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November 5, 2024

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ERCOT, PUC Say Texas Ready for Summer

Texas grid leaders met with reporters in Austin Tuesday to once again allay concerns about ERCOT’s management of the state’s electric supply.

“We’re ready [for the summer]. Our reforms are working. Our transition from a crisis-based business model to a reliability-based business model is showing results,” said Public Utility Commission Chair Peter Lake, referring to ERCOT’s conservative operations practice that has the ISO bringing on more reserves and doing so sooner.

“I want Texas to know that we will continue to operate with a margin of safety …. that will bring more generators online sooner rather than later,” he said.

Echoing Texas Gov. Greg Abbott, Lake said, “This grid is more reliable than it has ever been before.”

Brad Jones (Admin Monitor) Content.jpgERCOT’s Brad Jones details the grid operator’s response during tight conditions this week. | Admin Monitor

“We feel very confident about the summer,” ERCOT interim CEO Brad Jones said, pointing to a capacity planning reserve margin that has steadily increased from less than 10% in 2019 to 22.8% this year. That figure accounts for forecasted customer demand, emergency demand-reduction programs and “typical” unplanned outages and renewable energy production.

“As always, we have to be careful about those times where it’s both dark and still,” Jones said. “We have to make sure that we have the dispatchable generation to balance our fleet when wind and solar are not available, but we’re very happy to have that wind and solar development we’ve had over the past two years. It’s making our grid stronger.”

As Jones and Lake spoke, 12.6 GW of thermal generation was offline, an improvement over Monday’s 20% outage number. Wind and solar helped pick up the slack, as they have during recent days, by combining for about 29 GW of energy.

Demand peaked at just a bit more than 70 GW shortly before 4 p.m. CT Tuesday, the second straight day it has cracked the 70 GW mark.

‘Exactly as Intended’

But while May’s heat has set records, the state’s weather will only get hotter. ERCOT is expecting a record peak demand of 77.3 GW, according to its summer seasonal assessment of resource adequacy (SARA) released Monday. That would shatter the current all-time mark of 74.8 GW set in August 2019.

ERCOT expects to have 91.4 GW of resource capacity available to meet that demand during the summer, which extends into September. The SARA report includes seven risk scenarios that reflect different assumptions for peak demand, unplanned thermal outages and renewable generation output.

The ISO included the installed capacity ratings of individual generating units in the SARA for the first time as well as reporting the aggregate installed capacities of resource categories. Installed capacity ratings are based on the maximum power a generating unit can produce during normal sustained operating conditions.

Jones and Lake addressed ERCOT’s call for conservation last Friday when six gas-fired generators went offline for various reasons. Jones termed the call a “request” and noted ERCOT saw 300-400 MW of capacity freed up after the ISO issued an advisory. (See ERCOT Continues to Feel the Heat.)

“We were very surprised when several generators failed right before the peak,” Jones said. “Absent that, there would not have been a conservation appeal. It would have been a normal Friday. It wasn’t a conservation appeal. It was just a request to Texas to help us out over this weekend. It wasn’t that we’re in a dangerous situation at all; it was to make sure that we’re doing everything possible to keep the grid reliable.”

Lake was asked how he was so confident the lights would stay on given the heat yet to come and the possibility of further thermal outages.

“I know the lights are going to stay on because of all the reforms we put in place and because when we do encounter challenges like we saw last weekend, the multiple reforms are complementary and build off of each other to create even greater reliability,” he responded. “That’s how we know we can keep the lights on.”

The doubters remain. KUT Radio’s Mose Buchele was quick to paraphrase the press conference.

“Calling for statewide energy conservation out of the blue on Friday means the system is working well and exactly as intended,” he tweeted.

The grid operator on Monday also released its twice-yearly capacity, demand and reserves (CDR) report, a 10-year forecast of planning reserve margins (PRM) for the summer and winter peak load seasons through 2032. ERCOT defines the PRM as the percentage of resource capacity greater than firm electricity demand — which accounts for potential load reductions available through interruptible load programs — available to cover uncertainty in future demand, generator availability and new resources.

The CDR projects peak demand of 79.6 GW next summer that would erase this year’s expected peak. It forecasts a 36.2% PRM in 2023, 3.2 percentage points lower than the previous 39.4% margin reported in December’s CDR report. The decrease is due mainly to delays of planned projects that were previously expected to be in service by July 1, 2023.

ERCOT expects to add 13.1 GW of generation for the summer peak, with solar resources accounting for 11.7 GW available on an average basis during peak demand hours. Battery storage developers are expected to add 4.8 GW of capacity for summer 2023. The ISO currently assumes storage will provide ancillary services rather than support customer demand.

The reserve margin peaks at 46.2% for summer 2024.

The CDR expects summer peak demand to crack 90 GW in 2028, but projects energy efficiency programs to reduce that by 5.3 GW. Summer demand would peak at 95.7 GW in 2032, with energy efficiency reducing that by 7 GW, according to the report.

Winter demand would 74.7 GW during 2032-33, with the same assumed energy efficiency reduction. The CDR assumes only minimal increases in gas capacity by then, with no new contributions from coal or nuclear. Solar is projected to provide more than 31 GW, with an 81% capacity factor.

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Natural Gas Industry Sees Opportunity in Electric Coordination

Speakers at a webinar hosted by SERC Reliability on Tuesday said that electric utilities should see the natural gas industry as a partner for ensuring a reliable electric grid, rather than an obstacle.

The message was perhaps most strongly articulated by Kimberly Denbow, managing director of security and operations for the American Gas Association, who spoke midway through SERC’s “Natural Gas and Electric Coordination Vision for the Future” webinar. Previous guests had spoken of the danger of disruption to the power grid from interruption of natural gas supplies, and Denbow directed some pointed remarks at them for portraying “the electric sector as a victim of natural gas because of its dependence” on the resource.

“Do all you [electric] policy wonks see the dependence on natural gas as a growing risk … or, maybe, is the dependence not the growing risk, but rather … the federal and state policies intended to drive natural gas out of the picture?” Denbow said, referring to decarbonization initiatives that she said painted all fossil fuels with the same brush.

“Maybe that’s the growing risk, because we know natural gas supply is readily available domestically and … internationally … and it’s just a matter of being able to get the siting of the pipeline expansion and whatnot to get that supply to you all,” she added.

Brian Fitzpatrick, principal fuel supply strategist at PJM, echoed Denbow’s concern over government decarbonization policies, saying that the phrase “rapid decarbonization” sends “chills down my spine” and that he would prefer “thoughtful or smart decarbonization.” He pointed out that PJM “has been looking at [decarbonization issues] with a microscope” for the better part of a decade and found that a diverse fuel mix, including natural gas, was crucial to ensuring reliable electric service, as Denbow argued.

To illustrate why natural gas will continue to be essential to preventing severe outages, Denbow pointed to the events of Aug. 17, 2020, when Southern California was in the grip of a severe drought, along with both its hottest August on record and the worst wildfire season in modern history. As the afternoon heat increased cooling loads and raised demand for power, smoke from the fires led to decreased output from solar plants.

SoCalGas Hourly supply and demand (SERC) Content.jpgHourly supply and demand on the SoCalGas system for Aug. 17, 2020 | SERC

Natural gas production helped fill the generation gap, and Southern California Gas was able to tap stored gas supplies when the pipelines couldn’t keep up with demand. Denbow said the ability to tap storage was a critical difference between gas and other “just-in-time” power sources such as solar and wind, because it allowed the utility to ramp up generation quickly, unlike weather-dependent renewable resources.

Denbow acknowledged that, as other presenters pointed out, disruptions to natural gas supply from extreme weather, cyberattacks and other issues can lead to problems for the electric grid — as occurred in the winter storms of February 2021 in Texas and the Midwest. (See FERC, NERC Share Findings on February Winter Storm.) But she said the best way to overcome such challenges is with “communication, coordination and transparency” between electric utilities and gas distributors.

Most importantly, she urged grid planners to recognize that their industry faces the same fundamental challenges as the gas sector. She said the two industries could provide an important input, based on facts and experience, to a debate that is too often driven by the most negative, extreme voices.

“Overly ambitious, politically driven time frames, disconnected from the realities on the ground, are insufficient to help you all with re-engineering interconnections [and implementing] new investments,” Denbow said. “Layer onto this ongoing supply chain delays, as well as siting and permitting issues, and we have a formula for slow progress of emerging projects, not just on the gas side, but also on the electric side. How difficult do you think it will be to get overhead power transmission lines permitted, when below-ground, out-of-sight pipelines can’t get permitted?”

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Solar Developers: New Jersey’s Aging Grid Can’t Accept New Projects

Parts of New Jersey’s electricity grid are so old and its capacity so limited that new solar projects can’t be connected in certain areas of the state, a weakness that is stifling solar energy expansion, developers told legislators Monday.

During a Senate Energy and Environment Committee hearing for a bill that would levy a fee to generate millions of dollars to modernize the grid, developers said they wait for months, even years, to get projects connected, and sometimes the connection never happens. The problem is worst in South Jersey, where Atlantic City Electric (ACE) (NASDAQ:EXC) is the utility, but parts of the state served by Public Service Electric and Gas (NYSE:PEG) and Jersey Central Power & Light (NYSE:FE)
also have problems, they said.

“We’ve got to modernize the grid,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition. “The grid is 100 years old. It was designed for a completely different purpose. We need a system of highways; we need a system of byways. This has got to be equal access, where you can put power in any place and take it out anyplace. The only way to get there is to fund it.

“If we don’t start getting on that road right now, I can tell you that the industry is going to start to really close down,” he said.

The developers spoke in support of S431, which would establish a fixed “grid modernization” fee structure to pay for the cost of upgrading the grid, with the owners or developers of renewable energy systems paying the fee to electric utilities who would carry out the upgrades. The bill would require the New Jersey Board of Public Utilities (BPU) to create different “tiers” for the modernization fees depending on the size of the project, capping the fee for a residential net-metered system of 10 kW or less for the first three years at $50/kW.

The fee would defray the costs of interconnection, including administrative tasks or studies conducted by the utility, and infrastructure upgrades necessary for the safe operation of the renewable energy system, according to the bill. Electric utilities could charge their customers additional fees to recover interconnection costs that are not covered by the modernization fees.

In addition, the legislation would direct the BPU within 18 months of the bill’s enactment to adopt rules and regulations that would create a model procedure that conforms to those of the Interstate Renewable Energy Council (IREC).

The committee solicited public input but did not vote on the bill. A similar bill did not advance in the last legislative period, which ended in January.

Utilities said they recognize, and are taking steps to resolve, the problem.

ACE is “working to create new opportunities for solar in areas where the grid no longer has the available capacity to accommodate more solar installations,” spokesman Francis Tedesco said in an email.

“We continue to invest in and adopt new grid modeling tools and grid automation technologies as they become available,” he said, adding that such technology “allows us to optimize the system and make us better able to accommodate increasing amounts of solar.”

“As a result of our efforts, we have been able to expand interconnection opportunities for solar and continue to notify interested customers of these opportunities as they occur,” he said. “However, even with more sophisticated technologies and tools, physical upgrades to increase the capacity of the local energy grid will be required to accommodate the significant growth of solar we expect to see in the coming years.”

To help meet the challenge, the company is “working with interested stakeholders to identify the most efficient and fair path forward to expand capacity on the local energy grid to create new opportunities for solar,” he said.

PSE&G did not respond to request for comment.

A spokesperson for JCP&L, a subsidiary of FirstEnergy, said the hearing on S431 “provided a valuable opportunity for FirstEnergy representatives to hear the assessments from developers and better understand additional perspectives on interconnection.”

“We look forward to working with the sponsor and other stakeholders to provide future testimony and gather additional comments as this bill continues to evolve,” they said.

Closed Circuits

More than half a dozen solar developers — as well as representatives of the Mid-Atlantic Solar & Storage Industries Association (MSSIA) and the Solar Energy Industries Association — spoke in support of the legislation, outlining a scenario that is urgent and already hurting the industry.

Joshua Lewin, president of Somerville-based Helios Solar Energy, said the company has three customers with projects ranging from 120 kW to 1 MW that have been unable to connect a solar project to the grid. One is a data center; another is a furniture store owner that is trying to convert to clean energy with electric vehicles and heat pumps at his stores and distribution centers; and a third is a union contractor that is looking to convert its vehicle fleet to clean energy.

“Atlantic City Electric has denied us again and again,” he said. “We’ve tried multiple different ways to overcome these issues, and everything unfortunately fell through.”

DeSanti said there are now 50 circuits closed to new solar projects in the ACE area and showed the committee a map of the grid in South Jersey, in which some areas were colored black and a larger area was colored red. The grid in the black areas are “completely closed down” to new solar connections, and the area in red can accommodate no more than 250 kW of extra power, or about 25 homes, DeSanti said.

“So that means you can’t host community solar there; you can’t do grid supply there; you can’t host anything but a couple of residential [projects], maybe a small retail or warehouse facility,” he said. “But essentially, that’s pretty close to being closed as well.” He said that the legislation would create a fund to fund to invest in resolving that problem “on the backs of the development community,” who would pay the fee.

In a May 13 letter to the committee, the New Jersey Division of Rate Counsel urged members not to advance the bill, fearing that ratepayers would face unfair charges.

Rate Counsel Director Brian O. Lipman argued that a system to fund grid upgrades through set fees on developers supplemented with contributions from ratepayers would undermine the “beneficiary pays principle.” Under that principle, developers pay for grid upgrades as long as they consider that the risk is worth it and the expense allows the project to be financially viable. By placing the risk of cost overruns on the ratepayers, developers will not be as fiscally responsible in their decisions, the Rate Counsel argued.

Traditionally, the developer will pay if it considers the risk worth the reward, and that without that connection — if the developer just pays a fee and ratepayers cover the remainder — “avoidable and expensive electric system upgrades will be foisted onto captive ratepayers,” the letter said. In addition, by setting the fees every three years, they will lag the actual costs of projects, “possibly for significant periods of time,” and ratepayers may end up paying for upgrades for projects that never get built, the counsel wrote.

Clean Energy Growth

The legislative effort follows a series of hearings launched by the BPU in October that have focused on how to modernize the grid to handle the extra stress of rapidly growing solar and offshore wind generation in the state. The agency expects to release a draft report on the issue on June 27 and a final report later this year. (See NJ Launches Modernization Study.)

The state’s Energy Masterplan describes grid modernization as the “backbone on which all other efforts to transition to a clean energy economy will rely.” The plan sets a goal of 32 GW of solar-generated electricity, 11 GW of offshore wind and 9 GW of storage by 2050.

To reach that goal, the state — which had 3.89 GW of solar capacity in March — will need to deploy 950 MW of solar a year, according to the masterplan. But the state has averaged only 365 MW a year since 2016, according to BPU figures. And that installation rate could decline if developers struggle to get their projects connected to the grid. (See NJ Solar Pipeline Surges While Installations Drop.)

Supporting S431, Doug O’Malley, director of Environment New Jersey, said the grid connection problems potentially could “strangle clean energy projects before they can get onto the grid” and are already doing so.

“The critical thing to remind ourselves is that we have an electric grid that does not work for clean energy projects in a vast amount of the state,” he said. “Right now, we’re seeing essentially a de facto solar moratorium in place for certain parts of the state.”

Spreading Upgrade Costs

Similar concerns were raised by solar developers.

MSSIA President Lyle Rawlings said the grid problems in New Jersey is the “No. 1 issue that we need to address this year.”

“Many members are saying they’re abandoning Atlantic City electric territory altogether,” he said. “We are shutting down this industry, and businesses are leaving the state entirely, because they don’t see a future.”

He said New Jersey needs a statewide solution that would “socialize” the costs, or spread them across all users, replacing the current system, which is unfair, he said. At present, new solar developments connected when the circuit is open can early on be added for little cost but when it can handle no more, “the last one in has to pay for upgrades for the whole circuit, after a large number of projects got a free ride,” Rawlings said.

Kyle Wallace, director of public policy for Sunrun, said that if the modernization fee had been in place in some of the state’s busiest solar installation years — from 2016 to 2018 — it would have raised $3 million a year for grid upgrades. That would have been sufficient to improve the grid enough that those circuits now closed to new projects would still be open, he said.

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FirstEnergy Shareholders Approve Smaller Board of Directors

Shareholders at FirstEnergy’s (NYSE:FE) virtual annual meeting Tuesday approved a smaller board of directors, as agreed to by the company earlier this year to resolve shareholder lawsuits stemming from the company’s bribery of a top Ohio lawmaker for a financial bailout for two nuclear power plants.

Six long-time directors agreed not to stand for re-election, according to the agreement in the court stipulation. All had been named as defendants in the lawsuits.

At 12 directors, the board returns to its traditional size. Among the 12 are two directors first appointed in 2021 who are employees of Icahn Enterprises. (See FERC Authorizes Icahn Employees for FE Board.) Icahn owned 3.32% of the company’s outstanding shares as of March 3, FirstEnergy institutional investment records show.

A third new director is connected with Blackstone, which invested $1 billion in FirstEnergy stock at the end of last year and asked for a seat on the board. Blackstone owned 5.05% of outstanding shares as of Dec. 31, 2021, according to FirstEnergy.

John W. Somerhalder II, vice chairman and executive director of the board since last year, was elected chair of the board. He previously served as interim director and CEO of CenterPoint Energy.

Shareholders also rejected two proposals by activist shareholders. One from California-based John Chevedden would have amended the company’s shareholder rights policy to give shareholders with a combined 10% of outstanding shares the right to call special shareholder meetings.

The board recommended shareholders reject the proposal — which has appeared periodically in annual meetings since 2011 — and added that it plans to set the combined ownership threshold for such special meetings at 20% in 2023.

A second proposal, offered by Steven J. Milloy of Potomac, Md., would have required the company to investigate whether child workers were involved in mining cobalt in the Congo before creating electric vehicle charging stations.

Shareholders rejected both proposals, according to unofficial results, which the company must still file with the Securities and Exchange Commission.

Following the vote, Donald Misheff, outgoing chairman and one of the six veteran board members who did not seek re-election, said it had been “a great privilege to serve on your board. Under the leadership and guidance of our 2022 director nominees and our management team, I’m confident FirstEnergy will continue to move forward as a stronger, customer-focused organization.”

In brief, previously recorded remarks following Misheff, CEO Steven Strah said the changes enacted by the board and his management team over the last two years have put the company in a position to recover its reputation as well as its profitability.

“In 2021, we embraced pivotal changes — changes which advanced a culture that prioritizes integrity and accountability. We also embraced transformation and innovation to reimagine our company and reshape it into a more forward-thinking, premier utility.

“In the last year, we’ve implemented substantial actions to resolve the challenges we’ve been working through since 2020. These actions include strengthening the leadership team, building a best-in-class compliance program and substantially modifying our approach to political engagement,” Strah said.

The proxy statement outlining the issues taken up at the annual meeting can be found here.

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Energy Storage ‘Just Scratching the Surface’ Despite Supply Challenges

ATLANTA — Despite current supply chain problems, energy storage is just beginning to capture its potential, developers told the RE+ Southeast conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA), last week.

Raafe Khan, director of energy storage for Pine Gate Renewables, said supply chain problems have “definitely put a dent in many developers’ plans” but predicted the problem will ease because of “all these giga factories coming online in the next six to 12 months.”

Speakers expressed optimism over the resource’s future in supplying capacity and reducing demand charges and offered varying projections on the need for storage of longer than four hours.

Sizes Needed

Dmitri Moundous, senior manager of storage business development for Cypress Creek Renewables, said most peaking capacity needs in the near term can be served by two- to four-hour storage, with six- and eight-hour plus storage not widely needed until the 2030s.

Dmitri Moundous 2022-05-11 (RTO Insider LLC) FI.jpgDmitri Moundous, Cypress Creek Renewables | © RTO Insider LLC

“Once you get into those scenarios of 90-plus percent renewables, that’s when you start seeing multi-day and seasonal needs start showing up.”

Edward May, managing partner of Energy Intelligence Partners Consulting, said the need for longer-term storage may be coming faster than anticipated.

“We have been surprised. We have seen a couple of big, integrated utilities whose draft IRPs are reflecting some level of long-duration storage relatively soon,” he said.

“There seems to be plenty of room for two- and four-hour duration for the foreseeable future, but we are seeing some of the big utilities who are running their internal models and coming back and saying, ‘Actually, our models are telling us that … there is some value from long-duration storage in certain spots, on seams, things like that.’”

Reducing Demand Charges

May said he also sees increasing use of storage to reduce demand charges: “Co-ops, which are effectively just big C&I [commercial and industrial] customers, are subject to the same demand charges that a big manufacturing plant [has]. Some are going through the court systems to be allowed … to find ways to get batteries to be used as an asset that they can utilize.”

Edward May 2022-05-11 (RTO Insider LLC) FI.jpgEdward May, Energy Intelligence Partners Consulting | © RTO Insider LLC

In February, FERC ordered Duke Energy Progress (NYSE:DUK) and the North Carolina Eastern Municipal Power Agency (NCEMPA) to negotiate over how their supply contract should be changed to reflect the NCEMPA’s use of batteries to shave its demand charges (ER22-682). (See FERC Orders Negotiations in Duke-Muni Contract Dispute.)

Reducing usage during the time periods when demand charges are assessed “can save 50% off your bill,” he said. “So it’s pretty big number.”

“There are some co-ops in the Southeast that prior to energy storage … employed a person to sit at the desk and watch the weather,” he added.

“And basically, when temperatures are going to spike, they put on all their demand response and turn on diesel gensets at their largest customers.”

Storage as Capacity

Moundous said he wants to see storage grow beyond a grid following role to provide inertia support in areas like the Texas panhandle. “And we’re gonna see more and more of that on higher renewable penetration systems,” he said. “We have not scratched the surface of how much energy storage can provide capacity, in both regulated and deregulated markets, and how much you can displace uneconomic coal plants. So let’s get that done first and deploy in gigawatt scale.”

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West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says

Drought, wildfires, plant retirements and transmission outages have elevated the risk of supply shortfalls in the West, Texas, MISO and SPP, NERC said in its Summer Reliability Assessment on Wednesday.

“It’s a pretty sobering report,” John Moura, NERC’s director of reliability assessment and performance analysis, said in a media briefing. “It’s clear the risks are spreading. … Year after year, extreme weather is leading to reliability impacts.”

MISO’s North and Central areas face a “high risk of energy emergencies during peak summer conditions” because of a capacity shortfall and the outage of a key transmission line, NERC said in the assessment, which covers June to September. Drought is the cause of concern in Texas, and drought and wildfire risks will present challenges in the West, the report said.

Risk of Load Sheds in MISO/MRO

MISO has been unable to reverse capacity shortfall projections NERC has reported since 2018, with load-serving entities in four of its capacity zones currently lacking sufficient owned or contracted capacity to cover their requirements. (See OMS Drafting Letter over MISO Resource Adequacy Concerns.)

On Peak Reserve Margins (NERC 2022 Summer Reliability Assessment) Content.jpgOn-peak reserve margins for summer 2022 | NERC 2022 Summer Reliability Assessment

The RTO faces both a 1.7% increase in projected peak demand — largely a rebound from the pandemic — and a 2.3% (3,200 MW) reduction in generation capacity compared with summer 2021.

“System operators in MISO are more likely to need operating mitigations, such as load-modifying resources or non-firm imports, to meet reserve requirements under normal peak summer conditions,” NERC said. “More extreme temperatures, higher generation outages or low wind conditions expose the MISO North and Central areas to higher risk of temporary operator-initiated load shedding to maintain system reliability.”

MISO also will enter summer lacking a 500-kV transmission line that was damaged by a tornado in December. That will affect 1,000 MW of firm transfers between MISO Midwest and South, including parts of Arkansas, Louisiana and Mississippi. Restoration of a 4-mile section of the line is expected at the end of June.

Canada’s Saskatchewan, which is part of the Midwest Reliability Organization, has seen a 7.5% increase in projected peak demand since 2021. Although SaskPower is projected to remain above its planning reserve margin, with sufficient operating reserves for normal peak conditions, “external assistance is expected to be needed in extreme conditions that cause above-normal generator outages or demand,” NERC said.

Dry in the West, Texas, SPP

Drought conditions in Texas and much of the West threaten to reduce hydropower output and pose “unique challenges to area electricity supplies and potential impacts on demand,” NERC said.

Below-normal snowpack threatens the availability of hydroelectricity for transfers throughout the Western Interconnection, a particular risk for WECC’s California-Mexico (CA/MX) and Southwest Reserve Sharing Group (SRSG), which depend on imports to meet demand on hot summer evenings and other times when wind and solar output are reduced. “In the event of wide-area extreme heat event, all U.S. assessment areas in the Western Interconnection are at risk of energy emergencies due to the limited supply of electricity available for transfer,” the assessment said.

Much of Texas also faces extreme drought, which NERC said “can produce weather conditions that are favorable to prolonged, wide-area heat events and extreme peak electricity demand.”

US Summer Forecast (National Oceanic and Atmospheric Administration) Alt FI.jpgThe National Oceanic and Atmospheric Administration forecasts above average temperatures this summer for virtually all of the lower 48 states. | National Oceanic and Atmospheric Administration

 

Recent additions of solar and wind have raised ERCOT’s anticipated reserve margins above reference margin levels, meaning the grid operator should have sufficient capacity for normal peak demand. But extreme heat will increase peak demand and could cause a spike in forced outages or reduced output from generating resources. “A combination of extreme peak demand, low wind and high outage rates from thermal generators could require system operators to use emergency procedures, up to and including temporary manual load shedding,” NERC warned.

Mark Olson (NERC) Content.jpgMark Olson, NERC | NERC

Mark Olson, manager of reliability assessments, said another risk is the retirement of thermal plants and influx of renewables.

“There are fewer and fewer thermal plants in a number of areas as generation retires. So the ones that are remaining are being driven hard. They have to cycle to be able to balance variable energy,” he said.

“That takes a toll on the plants. So we can expect to see higher forced outage rates in the future [and] more generation mechanical issues.”

Continued drought in the Missouri River Basin also could result in reduced output from thermal generators in SPP that use the river for once-through cooling. Output from hydro generators on the river may also be reduced.

Solar PV Tripping Remains an Issue

Unexpected tripping of solar PV resources during grid disturbances remains a problem despite attempts to address it since 2016, with widespread losses last May and June in Texas and four events in California between last June and August.

“During these events, widespread loss of solar PV resources was also coupled with the loss of synchronous generation, unintended interactions with remedial action schemes and some tripping of distributed energy resources,” NERC said.

Since the 2016 Blue Cut Fire in California, which caused nearly 1,200 MW of solar PV to trip offline, NERC has been warning that the lack of inverter-based resources’ (IBRs) ride-through capability risks turning minor system disturbances into major ones.

NERC said a series of trips last year “reinforces that improvements to NERC reliability standards are needed to address systemic issues with IBRs,” an issue highlighted in a joint NERC-WECC report last month. (See NERC, WECC Repeat Solar Performance Warnings.)

The report said that the one inverter manufacturer involved in the Blue Cut Fire “quickly and proactively responded by ensuring that all [bulk power system]-connected solar PV facilities changed their frequency protection settings to avoid future issues. However, these disturbances in 2021 involve different inverter manufacturers, illustrating that the issue is still not widely understood or addressed across all manufacturers and plant owner/operators.”

Although NERC standards require documentation that demonstrates compliance with ride-through requirements in PRC-024-3, “they do not specify a certain degree of performance that must be met,” the organization said, calling for the standard to be retired and “replaced with a comprehensive ride-through standard that focuses specifically on the generator protections and controls.”

NERC “strongly recommends that a performance validation standard be developed that ensures that reliability coordinators, transmission operators or [balancing authorities] are assessing the performance of interconnected facilities during grid disturbances, identifying any abnormalities and executing corrective actions with affected facility owners to eliminate these issues.”

On Wednesday, NERC’s Standards Committee approved the Inverter-Based Resource Performance Subcommittee’s request to approve a standard authorization request to address the issue. (See “Other Standards Actions” in NERC Cold Weather Standards Set for Shortened Comment Period.)

John Moura (NERC) Content.jpgJohn Moura, NERC | NERC

“These types of risks have the potential to have a widespread impact across the entire interconnection, and that’s really the entire Western Interconnection, or the entire Eastern Interconnection, or the entire Texas Interconnection if you’re in ERCOT,” Moura said. “It’s a matter of keeping the balance of supply and demand. And if the supply and demand balance is shifted — even 1,000 MW very quickly — that really creates real trouble for the operators. They’re not used to dealing with this huge imbalance.

“The inverter tripping challenge is really one of the most risky issues I think we have to deal with as an industry in order to ensure we can reliably integrate interconnect the nearly 500 GW of solar we see coming online in the next 10 years,” he added.

NERC also has issued recommendations that electromagnetic transient (EMT) modeling and studies be incorporated into its reliability standards. “Existing positive sequence simulation platforms have limitations in their ability to identify possible performance issues, many of which can be identified using EMT modeling and studies,” NERC said. “As the penetration of IBRs continues to grow across North America, the need for EMT modeling and studies will only grow exponentially. Furthermore, NERC reliability standards need enhancements to ensure that model accuracy and model quality checks are explicitly defined.”

Moura said NERC wants FERC to add a requirement for EMT modeling in its pro forma interconnection agreement to ensure reliable connection of asynchronous inverter-based resources: solar, batteries or wind.

“In the past, when you interconnected a synchronous generator, you simply do a power flow analysis, a voltage stability analysis and a feasibility study,” he said.

When IBR resources were a smaller contributor, “maybe we didn’t need to do those [EMT] studies. But as … we’re seeing more and more, these types of studies are absolutely necessary. We cannot integrate resources reliably without doing those studies.”

Other Reliability Issues 

NERC also identified several other concerns:

  • Supply chain problems and staffing shortages are hampering efforts to complete new generation and transmission projects needed for reliability. WECC-CA/MX and WECC-SRSG “have sizeable amounts of generation capacity in development and included in their resource projections for summer,” while ERCOT is rushing to complete transmission projects to address transmission constraints and maintain system stability, NERC said. It warned of transmission congestion during peak conditions and reduced ability to serve load in localized areas. It said generator and transmission owners must inform their BAs, TOPs and RCs of any delays so they can develop responses.
  • Supply chain problems are also making it difficult for some coal-fired generators to obtain fuel and other supplies, with coal stockpiles “relatively low” compared to historical levels. Coal plants say their fuel supplies have been pinched by mine closures, rail shipping limitations and increased coal exports. “No specific BPS reliability impacts are currently foreseen,” NERC said.
  • The grid and other critical infrastructure sectors face cybersecurity threats from Russia and other potential actors, particularly because of Russia’s invasion of Ukraine. The Electricity Information Sharing and Analysis Center is sharing information with its members on potential threats.
  • An active late-summer wildfire season in the Western U.S. and Canada also poses threats. Above-normal wildfire risk is expected beginning in June across much of Canada, in the U.S. South Central states and in Northern California. In New Mexico, the Hermits Peak/Calf Canyon Fire has grown to almost 300,000 acres, making it the largest in state history. “If drought conditions persist, the fire outlook for late summer would likely extend across the Western half of North America,” NERC said, noting the potential for damage to transmission lines or pre-emptive shutdowns to avoid sparking blazes. In addition, smoke from wildfires can reduce output from solar PV.
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MISO Exec, IMM Debate Next Steps After Capacity Auction Shortfall

A month after its capacity auction indicated a Midwestern supply scarcity, MISO’s Independent Market Monitor and a MISO vice president debated the path forward in front of Illinois regulators.

During a special policy session of the Illinois Commerce Commission (ICC) last Friday on MISO’s resource adequacy, ICC Chair Carrie Zalewski said the commission wanted “to gain a fuller understanding” of the 2022-23 planning resource auction (PRA) clearing at the cost-of-new-generation entry and to discuss steps to preserve reliability and affordability as the RTO’s resource mix transitions.

Zalewski said the $236.66/MW-day clearing price in MISO Midwest is a significant increase over the $5/MW-day clearing price during the 2021-22 capacity auction. The grid operator has told stakeholders to prepare for the possibility of temporary, controlled load sheds during the summer months because of a 1.2 GW capacity shortfall in the Midwest. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Melissa Seymour, MISO’s vice president of external affairs for its Central Region, said members must build more capacity quickly. The IMM’s David Patton said the RTO is duty-bound to design an auction that results in higher clearing prices to prevent its existing thermal fleet from hemorrhaging more units.

Seymour said accredited capacity in MISO Midwest sank about 3.2 GW since the 2021-22 auction, primarily because of coal plant retirements. She said that though MISO continues to add more installed capacity year-over-year, retiring thermal generation has higher accredited capacity values than the accredited value of new renewable generation.

“Wind and solar do not get the same capacity credit as a traditional thermal unit,” Seymour told the ICC. MISO’s wind generation receives about a 15.5% capacity credit, while solar receives an approximately 50% capacity credit during summer peak times.

“We believe that unless more capacity is built over the next year, we’ll continue to see what we saw in this auction continue in the future,” she said. “We will do everything we can to make sure the overall grid stays reliable and dependable, and that the system won’t be compromised. But we do have less than a one-day-in-10 [year] loss-of-load probability because of the auction not meeting the requirements, so there is a chance that we might have to take actions to prevent blackout situations or rolling brownout situations.”

Seymour said MISO will likely take steps to increase visibility into the supply and demand picture ahead of capacity auctions.

She also said she thought that some market participants had more capacity that they could have offered, namely demand response resources. No market participants violated MISO’s 50-MW withholding threshold in the 2022-23 auction.

Seymour predicted high clearing prices will continue until MISO’s members bring more capacity online. But she also said the RTO’s proposed seasonal auction design — waiting on FERC approval — and new capacity accreditation calculations based on actual generation availability should help alleviate future shortages. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)

But Seymour also reminded commissioners that MISO’s capacity auction is a residual auction that functions like a “balancing market,” and that it isn’t meant for market participants to procure all resources to meet demand.

IMM: Capacity Auction Design the Culprit

Patton laid the shortfall’s blame squarely on “poor market signals” in the capacity auction.

“It’s not hard to understand how we got here,” Patton said. He told the ICC that the “unfortunate truth” is that MISO’s capacity market isn’t designed to signal when to stave off generation retirements or make investments. He said the vertical demand curve isn’t “aligned” with the reliability value of capacity and clearing prices have been “grossly understated” for years.

David Patton (ICC) Content.jpgMISO IMM David Patton speaks to the Illinois Commerce Commission | ICC

Patton said about 4 GW of MISO’s merchant capacity has retired over the past four years because of economic reasons. He said some of that generation would have remained online had clearing prices more closely reflected a unit’s going-forward costs of about $110-$175/MW-day. He said an efficient capacity price might even cover some of the units’ capital costs for new emissions controls to comply with environmental regulations.

“If we’re going to learn anything from this, we ought to learn that market signals really do matter and we ought to fix this market so that it will help the region maintain enough capacity to maintain reliability,” Patton said.

He urged the commissioners to support a sloped demand curve in MISO’s auction.

“That’s the only thing in the long term that’s going to solve this problem,” Patton said. “And I think the only reason MISO doesn’t have it is because the states have opposed it. And now, one-by-one, the states are starting to either be interested or support it. And I think the more states that voice their support for it, the more momentum there will be to come to a consensus.”

Illinois, as a retail choice state, should weigh in on the demand curve and persuade the Organization of MISO States to move the issue forward, Patton said.

He also pushed back on the argument that lower-accredited renewable energy is ousting higher-accredited thermal units.

“It’s not as if participants say, ‘I’m going to retire a 100-MW gas plant and replace it with 100 MW of wind,’ imagining in their minds that that’s a one-for-one tradeoff. The reality is the investment in renewables is happening independent of the decision to retire resources,” Patton said. “So, it’s true that they’re coming in at lower accredited values, but the real problem is that a number of the resources that retired really should not have retired, regardless of what was going on in the renewables side of the equation. It’s just that we didn’t give them the economic incentive to stick around.”

Seymour countered that MISO’s capacity auction is not designed to incentivize resources or bring new capacity online because states oversee their own resource adequacy planning.

She agreed that a sloped demand curve in previous auctions may have led to higher auction prices and driven some generation construction and prevented some generation from retiring. She also said MISO’s pending request at FERC to employ a minimum capacity obligation rule, where load-serving entities must procure 50% of their load obligation ahead of the auction, may assuage capacity deficiencies.

Patton said he didn’t see how a minimum capacity rule would increase supply. He said the rule would only have load-serving entities bilaterally contracting for the same stock of surplus.

“It’s hard to imagine that it’s going to increase the amount of physical supply that exists. It just moves some of the settlements from the PRA into the bilateral market,” he said. “Until you fix the price in the PRA, you’re not creating an incentive for anybody to build anything that would help you get out of the shortage.”

MISO expects about 11 GW of generation to retire over the next year, Seymour said.

“Excess is going away in most instances. We’re seeing people come more in balance or a little bit short of their total requirement, mostly because people are deciding to retire their older units … and not replacing [with] a one-for-one … whether it be thermal or wind and solar,” Seymour said.

She said federal environmental regulations and utilities’ own green goals are creating a “gap” between resource retirements and resource additions. MISO expects to be in a “mind-the-gap” situation in the 2023-2025 timeframe, Seymour said.

In a majority-renewable future, the RTO is probably going to have resources that don’t run very often to provide inertia, frequency response and voltage support, she said.

ICC Commissioner Maria Bocanegra said one of her biggest fears is repeating a blackout situation similar to ERCOT’s prolonged blackouts during the February 2021 severe winter storm.

Seymour said that unlike ERCOT, MISO is not an island and can import considerable amounts of power.

“That is one of the biggest things that we have going for us that ERCOT didn’t,” she said. “They had minimal access to anything outside of the ERCOT footprint to be able to import to serve their need.”

Seymour reminded commissioners that during the same winter storm, MISO was able to import supply from PJM and in turn, export power to SPP.

Patton Says Real Threat Begins Next Summer

Patton told commissioners that he doesn’t expect blackouts in MISO this summer.

“I think load shed in MISO is extremely unlikely this summer, because some of the resources that didn’t sell in the capacity auction are actually still going to be around during the summer,” he said. “They’re retiring after the summer. So, I don’t think the threat of load shed is very high for MISO for this planning year. I’m a little more worried about after some of these retirements that are in process disappear …  and they won’t be there next summer.”

The IMM allows retiring generators an exemption from offering into the PRA when they plan to retire and won’t be available for the entire planning year.

Late-spring heat paired with seasonal maintenance outages has already forced MISO to issue two emergency advisories before the June 1 start of the 2022-23 planning year.

MISO declared a maximum generation emergency alert Friday afternoon for its Central region. The grid operator said it was experiencing forced generation outages, above normal temperatures and higher than forecasted load. On Tuesday, the RTO declared conservative operations for its South region through Friday.

The Industrial Energy Consumers of America (IECA) sent a letter to FERC Chair Richard Glick, urging the commission to issue a notice of proposed rulemaking to overturn the state opt-out for demand response.

IECA CEO Paul N. Cicio said it is “of immediate importance” that FERC reverse the opt-out, which allows states within a regional grid to block distributed resources from participating in wholesale energy markets.

“This action will reduce inflation, electricity costs and improve reliability,” the IECA wrote. “We believe that your action will impact the next PRA in MISO and help to drive down prices of which all consumers will benefit. This could ensure that our factories continue to operate and maintain jobs at a time when our economy desperately needs the assistance.”

IECA argued a continuation of the rule has contributed to MISO’s capacity crisis.

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Port of Seattle Looks to Get into Hydrogen Business

The Port of Seattle is studying if and how it should get into the business of producing and distributing hydrogen.

Realistically, that move — if made — is a few years down the road.

The port wants to trim its carbon footprint and be a player in the fledgling hydrogen supply economy, Ryan Calkins, president of the port’s commission, told NetZero Insider. There is some urgency for the port getting into the field as medium- and heavy-duty trucks, plus ships are likely to switch to hydrogen fuels. “We really need to build this soon,” Calkins said.

For example, a handful of hydrogen-fueled ships, mostly ferries, are now in use in northern Europe and Japan. Calkins believes the shipping industry, which accounts for 2.2% of worldwide greenhouse gas emissions, could gradually expand more into using hydrogen as a fuel, which would mean those vessels will use ports where hydrogen is stored.

The Port of Seattle and some partners are conducting two studies covering whether the port should get into the hydrogen business and how, where to locate facilities, costs, potential customers and storage. The federal government has provided $2.12 million to the port to tackle the studies.

“This is to get a better understanding of what this will look like,” Calkins said. 

The port is one year into a two-year study on the big picture of getting into the hydrogen fuel business. Its partners on the study are Seattle City Light, Pacific Northwest National Laboratory and Sandia National Laboratory. 

A second two-year study by the port and Seattle City Light is expected to start soon and will look at hydrogen storage issues, such as types and sizes of tanks, and examine safety risks, such as the potential for explosions.

Washington officials are making a big push to have the U.S. Department of Energy select the state as one of four to eight national “hydrogen hubs” to be funded by $8 billion in appropriations from the Infrastructure Investment and Jobs Act. State lawmakers in March passed a bill to create a new Office of Renewable fuels to support the develop of hydrogen and other renewable fuels. (See Green Hydrogen Bill Passes Wash. Legislature.)

At a carbon policy forum held in Seattle last month, state Sen. Reuven Carlyle said, “This is a ruthless competition nationwide. It’ll be political malpractice not to leave everything on the field.”

Hydrogen efforts are already taking shape in other parts of the state. In Central Washington, Douglas County Public Utility District is constructing what will be the state’s first green hydrogen production facility near its Wells Dam on the Columbia River. The $25 million project is expected to go online in late 2022 or early 2023.

Last week, Australia-based Fortescue Future Industries said it would examine converting a disused Centralia, Wash., coal mine into a green hydrogen production facility. Centralia is located about 85 miles south of Seattle. (See Australian Company Eyes Closed Wash. Coal Mine as Green Hydrogen Site.)

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MISO, SPP Hold 1st Common Seams Initiatives Meeting

MISO and SPP staff and stakeholders discussed transmission reconfigurations and the search for smaller interregional transmission projects Tuesday during their inaugural Common Seams Initiatives (CSI) meeting.

The RTOs announced the biannual meetings last month as a means to better inform stakeholders on how they’re improving seams coordination. (See MISO and SPP Announce New Interregional Stakeholder Meetings.)

Staff said the meetings make sense because both RTOs list seams work as strategic priorities. They will replace the grid operators’ joint operating agreement meetings and no votes will be held.

SPP Senior Interregional Coordinator Clint Savoy said the virtual, informational meetings will span the RTOs’ planning, operations, markets and regulatory activity and serve as an “all-encompassing ‘here’s what we’re working on.’”

RTO staffs said they’re working to create web pages for CSI meetings. Savoy said the grid operators are open to hearing stakeholder-led presentations and that some meetings may be held in-person.

Tuesday, staff focused on five recommendations state regulators handed down to MISO and SPP in early 2021. The Organization of MISO States and SPP’s Regional State Committee’s Seams Liaison Committee (SLC) have advised the RTOs to consider creating targeted market efficiency projects (TMEPs), improve their respective generator interconnection queue processes, track and address rate pancaking at the seams, keep state regulators apprised of long-range planning efforts and devise coordinated transaction scheduling and market-to-market (M2M) interface pricing. (See MISO, SPP Regulators Call for Pancaking Fix, Smaller Projects.)

In February, the grid operators announced plans to conduct a TMEP study this year that will search for smaller, congestion-relieving cross-border transmission projects. (See MISO, SPP Take on 2nd Interregional Planning Effort.)

Savoy said MISO and SPP are aiming for an “easily repeatable” process that could be conducted every year, if necessary. He said the RTOs are compiling two years’ worth of seams congestion data to identify potential projects and will negotiate a cost-allocation design in 2023.

The two have also participated in the SLC’s Rate Pancaking Working Group to inventory instances of rate pancaking and develop solutions.

Debate on MISO Tx Reconfiguration

Savoy said SPP is conducting a constraint management analysis of its day-ahead handling of MISO market-to-market constraints “to see if anything needs to change.” The results will eventually be shared with MISO and stakeholders. (See SPP Reviewing its M2M Processes After MISO Monitor’s Comments.)

Meanwhile, MISO has formed the nonpublic Reconfiguration for Congestion Cost Task Team (RCCTT), which focuses on plans to reroute transmission flows during times of heavy congestion costs. Tony Rowan, senior manager of north reliability coordination, said MISO’s increasing transmission congestion caused some of its northern market participants and third-party vendors to suggest reconfiguration options. Rowan said the requests were unusual and that transmission owners rejected most of the recommendations over reliability concerns.

The RCCTT is maintaining a monthly list of MISO’s top congested constraints, including M2M flowgates. SPP staff said they have been meeting with RCCTT leadership to share their information on flowgate congestion.

EDF Renewables’ Arash Ghodsian pointed out that much of the RTOs’ work to address seams congestion is being done behind closed doors.

“We talk about urgency. Obviously near-term congestion is happening,” Ghodsian said. He asked for future educational sessions on staffs’ work on seams congestion.

Minnesota Public Utilities Commission staffer Hwikwo Ham asked the grid operators to research Iowa’s Interstate Power and Light’s recent transmission reconfiguration, which he said has lowered ratepayer bills.

“Southwest Minnesota is a total mess at this point,” Ham said of the need for reconfiguration. “We are leaving tons of money on the table given the level of congestion in Southwest Minnesota and Iowa.”

American Electric Power’s Jim Jacoby said he is concerned that MISO’s reconfiguration work might harm system reliability.

“I would think you’d want to fix a problem before reconfiguring the system,” he said.

Rowan said some the congestion may already have led to transmission projects. He said RCCTT members are working to avoid simply “masking” congestion problems and keeping them open for project opportunities.

“That is very much at the forefront of discussions in the RCCTT,” Rowan said.

WPPI Energy’s Steve Leovy said the reconfiguration work is focused on congestion caused by temporary, unusual conditions.

“We need to both improve the system and squeeze more out of the system if we can to operate the system as efficiently as we can. … I see room for both,” Leovy said.

Before closing the meeting, MISO’s Jack Dannis said the RTOs are monitoring a possible minimum transmission transfer capacity, as suggested by FERC’s Joint Federal-State Task Force on Electric Transmission.

Dannis said the November CSI meeting will focus on a possible transfer requirement between the regions.

Savoy said SPP intends to include a minimum transfer capacity with MISO in its five-year strategic plan. “This is something we should be discussing and determining how it will look,” he said.

American Clean Power Association’s Daniel Hall thanked the RTOs for teeing up the topic.

“I certainly think the tea leaves are such that FERC will do something in this arena. I think it behooves all of us for MISO and SPP to look into this,” he said.

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Rhode Island Advocates: Fund State Transit Master Plan to Reduce VMTs

Fully funding Rhode Island’s Transit Master Plan could reduce residents’ vehicle miles traveled (VMT) by 8% and should be a key recommendation in the state’s next greenhouse gas emissions reduction plan, Mal Skowron, transportation program and policy coordinator at the Green Energy Consumers Alliance, told state officials Tuesday.

Skowron made her recommendation during a listening session of the Rhode Island Executive Climate Change Coordinating Council (EC4) on priorities for reducing transportation emissions that should be in the update to the 2016 GHG Emissions Reduction Plan. Rhode Island’s Act on Climate, which Gov. Dan McKee signed last spring, directs the EC4 to submit the updated plan to the legislature by the end of the year.

Listening session attendee Hans Scholl agreed with Skowron’s call to fund the plan, saying that the “vast majority of Rhode Islanders live within 10 minutes of public transportation, but it’s just totally underutilized.”

Capital costs of the Master Plan would be $1.9 billion to $3.1 billion through 2040, with operating costs of $237 million annually.

Reducing VMTs is one of the actions recommended in the 2016 GHG plan to cut transportation emissions from fossil fuels. The EC4 is considering priority actions for the plan update that could further a VMT reduction goal, including increasing transit and share ridership.

The State Planning Council adopted the transit plan in December 2020 under the umbrella of a Long-Range Transportation Plan. Funding for some of the plan was in place at the time of its adoption, but full implementation isn’t expected until 2040. Since its adoption, additional funding has been moving more of the plan forward.

U.S. Sen. Jack Reed helped secure a $900,000 grant to study a major transit corridor expansion as recommended in the plan for services that provide high-volume markets with fast and frequent service. An additional $225,000 in matching funds for the study are included in McKee’s proposed FY23 budget.

The transit plan said high-capacity services could include rapid bus routes with limited stops and light rail featuring two-car trains.

Completion of the study will allow the state to take advantage of funding opportunities in the Infrastructure Investment and Jobs Act, Reed said.

Rhode Island’s 2016 GHG reductions strategy also recommends electrification of the Rhode Island Public Transit Authority’s (RIPTA) bus fleet and state passenger and freight rail systems.

“RIPTA has made a lot of progress with electrifying its fleet,” Carrie Gill, chief economic and policy analyst at the Rhode Island Office of Energy Resources, said during the listening session.

McKee and Reed joined authority officials Friday to break ground on the state’s first charging station for electric buses to use while on a route during service hours. The governor also announced Thursday that RIPTA has issued a request for expressions of interest to design a new transit center that would support transit growth as envisioned in the master plan.

The EC4 held a listening session on the electric sector in April to inform the GHG plan update, and another session is scheduled for the thermal sector (residential, commercial and industrial heating and natural gas distribution) in June.