves the new FFSS product by removing language disqualifying or decertifying resources from the firm-fuel program.
  • NPRR1168: changes the Texas standard electronic transaction (Texas SET) to “Establish/Change/Delete CSA Request” and adds new sections to the protocols related to administering requests to change end dates for active continuous service agreements (CSAs).
  • NPRR1177: requires resources to file exceptional fuel costs that include contractual and pipeline-mandated costs, following negotiations between consumer representatives and a generator.
  • NPRR1178: clarifies and updates expectations for resources providing ECRS.
  • NOGRR253: aligns the guide’s language regarding ECRS and nonspin with NPRR1178’s proposed revisions and NPRR1096’s proposed protocol language. The NOGRR would also clarify that ERCOT may manually deploy load resources, other than controllable load resources that are providing ECRS or responsive reserve, to maintain a minimum 500 MW of physical responsive capability reserves on dispatchable resources to balance demand with supply while maintaining stable grid frequency for smaller disturbances.
  • RMGRR172: updates the Texas SET transaction’s name to “Establish/Change/Delete CSA Request” and adds new sections to the guide that describe how to cancel a pending CSA through MarkeTrak.
  • VCMRR031: defines variable costs and clarifies that all cost components used to calculate a filing entity’s fuel adder should also be based on variable costs; removes the minimum requirements fee cost category from being included in the fuel adder; and changes the review timeline to give ERCOT the ability to follow up on more complex cost submissions.

— Tom Kleckner

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Electric Reliability and Safety Continue to Improve in NY

New York’s electric utilities in 2022 showed improved service reliability over 2021 and over the average in the preceding five years. (Case 23-E-0119)

But in other areas, the New York State Public Service Commission found performance by electric and other utilities lacking in 2022. It is assessing a record $22.6 million in penalties against six utilities for failing to meet customer service metrics.

The penalties are one of the sticks in the carrot-and-stick assortment of utility performance incentives contained within the commission’s rate design, and it was a particularly big stick this time: The PSC said the penalties assessed Thursday were 10 times higher than those imposed for 2021 failures.

PSC Chair Rory Christian in a prepared statement said: “In 2022, almost a quarter of those utilities fell short of their legal requirements in certain areas. The Commission will aggressively work to ensure lagging utilities improve performance. Maintaining reliability and ensuring good customer service is required for utilities, and the Commission holds them accountable when they fail to meet our standards.”

Aside from New York State Electric & Gas — which garnered a $7 million revenue reduction for outage frequency — reliability was a bright spot for New York electric utilities in 2022.

Department of Public Service staff said the reliability of the state’s electric utilities is measured by two primary metrics: frequency and duration.

Excluding major storms, frequency was less in 2022 than in 2021 and less than the statewide five-year average. Duration, again excluding major storms, averaged 1.9 hours, 5.4 minutes shorter than 2021 and 4.8 minutes less than the five-year average.

There were 34 major storms in 2022, four fewer than the year before. But the impact of the 2022 storms was much greater than 2021’s storms, with 31% more customers affected and a 100% increase in duration of outage.

The majority of the 2022 increases can be attributed to just three winter storms.

During Thursday’s meeting, Christian called this a worrisome development, illustrating how impactful a single storm can be in an era where severe weather events are becoming more frequent.

Central Hudson, Con Edison, National Grid, Orange & Rockland and RG&E met all reliability targets in 2022. But NYSEG missed its frequency target for the fourth consecutive year.

DPS staff said tree contact continues to be the largest contributing factor in NYSEG’s outages, accounting for 42.1% in 2022, more than any other utility in the report.

The PSC expanded NYSEG’s vegetation management budget in the 2020 rate order; the utility has seen a decrease in outages due to trees within its rights of way since then but an increase in outages caused by trees outside the ROWs.

These “danger trees” outside the ROWs were specifically targeted in one of the programs funded in 2020.

Overall, 82,288 service interruptions affected 5,298,241 customers statewide for a combined total of 10,075,244 hours in 2022. The dataset covers the six regulated electric utilities and PSEG-LI.

On safety measures — stray voltage, gas leaks and other potential hazards — the DPS review found electric and gas utilities in full compliance and continuing a trend of improvement in most respects.

DPS staff in their review said most of the state’s utilities met or exceeded the customer service standards established in their rate case proceedings for metrics such as call answer rate, customer satisfaction survey and PSC complaint rate. The 2022 laggards, and their revenue penalties, are:

Central Hudson, $2.9 million; NYSEG, $8.72 million; RG&E, $5.9 million; Con Edison, $4 million; St. Lawrence Gas, $36,000; National Grid, $1.05 million.

The customer service reports issued Thursday are separate from ongoing DPS investigations into current and past billing problems at Central Hudson, NYSEG and RG&E. But the PSC said the reports could inform the billing investigations.

Also on the consumer protection front, the PSC on Thursday set rules and regulations governing energy brokers and consultants. (Case 23-M-106)

Christian said the move is designed to increase transparency in and oversight of a previously unregulated but rapidly growing area of the clean-energy economy in New York.

The new rules require persons, firms and associations acting as an energy broker or consultant to register annually with the PSC, pay a $500 registration fee, and demonstrate financial accountability. The deadline is Aug. 31, 2023.

The new rules also require disclosure of compensation paid to brokers and establish enforcement procedures.

Rebates from the broker/consultant to the ratepayer are banned, as they could obscure actual costs, and the PSC can order customer rebates to be drawn from a letter of credit that brokers/consultants will have to provide.

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ERCOT Sovereign Immunity Affirmed by Texas Supreme Court

The Texas Supreme Court on Friday narrowly affirmed ERCOT’s sovereign immunity, granting it protection against fraud claims and allegations of overpricing during the 2021 winter storm, and asserted the Public Utility Commission’s jurisdiction over the grid operator in a pair of rulings.

In a 5-4 decision, the state’s high court found that ERCOT is a governmental entity and immune to lawsuits because “it prevents the disruption of key governmental services, protects public funds and respects separation of powers principles.”

The majority held that the ISO is entitled to sovereign immunity because the state’s Public Utility Regulatory Act “‘evinces clear legislative intent’ to vest it with the “‘nature, purposes and powers’ of an ‘arm of the [s]tate government’” and because doing so satisfies the ‘political, pecuniary and pragmatic policies underlying our immunity doctrines’” (22-0056, 22-0196).

Writing for the majority, Chief Justice Nathan Hecht said ERCOT is a “unique entity” and provides an “essential governmental service.” He said ERCOT operates under the PUC’s direct control and oversight, it performs the “governmental function of utilities regulation, and it possesses the power to adopt and enforce rules pursuant to that role.”

“ERCOT’s governmental nature is demonstrated most prominently by the level of control and authority the state exercises over it and its accountability to the state,” Hecht wrote. “In this regard, it is much like a state agency … the state has complete authority over everything ERCOT does to perform its statutory functions.”

In a 53-page dissent that outnumbered the 40-page decision, justices Jeffrey Boyd and John Devine wrote that “the public’s trust is undermined when the judiciary extends sovereign immunity, contrary to history and tradition, to what is undeniably not sovereign: purely private entities.” They called on Texas lawmakers to correct the court’s “mistake” and waive the grid operator’s “newfound immunity” so injured parties have the right “to claim the protection of the laws.”

Thousands of wrongful death and property damage lawsuits stemming from Winter Storm Uri have been combined in pending multidistrict litigation in a district court, where ERCOT is a defendant in most of the cases.

“The root justification for possibly protecting private entities with the [s]overeign’s immunity is that, by statute or contract, they act as arms of the state: the government acted through the entity and the actions are effectively attributed to the government as ‘action taken by the government,’” Boyd and Devine wrote. “Unlike any other entity previously granted immunity by this [c]ourt, no statute designates ERCOT as a part of the government.”

ERCOT said in an emailed statement that it was pleased with the decision.

“The [c]ourt’s careful consideration of these significant legal issues allows us to continue to focus on our core [s]tate responsibilities on ensuring a reliable grid for Texans,” the grid operator said.

The PUC responded that it would “let the ruling speak for itself.”

The decision resolves two separate proceedings the Supreme Court heard in January. (See ERCOT Claims Immunity Before Texas Supreme Court.)

The high court affirmed a 2021 appeals court ruling that ERCOT is a “governmental unit” in a lawsuit brought by San Antonio municipality CPS Energy. The utility alleged that it was short-changed $18 million during the winter storm by ERCOT’s mishandling of power pricing.

It also reversed an appeals court’s judgment that the ISO is a private, membership-based nonprofit, not created or chartered by the state, in a case involving Panda Power that dates to last decade. The developer said ERCOT knowingly produced false market data in 2011 and 2012 reports that led Panda to build three power plants, a $2.2 billion investment that failed to meet its expectations.

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Loan Programs Office Announces $9.2B for Ford Battery Plants in Tenn., Ky.

The Department of Energy’s Loan Program Office (LPO) on Thursday announced a conditional commitment for a loan of up to $9.2 billion to help BlueOval SK, a joint venture between Ford and Korean battery manufacturer SK On, to produce electric vehicle batteries at sprawling plants in Kentucky and Tennessee.

The three plants, one in Tennessee and two in Kentucky, will together be able to produce 120 GWh of batteries per year, to be used in Ford and Lincoln EVs, the LPO announced. Already under construction, the Kentucky plants cover an estimated 2.3 square miles, with battery production to begin in 2025, according to the BlueOval website.

With a 6-square-mile “megacampus,” the Tennessee plant will be the largest in Ford’s portfolio and include both battery manufacturing and a factory for Ford EVs, according to BlueOval. As described on the company website, the plant will “be carbon neutral, use 100% renewable energy, send zero waste to landfill and use fresh water only for human consumption ― as [Ford] moves towards a closed-loop manufacturing process.”

Production in Tennessee also is scheduled to begin in 2025, the company said.

Job creation across all three plants will be about 5,000 during construction, with 7,500 permanent positions. BlueOval is working with community colleges in Kentucky and Tennessee to develop training programs “where thousands of employees will gain the skills required to work at the battery plants,” according to the company announcement.

BlueOval will be building a training facility next to the Tennessee plant to “really [focus] on the curriculum for training, deep learning, and getting people through that part of the training before they come out on the shop floor to be a part of the launch,” said Kel Kearns, the plant manager, as reported by WBBJ in Jackson, Tenn.

The LPO noted that the Kentucky and Tennessee projects are also located near or in disadvantaged communities, reflecting President Joe Biden’s “Justice 40” commitment to ensuring 40% of all federally funded projects benefit low-income and disadvantaged communities.

“The DOE’s commitment to this project will strengthen battery manufacturing in the U.S. while reducing carbon emissions, providing customers with high-performance vehicles, and creating good jobs for future generations,” said BlueOval CEO Robert Rhee.  The company must meet additional LPO requirements before the conditional loan can be finalized.

A Domestic Supply Chain

Building out a domestic supply chain for EV and stationary batteries is a key priority for the LPO, as domestic content in EVs and batteries has become a political flashpoint for Biden’s push to make electric vehicles 50% of all new car sales by 2030.

The industry is highly dependent on China for batteries and the processing of critical minerals in them, including lithium, cobalt and nickel. Sen. Joe Manchin (D-W.Va.) made a U.S. supply chain buildout a key part of the Inflation Reduction Act.

To be eligible for the full $7,500 EV tax credit in the IRA, a vehicle must meet domestic content and assembly requirements.

According to Internal Revenue Service guidelines, to receive the full credit, the final assembly of an EV must occur in North America. In addition, 40% of the critical minerals in the battery and 50% of other battery components must be sourced, processed or manufactured in the U.S. or in a country with which the U.S. has a free trade agreement.

The domestic content percentages go up each year, with critical minerals increasing 10% per year, up to 80% in 2027, while the battery component also will increase 10% per year, rising to 100% in 2029.

Some, but not all, models of Ford’s top EVs — the Mustang Mach-e SUV and F-150 Lightning pickup truck — qualify for the full credit, according to the company website.

The LPO received $3 billion from the IRA specifically for its Advanced Technology Vehicles Manufacturing (ATVM) program, an amount that can be used to provide up to $40 billion in loan authority, according to an online fact sheet.

The BlueOval announcement is the latest conditional loan from the ATVM program. This month, the LPO made a conditional commitment for an $850 million loan to KORE Power for an Arizona plant that will produce battery cells to be used in both EVs and grid-scale stationary storage. (See LPO Announces $850M Conditional Loan for Ariz. Battery Cell Plant.)

In March, the office also announced a $375 million conditional loan to Li-Cycle Holdings to develop North America’s first recycling facility for battery-grade lithium, to be located in New York. (See DOE OKs $375 Loan for NY Battery Recovery Plant.)

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FERC Rejects PG&E Standard Interconnection Agreement

FERC rejected a controversial pro forma transmission-to-transmission interconnection agreement filed by Pacific Gas and Electric that the utility said was modeled on CAISO’s large generator interconnection agreement as a means to streamline its interconnection process.

“PG&E states that the pro forma IA [interconnection agreement] will standardize and simplify new agreements and provide transparency and predictability for interconnection customers that are interconnecting their transmission system or transmission facility to PG&E’s transmission system,” FERC said (ER23-1661).

The utility argued that the new IA would “create efficiency since it anticipates 15 new or replacement interconnection agreements through 2025,” the commission said.

CAISO plans and operates PG&E’s transmission system, and its pro forma large generator interconnection agreement (LGIA), with revisions for transmission interconnections, contains “many terms and definitions … consistent with CAISO’s tariff, PG&E said as part of its explanation of why it had used it as a model.

The proposal elicited a slew of protests from utilities, state and federal agencies and balancing authorities that offered 18 categories of reasons why the standardized agreement would be unreasonable and discriminatory to those seeking to connect to PG&E’s sprawling transmission grid.

“Protestors request that the commission reject the pro forma IA or, in the alternative, that the commission establish hearing and settlement judge procedures,” FERC said. “Several protestors … note that the commission has never approved a pro forma ‘load’ interconnection agreement, and instead reviews interconnection agreements on a case-by-case basis.”

One group of protesters called the “Indicated Public Entities” included the city and county of San Francisco, the Northern California Power Agency, the Transmission Agency of Northern California, the Sacramento Municipal Utility District, the Port of Oakland and three irrigation districts that generate electricity.

“Indicated Public Entities argue that PG&E’s desire to ease negotiation of new interconnection agreements is no justification for limiting interconnecting entities’ ability to negotiate terms based on their own circumstances,” FERC said.

The U.S. Department of Energy, the Western Area Power Administration, and the California Department of Water Resources filed motions to intervene and protests.

“DOE asserts that providing uniformity is an insufficient justification for terms of the pro forma IA that conflict with legal rights and obligations of the United States,” FERC said.

DOE also emphasized that PG&E had not adequately explained why it had chosen CAISO’s pro forma LGIA as a “useful or appropriate template for transmission-to-transmission system interconnections,” the commission said.

FERC agreed with the arguments made by DOE and others.

“Rather than explaining why the specific provisions of its proposed pro forma IA are just and reasonable and not unduly discriminatory or preferential in their own right, PG&E places significant emphasis on the fact that it used the CAISO pro forma LGIA as a template for its proposed pro forma IA, and that the Commission previously accepted similar interconnection agreements,” FERC said.

But “CAISO’s pro forma LGIA is designed to address the specific issues associated with the interconnection of a generator to CAISO’s transmission system,” it said. “System-to-system interconnections raise different issues and require different considerations than those addressed in an LGIA.”

In addition, PG&E’s proposal included “significant deviations from CAISO’s LGIA without sufficient explanation, FERC found.

Another main reason FERC said it rejected PG&E’s proposal was because it “contemplates a pro forma IA that includes individually tailored and negotiated appendices that will replace existing IAs when they terminate.”

“We find that PG&E has not adequately explained how the individually tailored and negotiated appendices will be used to capture the customer-specific requirements of PG&E’s differently situated interconnection customers,” FERC said.

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Report Criticizes Gas Plant Performance During California Heat Wave

California’s gas-fired power plants experienced a surge in curtailments during last summer’s heat wave, according to a new report, which questions whether the facilities are a solution to preventing energy shortfalls.

At the same time, the gas plants’ emissions spiked, worsening air quality in disadvantaged communities, according to the report, released Wednesday by Regenerate California. The group is a coalition led by the California Environmental Justice Alliance (CEJA) and the Sierra Club.

“Gas simply does not do its job when it matters most,” said Ari Eisenstadt, energy equity manager at CEJA. “Gas plants’ mythical reliability value in keeping the lights on is far outweighed by their negative air quality impacts for environmental justice communities.”

Regenerate California partnered with consultant Grid Strategies to analyze power output and emissions from 107 gas plants in California during the record-breaking heatwave from Aug. 31 to Sept. 9, 2022.

Potential generation that was lost due to gas plant outages and derates during the heat wave totaled more than 1.1 million MWh, or nearly 5,000 MW on average, according to the analysis, which used CAISO data.

And during the peak period from 4 to 9 p.m., curtailments were about 200 MW higher on average.

“California gas plant curtailments track fairly closely with CAISO hourly demand during the heat wave, likely reflecting that derates due to high ambient temperatures coincide with periods of high electricity demand,” the report said.

The report didn’t include curtailment data from days outside of the heat wave. But Grid Strategies Vice President Michael Goggin said a standard assumption is that about 5% of the gas fleet will be unavailable during peak periods.

In contrast, a curtailment of 10% or even as much as 15% was seen at peak periods during last year’s heat wave, Goggin said Wednesday during a media briefing on the report.

That was due to gas plants running less efficiently when the weather heats up, along with an increase in equipment failures, Goggin said. Older plants that were fired up during the heat wave were less reliable, he added.

“It’s pretty clear that these gas plants fell well short of what was expected of them,” Goggin said.

When asked to comment on the report, a spokesperson with the Edison Electric Institute, which represents U.S. investor-owned electric companies, said EEI members are working to deploy wind, solar and energy storage resources while demonstrating technologies that aren’t yet available at cost and scale.

“As we continue to deploy those resources, nuclear energy and natural gas generation are essential partners in accelerating the clean energy transition,” EEI media relations director Sarah Durdaller told RTO Insider. “They allow our member companies to integrate more renewables into the energy grid while ensuring resilience and reliability.”

Emissions Spike

The report also examined gas plant emissions using data from EPA’s continuous emissions monitoring program. For the 107 plants for which EPA data were available, emissions of sulfur dioxide, nitrogen oxides and carbon dioxide increased by about 60% during the heat wave compared with a baseline period of Aug. 19-28, 2022.

Not only did overall emissions increase, but emissions per megawatt-hour were also up as older plants came online, Goggin said.

“There were some very dirty power plants that turned on during these really top hours of need,” he said.

The increased emissions came after Gov. Gavin Newsom issued an emergency proclamation at the start of the heat wave, loosening air quality requirements to allow gas-fired power plants to generate more electricity. (See Newsom Declares Emergency as Heat Stresses Calif. Grid.)

Blackouts Avoided

CAISO was able to avoid rolling blackouts during the heat wave, despite demand reaching a new high of more than 52 GW on Sept. 6. Several factors helped prevent a blackout, the ISO said, including an emergency text message sent out to 27 million cell phones on Sept. 6 urging consumers to conserve electricity. Within 20 minutes of the 5:45 p.m. alert, demand plunged by 2,385 MW. (See CAISO Reports on Summer Heat Wave Performance.)

“That’s really what kept the lights on,” Eisenstadt of CEJA said during Wednesday’s media briefing. “If we were paying people to do that — especially if we were paying low-income ratepayers to do that — the effect would be massive.”

Eisenstadt and others called on the state to fund clean energy projects rather than keeping gas plants going.

“We must invest in demand-side solutions and drive local clean energy buildout in environmental justice communities to improve air quality and ensure grid reliability,” said Teresa Cheng, senior campaign representative with the Sierra Club.

And Eisenstadt said the dense snowpack from California’s unusually wet winter — with its expected boost to hydropower this summer — gives the state a window of opportunity to move away from gas power plants to greener forms of energy.

Some older gas plants that were slated for closure now may be kept in service as part of the Strategic Reliability Reserve that the state developed last year as part of Assembly Bill 205.

For example, AES Corp. announced in April that it signed agreements with the California Department of Water Resources to extend operations of once-through cooling units at its Huntington Beach and Alamitos gas plants through 2026. The units had been scheduled to stop operating in December 2023.

Units at Huntington Beach and Alamitos made it onto a list in the Regenerate California report of the top 15 gas plants ranked by megawatt-hours of curtailment during the heat wave.

If the three-year extensions for the 1.4 GW at Huntington Beach and Alamitos are approved, AES will run the units during emergency grid reliability events within the Strategic Reliability Reserve Program, the company said.

“Our Southland legacy units continue to demonstrate that they are ready and able to support the reliability of California’s electric grid,” Andrés Gluski, AES president and CEO, said in a statement at the time.

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NERC Finds Grid Generally Reliable and Resilient

NERC on Thursday released its 2023 State of Reliability report, which found that the North American bulk power system generally remains highly reliable and resilient.

Transmission system reliability has improved significantly for the fifth consecutive year, but conventional generation — challenged by more frequent extreme weather — saw its highest level of unavailability overall since NERC started gathering generator availability in 2013.

Generation saw its worst “weighted equivalent forced outage rate” last year, Manager of Performance Analysis Donna Pratt said on a conference call with reporters Thursday.

“When we analyze this by fuel type, we also observed increasing outage rates for coal over the five-year period, which correlates to higher numbers of start-ups and maintenance outages,” Pratt said. “And the unavailability of gas-fired generation recently has been consistently higher during the winter months.”

Those are two of the main reasons why generation is “surpassing transmission in contributing to major load-loss events,” she added. No apparent trends are discernable in other forms of generation, the report said.

“Higher overall outage rates for coal and gas generation, as well as some utility-scale solar generation not operating as necessary for reliability, indicate that there is still significant work to be accomplished to accommodate the rapidly changing weather and generation resource mix in conjunction with electrification of the economy in a reliable manner,” said Pratt.

The most significant reliability event of the year was the winter storm in December, also known as “Elliott,” which impacted the eastern U.S. and prompted a joint inquiry from FERC and NERC into what happened. The inquiry is expected to be completed late this year, so NERC’s report did not go into depth on Elliott. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)

But in response to that and other recent cold weather events, NERC issued a Level 3 “essential action alert” this May to tell the industry to increase its winter preparedness. NERC has issued several new standards on winter readiness this year, and others are under development.

NERC’s report also highlighted a June 4, 2022, event around Odessa, Texas, where a failed surge arrestor caused the loss of 333 MW of synchronous generation, leading to the erroneous loss of another 511 MW and an unexpected loss of 1,700 MW of solar PV generation.

“The total generation lost exceeded the most severe single contingency and nearly exceeded the Texas Interconnection resource loss protection criteria, the design threshold that is used to establish the requirements for frequency recovery in the Texas Interconnection,” the report said.

That event and other similar ones indicate that the dynamic performance of inverter-based resources (IBRs) have to be improved if the grid is to benefit from their rapid expansion, NERC said.

Texas has had similar events with IBRs, as has the Western Interconnection, and NERC has highlighted the issues with IBRs since 2016. NERC is working to upgrade its standards to address the issue, and FERC launched a rulemaking on it last year. (See FERC Addresses IBRs in Multiple Orders.)

Immediate industry actions are needed to implement published guidelines and ensure the reliable operation of the grid as IBRs grow.

“IBR modeling requirements need significant improvement to ensure that high-quality, accurate models are used during reliability studies so performance issues can be identified before they occur during real-time operations,” NERC said.

Physical and cyberattacks on grid assets are increasing, and that reinforces the need for the further development and adaptation of standards and guidelines.

“The growing attack surfaces that result from the increasing penetration of distributed energy resources call for ongoing development and adaptation of cyber and physical security standards and guidelines to keep up with the ever-changing threat landscape,” NERC said. “Furthermore, cyber-informed planning should include designs and be considered when planning and integrating the technologies into the grid to strengthen the cyber robustness.”

Hostile nation states are continually targeting North American critical infrastructure and are constantly evolving methods to compromise the grid’s security, reliability and resilience.  Homegrown extremists have also targeted the grid, NERC added.

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South Fork Wind Announces ‘Steel in the Water’

The two offshore wind farms vying for first-in-the-nation status both now have “steel in the water.”

New York announced Thursday that the first monopile foundation has been installed for South Fork Wind, a 132-MW project being developed by Ørsted and Eversource off the eastern tip of Long Island.

Two weeks ago, installation of the first monopiles and transition pieces began at Vineyard Wind 1, an 800-MW project being developed by Avangrid Renewables and Copenhagen Infrastructure Partners south of Martha’s Vineyard in Massachusetts.

Vineyard and South Fork occupy the same patch of the Outer Continental Shelf south of New England that the Bureau of Ocean Energy Management is developing for emissions-free wind power.

Bokalift 2 is the center of activity on South Fork, supported by a fleet of smaller vessels and onshore personnel.

DEME’s slightly smaller Orion is performing a similar role for Vineyard, also supported by a cast of hundreds.

The heavy lift vessel Orion carries components to the Vineyard Wind project off the Massachusetts coast. | Vineyard Wind

Work on both began in 2022, and while Vineyard got a two-week head start on actual tower installation, the crews need to erect 62 turbines there, compared with only a dozen at South Fork.

Developers of the two projects and their fans in state government each say that theirs will be the first utility-scale or commercial-scale offshore wind project in U.S. waters; bragging rights presumably would belong to the one that goes online first.

South Fork expects to start producing electricity this year. Vineyard had previously specified a 2023 startup date in its publicity materials but no longer includes any prediction.

An increasingly interesting question is, which wind farm will be the third in U.S. waters?

Developers of three projects comprising 97% of New York’s contracted offshore wind pipeline and two projects comprising 67% of the pipeline in Massachusetts have all said they cannot proceed under the financial terms they agreed to before interest rates and input costs skyrocketed.

They’re seeking to cancel and renegotiate their deals. Whether or not they are successful, project delays and/or higher costs to ratepayers appear likely.

In that sense, being first worked to the advantage of South Fork and Vineyard — they locked in their contracts before costs increased.

New York Gov. Kathy Hochul said in a news release Thursday that South Fork will not only help protect the climate but also help the state develop economically.

“This progress on building the first utility-scale offshore wind project in the country cements New York as a national hub for the offshore wind industry,” she said.

Massachusetts has economic goals similar to New York’s in the offshore wind sector and has set a significantly higher per capita target for gigawatts of offshore wind power.

Massachusetts Gov. Maura Healey on June 7 offered an assessment similar to Hochul’s:

“Our administration is grateful for the important work being done by Vineyard Wind, Avangrid, CIP, DEME and labor partners to bring clean, affordable energy to Massachusetts. We’re thrilled to see this historic project move one step closer to completion and committed to supporting the offshore wind industry across the state.”

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NERC Committee Delays Guidance on Grid-Forming Batteries

A white paper on a pressing matter — managing battery systems connected to the grid — bogged down in a debate over its details as NERC’s Reliability and Security Technical Committee (RSTC) met Wednesday.

A request for approval of “Grid Forming Functional Specifications for BPS-Connected Battery Energy Storage Systems” was tabled to allow time to seek industry comment and potentially rework the report.

It was the only matter on the 27-item agenda that drew any votes of opposition.

Shortly before the vote, RSTC Chair Greg Ford said the subject is important but that getting the report correct is important as well.

“As a matter of fact, it’s probably one of the more important documents we’ve talked about in a while as we move this grid transformation and this whole idea of bringing batteries into the fold of dispatch,” he said.

“We’re trying to make this paper as solid and informative as we can so that we can allow it to take us to the next steps, whether that be guidelines or SARs [standards authorization requests] in the future, depending on how batteries come into play.”

The debate and discussion touched on the input the Inverter-Based Resource Performance Subcommittee sought as it wrote the white paper — one speaker said he saw no NERC-registered entities on the list — but centered more on the wording of the report, which some felt was too strong.

Growing Need

The version of the white paper before the committee Wednesday states that:

Studies have shown that absent supplemental synchronous machine-based solutions, grids dominated by inverter-based resources (IBRs) need grid-forming (GFM) IBRs to maintain stable operation.

Accordingly, the need for GFM technology is expected to accelerate with the rapid growth of IBRs, and planning is necessary to ensure sufficient GFM IBRs are installed.

One of the largest obstacles to installing GFM on the bulk power system (BPS) is establishing clear interconnection requirements for the performance, testing and validation of the technology.

So, the paper addresses how transmission owners, planners and coordinators can establish these requirements and test interconnecting resources.

It gives generator owners clear performance expectations for GFM resource interconnections so they can work with manufacturers before interconnection studies begin and possibly streamline the interconnection queue process.

A common question among industry stakeholders is how many IBRs should be deployed with GFM functionality; there is not a single answer, but initial studies indicate upward of 30% may be necessary.

Since the current percentage is near zero in nearly all large, interconnected power systems, the paper recommends starting to require and enable GFM in all future battery energy storage systems (BESS), a relatively low-cost step to ensure system stability.

Industry should begin specifying, requiring and implementing GFM for all new BPS-connected BESS.

Sticking Points

Words like “requiring” and “should” were problematic for some at the meeting.

“I think in this white paper, if it was just providing the technical recommendations on the specifications, I think I would let it go,” one speaker said. “But this is going further and it’s recommending that you ‘shall,’ in all battery storage applications, install grid-forming and enable it. That’s quite a strong statement to make without having industry comment.”

Ford agreed on the power of words, saying that “should be doing” and “should be considering” are different things.

Others emphasized the importance of the issue beneath the semantic debate.

“This is critical for reliability, the work that y’all are doing, and this paper is really important,” another attendee said. “Bringing the grid-forming characteristics to the surface is pretty important because we can’t wait till we need it to start thinking about getting it, because it’s too darn late at that point.”

Another said: “This is something this group asked for. We’ve been talking about it for three years. Our interconnection queue is getting tremendously bogged down with battery storage. … We are always struggling on this. Any delay is not going to do us much of a service, quite honestly.”

Another sought to reverse-engineer a solution to the debate, asking: “What are we trying to achieve here with this white paper?”

“The goal is to provide some guidance to utilities in areas that are already … considering grid-forming today,” subcommittee Chair Julia Matevosyan said.

Another speaker said he saw a wide leap in functionality between a white paper offering helpful ideas and one leading to SAR that “sets off bells and whistles of importance.”

“There ought to be a way to distinguish between the two,” he added.

Matevosyan did her best.

“If I may, I would just like to reiterate that this is just a white paper, there is no talk of SAR,” she said.

Wednesday’s vote pushes any RSTC action on the white paper back at least until the group’s September meeting.

“That was — fun,” Ford said as he called a recess, closing the matter after more than an hour of discussion.

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Blackstone Infrastructure to Scoop up Minority Stake in NIPSCO

Blackstone Infrastructure Partners will pick up a nearly 20% stake in Northern Indiana Public Service Co. for a little more than $2 billion, parent NiSource announced Tuesday.

NiSource has been on the hunt for a buyer for a noncontrolling equity interest in NIPSCO since late last year. (See NiSource Selling Minority Interest in NIPSCO.) The $2.15 billion deal will have Blackstone acquiring a 19.9% stake and pledging an additional $250 million in equity to fund a pro rata share of NIPSCO’s ongoing capital needs, according to NiSource.

NiSource said the purchase will help finance NISPCO’s continuing transition to a decarbonized fleet and reinforce grid resilience while “accelerating the reindustrialization of the Midwest.” It also said Blackstone is interested in a “long-term buy-and-hold approach to large-scale infrastructure assets.”

NIPSCO said it expects to invest $3.5 billion in the grid through 2030, with most of that going to new renewable generation to replace coal-fired assets. The company said it will end reliance on coal by 2028; that’s compared to the 75% coal generation mix it employed in 2018.

The transaction is expected to close by the end of 2023, pending FERC approval.

NIPSCO President Mike Hooper said the deal will allow NIPSCO to invest in large renewable generation projects while making capital improvements to its electric and gas infrastructure.

NiSource CFO Shawn Anderson added that the utility is “confident this is the right path forward” to boost NIPSCO’s balance sheet and “navigate the current challenging interest rate backdrop” while the utility establishes a more sustainable and reliable system.

“We’re pleased to reach this agreement at a compelling valuation following a robust and competitive process and are confident that Blackstone is the right partner for NIPSCO and NiSource going forward, given its global footprint and deep infrastructure experience, including in renewable development and procurement,” NiSource CEO Lloyd Yates said in a press release. “With this transaction, our commitment to Indiana remains unchanged, and we will be able to drive further sustainable growth for our stakeholders. This financing transaction will have no impact on NIPSCO’s current strategic direction or on our commitment to our gas and electric customers in Indiana.”

Blackstone Global Head of Infrastructure Sean Klimczak said the deal “underscores Blackstone’s commitment to decarbonization to create value for our investors and our desire to help facilitate the reindustrialization of the Midwest.”