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Federal Energy Regulators Finalize Rules to Bolster Reliability Against Extreme Weather Threats

June 15, 2023

by Paul Ciampoli
APPA News Director
June 15, 2023

The Federal Energy Regulatory Commission on June 15 finalized two rules intended to help improve reliability of the bulk power system against threats of extreme weather.

One rule directs the North American Electric Reliability Corporation to develop a new or modified reliability standard to require transmission system planning for extreme heat and cold weather conditions over wide geographical areas, including studying the impact of concurrent failures of bulk power system generation and transmission equipment and implementing corrective actions as needed.

In a presentation at FERC’s open meeting, Commission staff noted that NERC must develop a new reliability standard or modifications to the current transmission planning Reliability Standard, TPL-001-5.1, no later than 18 months from the date of publication of the final rule in the Federal Register.

Specifically, the final rule directs NERC to develop a new or modified reliability standard that addresses three major concerns. 

First, the draft final rule requires the proposed standard to define benchmark events based on prior extreme heat and cold weather events and/or future meteorological projections. 

Second, the proposed standard must require planning entities to develop planning cases for extreme heat and cold weather events using steady state and transient stability analyses that cover a range of extreme weather scenarios, including the expected resource mix’s availability during extreme weather conditions and the wide-area impacts of extreme weather. 

Third, to the extent these planning studies discover specified instances when performance requirements during extreme heat and cold weather events are not met, the proposed standard must require planners to develop corrective action plans to allow the performance requirements to be met.

The second rule directs transmission providers to submit one-time reports describing their policies and processes for conducting extreme weather vulnerability assessments and identifying mitigation strategies (Docket Nos. RM22-16, AD21-13).

FERC staff noted that an extreme weather vulnerability assessment — as defined in the final rule — is any analysis that identifies where and under what conditions jurisdictional transmission assets and operations are at risk from the impacts of extreme weather events, how those risks will manifest themselves, and what the consequences will be for system operations. 

The final rule directs FERC-jurisdictional transmission providers to file one-time informational reports describing how they conduct extreme weather vulnerability assessments, if at all. 

Specifically, transmission providers will need to report how they:  1) establish a scope; 2) develop inputs; 3) identify vulnerabilities and exposure to extreme weather hazards; 4) estimate the costs of impacts; and 5) use the results of vulnerability assessments to develop risk mitigation measures. 

FERC staff said the reports would provide the Commission with a fuller record as to whether and how transmission providers assess and mitigate vulnerabilities to extreme weather and will enable coordination among transmission providers as well as information sharing on best practices.

The final rule reflects certain changes from a related Notice of Proposed Rulemaking, FERC staff said.  The changes include requiring reporting on how transmission providers define extreme weather and requiring reporting on how Regional Transmission Organizations and Independent System Operators account for differences between transmission owner members’ assumptions and results. 

The new rules stem from the Commission’s June 2021 technical conference on Climate Change, Extreme Weather and Electric System Reliability.

Both rules take effect 90 days after publication in the Federal Register.

Senators Urge DOE to Reconsider Transformer Conservation Standards Proposal

June 1, 2023

by Paul Ciampoli
APPA News Director
June 1, 2023

The Department of Energy should reconsider its proposed rule to increase conservation standards for distribution transformers, 47 U.S. senators said in a June 1 letter to Secretary of Energy Jennifer Granholm. The bipartisan letter was led by Senator Bill Hagerty (R-TN).

On December 28, 2022, DOE announced it was proposing new energy efficiency standards for distribution transformers to improve the resiliency of the grid.

For over a year, the electric sector has been informing DOE about the severity of the supply chain challenges that have prolonged and complicated distribution transformer production and availability.

In announcing the proposed rule, DOE stated it “represents a strategic step to advance the diversification of transformer core technology, which will conserve energy and reduce costs. Almost all transformers produced under the new standard would feature amorphous steel cores, which are significantly more energy efficient than those made of traditional, grain-oriented electrical steel.”

“The availability of critical grid components remains a significant challenge for the electric power industry that could impact national security, grid reliability and resilience, as well as the ability to continue the important work of electrification and grid modernization,” the Senators wrote in their letter.

The proposed rule increases efficiency standards on distribution transformers, critical grid products, which currently are no less than 97.7% energy efficient, “at a time when the industry is struggling due to a significant increase in demand, supply chain issues, and skilled workforce shortage,” they said.

“These factors have made it hard for manufacturers to meet current demand for distribution transformers, creating challenging lead time conditions and concerns regarding grid reliability and resiliency,” the lawmakers noted.

“Further, the proposed rule has introduced uncertainty that prevents utilities from signing long-term contracts and manufacturers from making investment decisions,” the letter said.

The Senators noted that the proposed rule would require all distribution transformers to shift from the industry standard  grain-oriented electrical steel (GOES) cores to amorphous steel cores. GOES currently accounts for more than 95 percent of the domestic distribution transformer market and, therefore, manufacturers’ production lines are tooled for designs that use GOES.

“A final rule that adopts DOE’s current proposal could meaningfully worsen the current supply chain shortage by requiring manufacturers to change production lines to less readily available amorphous steel,” the Senators argued.

Currently, the United States only has one domestic producer of amorphous steel. “Moving to amorphous steel cores, as proposed by DOE, would require this sole domestic supplier to rapidly scale operations from its current market share of less than five percent to accommodate the entire distribution transformer market. Such a recalibration of the supply chain will further delay manufacturing production timelines – currently estimated to be a minimum of 18 months to two years,” the lawmakers said.

Between 2020 and 2022, average lead times to procure distribution transformers went from eight to 12 weeks to up to three years. “This multi-fold increase is directly impacting the electric power industry’s grid modernization and reliability efforts, as well as its ability to respond and recover from natural disasters, posing challenges for communities that need to rebuild as well as new development,” the Senators told Granholm.

Senators also expressed concern that requiring the use of amorphous steel for new distribution transformers could put the administration’s electrification goals at risk by exacerbating an existing grid vulnerability. “At the same time, we recognize the numerous and often underappreciated benefits of energy efficiency and support the overall goal of reducing wasteful electrical losses in our distribution grid.”

The lawmakers “believe the most prudent course of action is to let both GOES and amorphous steel cores coexist in the market, as they do today without government mandates, for new installations as we ramp up domestic production and reorient supply chains.”

They urged the DOE “to refrain from promulgating a final rule that will exacerbate transformer shortages at this strategically inopportune time. Such a standard could come at meaningful cost to grid reliability and national security, continuing the clean energy transition, and bolstering domestic supply chains and the workforce.”

Instead, they urged the Department to finalize a rule “that does not exacerbate the shortage in distribution transformers and convene stakeholders across the supply chain to develop consensus-based approach to setting new standards.”

Senators have also asked for a briefing “with your office on the path forward on DOE’s proposal, as well as how to best leverage existing DOE authority to bolster domestic supply chains and help alleviate the current and persisting supply chain challenges facing distribution transformers.”

APPA, Other Groups Urge President Biden to Convene Electrical Steel Summit

May 23, 2023

by APPA News
May 23, 2023

The American Public Power Association and several other trade groups are urging President Biden to convene an Electrical Steel Summit that would bring together stakeholders for a strategic discussion on the current challenges to sustaining and growing domestic production of electric steel.

The summit would bring together users and manufacturers of electrical steel such as electric utilities, electrical manufacturers, automobile manufacturers, steel manufacturers, labor unions, home builders and others “to help solve the current supply chain crisis that threatens both the national security and economic outlook for the United States and to deliver on this Administration’s goals for electrification and decarbonization,” the May 22 letter said. Steel, specifically grain-oriented electrical steel (GOES) is a critical component in distribution transformers that are in short supply.

“As organizations representing the electrical steel value chain, we are increasingly concerned about the skyrocketing demand and limited availability of domestically produced electrical steel, which is a core component to the industries and products that we represent and vital to expanding electrification in the United States,” the groups said.

“We write to urge your administration to make it clear that electrical steel is critical to the national and economic security of the United States and to prioritize actions that will create a sustainable supply.”

In order to deliver on the “ambitious goals and visions of the Infrastructure Investment and Jobs Act (IIJA), and Inflation Reduction Act, it is vital that the federal government recognize and support the domestic production of electrical steel to meet the unprecedented demand for electrification and grid modernization and resilience initiatives,” APPA and the other groups said.

Electrical steel, including grain oriented electrical steel and non-grain oriented electrical steel, “is a vital component in the manufacturing of a range of critical electrical products. Electric motors, transformers, electric vehicle chargers, generators, and other critical electrical equipment all require electrical steel due to its unique properties that reduce power loss. Shortages of domestic electrical steel are contributing to significant and persistent supply chain challenges across our industries.”

The groups said that the limited availability of domestically manufactured electrical steel “poses challenges to the widespread adoption of electric vehicles, delays timelines for utilities to restore power following natural disasters, and is a contributing factor to an insufficient inventory of distribution transformers to meet the demand for new home and commercial construction.”

They noted that the Department of Energy in 2022 reported that the United States is dependent on a single manufacturer for GOES, which severely limits electrical manufacturers’ ability to source domestically and meet certain domestic content thresholds.

While two domestic manufacturers have committed recently to increase GOES production, even with this expanded output, domestic supply levels will still fall far short to meet electrification goals and satisfy demand created by the IIJA and IRA, the groups went on to say.

“Further, plans to expand domestic steel capacity and manufacturing of critical electrical equipment, such as transformers, are now in flux as DOE contemplates new efficiency standards that would upend the market and manufacturing process,” the letter said.

The groups said that “Now is the time to demonstrate leadership by prioritizing the critical importance of electrical steel and growing domestic manufacturing jobs by working with Congress to put requisite financial resources toward shoring up domestic supply. The federal government can guarantee purchase of GOES and NOES up to a defined amount, as needed by critical electrical industries, to serve a more electrified economy as well as incentivize expanded manufacturing capacity.”

Along with APPA, the following groups signed on to the letter:

USDA Releases Guidance for Applying for Forgivable Rural Renewable Energy Loans

May 16, 2023

by Paul Ciampoli
APPA News Director
May 16, 2023

The U.S. Department of Agriculture’s Rural Utility Service on May 16 issued a notice of funding opportunity for the Powering Affordable Clean Energy forgivable loan program.

To be invited to submit a PACE loan application, applicants must first submit a Letter of Interest. LOIs can be submitted beginning at 11:59 a.m. on June 30, 2023, and must be submitted by 11:59 a.m. on September 29, 2023. If invited to submit an application, an applicant is expected to submit the PACE loan application within 60 days of being invited.

The minimum award is $1 million and the maximum is $100 million. USDA’s Rural Utility Service estimates that roughly $2.7 billion in project financing can be accommodated by the $1 billion authorized for the program by the Inflation Reduction Act.

PACE is an expansion of the current RUS Electric Loans for Renewable Energy.

Generally, electric loans for renewable energy:

Generally, a rural area is defined as an area with a population of 20,000 or less.  Approximately 1,600 public power utilities qualify as a rural utility.

Additionally, projects for the wholesale sale of power to utilities serving rural customers can also qualify for an Electric Loan for Renewable Energy.

PACE expands on the Electric Loan for Renewable Energy program by adding storage as an eligible project category and providing loan forgiveness.

The guidance provides for three tiers of loan forgiveness: (1) 20 percent for any qualifying loan; (2) 40 percent for qualifying loans for projects where 50 percent or more of the population served is located within an energy community or a “Distressed or Disadvantaged Community” and (3) 60 percent for qualifying loans for projects.

PACE is also “stackable” with energy tax credits, meaning a project could be financed with PACE and also receive refundable direct payment of the energy investment tax credit or production tax credits for a project that would otherwise qualify for such credits.

APPA is hosting a webinar on Tuesday, May 30, from 3-4 p.m. Eastern, with RUS Assistant Administrator Christopher McLean, who will provide background information about the PACE program, provide a timeline and instructions about the application process, and offer an opportunity to ask questions.

NERC Issues Alert to Evaluate Bulk Electric System’s Winter Readiness

May 15, 2023

by Paul Ciampoli
APPA News Director
May 15, 2023

The North American Electric Reliability Corporation has issued a Level 3 extreme cold weather alert to balancing authorities, generator owners, and transmission operators.

The alert includes eight essential actions, as well as a series of questions, that are intended to evaluate the bulk electric system’s winter readiness, and progress toward, mitigating risk for winter 2023-2024 and beyond.

“NERC registered entities should note that only entities registered as mentioned above will be able to respond to the alert in the NERC Alert System,” NERC said.

The alert has a response due date of October 6, 2023.

NERC will also be publishing a FAQ document for the level 3 alert later this week. A separate announcement will be sent to industry once it has been posted.

Gainesville Regional Utilities Moves Transformer With a Little Help from Palmolive Dish Soap

May 11, 2023

by Paul Ciampoli
APPA News Director
May 11, 2023

Florida public power utility Gainesville Regional Utilities and Rountree Transport & Rigging recently teamed up to move a 114,000-pound transformer at the utility’s Sugarfoot Substation.

This upgrade is a part of our ongoing seven-year project to enhance substations with higher-capacity, more efficient units, improving reliability and accommodating system growth, GRU noted.

“Thanks to innovative techniques, including the use of hydraulics, steel rails, and a secret ingredient (orange Palmolive dish soap),” GRU noted in a Facebook post. The Palmolive soap was “used to lubricate the rails they slide the transformer on. They discovered that orange works best,” noted David Warm, GRU spokesman.

Tom Boyer, substation principal engineer at GRU, said on May 8 that “We have replaced four transformers so far since starting this program.” 

The fifth transformer was delivered “about a week ago but won’t be in service until later this month or early next month. We have two more transformers scheduled to be delivered at the end of this year,” he said.

San Francisco Officials Urge PG&E to Reconsider Position on Sale of Grid Assets

May 8, 2023

by Paul Ciampoli
APPA News Director
May 8, 2023

In a May 3 letter to Patricia Poppe, CEO of California investor-owned utility Pacific Gas & Electric, San Francisco officials including Dennis Herrera, General Manager of the San Francisco Public Utilities Commission, urged the utility to reconsider its position related to the city’s plan to buy PG&E’s grid assets, which would allow the city to become responsible for all electric distribution service within San Francisco’s boundaries.

The letter also asked for information on recent power outages that affected the city.

Joining Herrera in the letter were Mayor London Breed, City Attorney David Chiu and President of the Board of Supervisors Aaron Peskin.

City Acquisition of PG&E Assets

“The city is focused on ensuring timely access to affordable, reliable, and clean electricity for our businesses, residents, and essential services,” the letter said. “After a substantial commitment of time and resources on this issue, we remain united in our belief that the only path forward to achieve these goals is for the city to become responsible for all electric distribution service within our own boundaries.”

The city is uniquely positioned to acquire these assets, the San Francisco officials said, noting that for over a century, the city, through the San Francisco Public Utilities Commission, has owned and operated its own electric utility (Hetch Hetchy Power).

Through Hetch Hetchy Power, the city supplies electricity to municipal facilities, schools, hospitals, public transportation, and other facilities. In 2016, the city launched CleanPowerSF, San Francisco’s Community Choice Aggregation program.

Through these two programs, the San Francisco PUC already supplies nearly 80% of the electricity consumed within the city, but both programs rely on PG&E for use of its local distribution grid.

“This arrangement is unusual, a source of friction for both the city and PG&E, and inconsistent with the City’s goals and objectives,” the letter noted.

“In recent years especially, this arrangement has caused substantial delays in the provision of essential services. After many decades, it is time for the city to gain the energy independence that comes from owning its local grid,” the San Francisco officials said.

They pointed out that during PG&E’s bankruptcy, the city submitted a proposal to purchase PG&E’s assets serving San Francisco. After PG&E emerged from bankruptcy, the city reiterated its desire to engage in a mutually beneficial negotiation.

“These calls went largely unanswered under previous PG&E leadership, so the city has moved forward under state law. But we continue to hope you will reconsider the company’s position and realize that a cooperative process leading to an agreement would provide significant value to PG&E’s customers and shareholders.”

The letter said that PG&E’s recently announced asset sales illustrate the company’s ongoing need for capital and the limited capital market options available. “As PG&E explained in a FERC filing, asset sales can ‘strengthen PG&E’s financial condition; allow PG&E to more efficiently access equity capital to fund significant capital requirements to improve the safety and reliability of its system; and be consistent with PG&E’s path to an investment grade credit rating,’” the letter said. “The city’s purchase of the PG&E assets serving San Francisco would provide those same benefits.”

 Whether or not PG&E decides to work with the city on a negotiated transaction, “we want to engage cooperatively with PG&E to determine the most reliable, efficient and least disruptive means of separating PG&E’s electric system from the assets that the City intends to acquire,” the San Francisco officials said. “This will benefit PG&E and all ratepayers and allow PG&E to focus more on important matters such as wildfire hardening and improving the overall reliability, capacity, and safety of its system.”

The officials said that engaging collaboratively on the technical aspects of this project is consistent with PG&E’s core goals of providing safe, reliable and efficient service to its customers.

“We request that PG&E’s engineering team meet with the city’s engineering team to identify the preferred engineering solutions for separation. We are prepared to begin these meetings as soon as possible. We look forward to further discussions with you on both of these matters and hope to achieve expeditious and mutually beneficial resolutions.”

Power Outages

The letter also notes that the city recently has experienced several power outages that created significant public health and safety risks and economic disruption.

“We are concerned about the frequency and duration of these outages and PG&E’s response to them. The city currently lacks sufficient information about these outages to understand whether or how PG&E could have prevented them or minimized their impact. But PG&E has not met its obligations to provide accurate, responsive, and informative communications to affected customers and local officials,” the officials said.

The city “requires information from PG&E about these recent outages and seeks PG&E’s commitment going forward to provide affected customers and local officials timely and accurate information about the nature of the outage, what PG&E is doing to restore service, and its best estimate of when it will restore service.”

Pacific Northwest Forecast Projects a 20% Increase in Load Over the Next Five Years

May 8, 2023

by Paul Ciampoli
APPA News Director
May 8, 2023

The Pacific Northwest Utilities Conference Committee released its 2023 Northwest Regional Forecast on May 4, which projects a 20 percent increase in load over the next five years. This equates to roughly 4,000 average megawatts.

“The 2023 forecast reflects accelerated and steeper regional load growth compared to previous years. Much of this load growth is attributed to more certainty in prospective new industrial loads over the next five years,” the report said.

“The forecast is significant in light of recent extreme weather conditions that have already resulted in higher demand, emphasizing the importance of having enough capacity to meet rising energy needs,” the PNUCC said.

“Utilities in the region are increasing the pace of their plans for new renewable resources and energy storage, and identifying new transmission needs in their preferred resource portfolios,” said PNUCC Executive Director Crystal Ball in a statement. “As demand and resources grow, working together to increase regional coordination and develop innovative solutions will be crucial to maintaining a reliable interconnected grid.”

PNUCC’s updated 10-year forecast serves as an annual barometer for the region’s electric power system and provides a snapshot of electricity demand and the existing and proposed generation resources Northwest utilities are planning.

Ball said that the 2023 forecast doesn’t include emerging technologies, such as advanced nuclear, offshore wind, renewable hydrogen, and long-duration storage, that are considered part of the future grid.

“However, utilities anticipate technological advancements will be required to further diversify the mix of clean generation, and utilities are expected to update their plans as they gain more information about future loads, resources and transmission opportunities,” the PNUCC said.

For the first time, the forecast projects the region needs higher amounts of summer capacity resources to meet summer peak hour demand compared to the winter capacity needs. Winter peak hour demand remains higher than summer. In addition to summer and winter peak needs, the forecast monitors annual energy needs.

This year’s forecast shows more growth in the annual energy deficit as well. Watching changes in these trends provides the region with greater situational awareness and identifies areas where more coordination can help, the PNUCC said.

Utilities are predicting greater energy efficiency savings compared to last year’s forecast, recognizing energy efficiency as a key resource in the region. The ten-year savings projected in the 2023 forecast are slightly higher as utilities seek more savings to meet growing capacity and energy needs during the clean energy transition.

“Utilities also continue to deploy and find new ways to rely on customers to reduce energy use at peak times, such as incentivizing shifting energy usage to different times of day,” the PNUCC said.

Two elements that will impact future load are electrification and climate change, both of which are expected to unfold and affect loads differently across the region. The potential impact of electric vehicle and heating system adoptions is slight in this year’s forecast but is expected to increase over the next several years.

Utilities have a strategic focus on the need for upgraded and new transmission infrastructure to ensure a reliable and resilient grid that can accommodate the forecasted changes, the PNUCC said.

“Planning and construction of new transmission infrastructure is underway and more enhancements to the transmission system will be needed as it is a critical component to integrating new resources and delivering generation to load centers,” it said.

The PNUCC is a not-for-profit trade association of consumer-owned and investor-owned utilities and other power industry partners.

Gridscape to Develop Microgrids for California CCA East Bay Community Energy

May 5, 2023

by Paul Ciampoli
APPA News Director
May 5, 2023

Gridscape has been selected by California community choice aggregator East Bay Community Energy to develop microgrids for approximately 30 critical facilities.

The project will see Gridscape install 3.1 megawatts of solar PV systems and 6.2 megawatt hours of battery storage systems at 30 sites.

The initiative is part of EBCE’s Resilient Municipal Critical Facilities Program, which aims to bundle small community projects into a larger portfolio to achieve economies of scale and viability.

Gridscape will oversee all aspects of this project. Alok Singhania, partner, Gridscape, says that the program’s unique business model bundles sites from multiple cities into one portfolio to achieve economies of scale in project financing, legal, procurement, and construction.

Vipul Gore, CEO of Gridscape, says the project is likely to take around 18 months to complete, with the main barriers being permit approval delays, utility interconnection delays, and supply chain delays, although these are improving and may not pose a delay to this project.

The project will mark Gridscape’s largest deployment of microgrids under a single third-party financed PPA agreement, demonstrating how bundling small community projects can achieve economies of scale, making local power plant projects viable, the company said.

The program received a $2 million grant from Congress.

EBCE operates a community choice energy program in the California Bay Area for Alameda County and fourteen incorporated cities, serving more than 1.7 million residential and commercial customers.

EBCE initiated service in June 2018 and expanded to Tracy in neighboring San Joaquin County in 2021 and will expand service to Stockton in 2024.

Texas Grid Expected to Experience Greater Reliance on Renewable Energy This Summer

May 5, 2023

by Paul Ciampoli
APPA News Director
May 5, 2023

The Texas power grid is expected to see a greater reliance on renewable energy this summer, the chairman of the Texas Public Utility Commission and the CEO of the Electric Reliability Council of Texas said on May 3.

ERCOT on May 3 released its Seasonal Assessment of Resource Adequacy for the ERCOT Region for this summer and Texas PUC Chairman Peter Lake and ERCOT CEO Pablo Vegas held a news conference that same day related to the summer outlook for the state’s grid.

Lake underscored the point that the SERA report is not a forecast. “This is a scenario analysis that evaluates a range of potential outcomes. It is not a prediction of what will actually happen,” he said.

“Operationally, the ERCOT grid is ready for this summer. The reliability reforms that were put in place have been tested and continue to work,” Lake said. Reforms passed in the last session of the Texas Legislature “have been utilized and put in place to ensure our grid operates more reliably now than it ever has in the past.”

At the same time, he said that the Texas grid “faces a new reality. Data shows for the first time that the peak demand for electricity this summer will exceed the amount we can generate from on demand dispatchable power, so we will be relying on renewables to keep the lights on. On the hottest days of summer, there is no longer enough on demand dispatchable power generation to meet demand in the ERCOT system,” Lake said.

He said that from 2008 to 2022, Texas on demand dispatchable power supply grew only 1.5%. “In that same timeframe, our population grew 24 percent. The increase in demand for electricity is outpacing the supply of on demand dispatchable power,” Lake said.

“In this new reality, our risk goes up as the sun goes down because it’s still hot at 9 p.m.,” he said. “The sun sets faster than the atmosphere cools and our solar generation is all gone, so at that point in the day, we will be relying on wind generation on our hottest days. If the wind does not pick up, we will have to rely on our on demand dispatchable generators and the data is showing us that on our hottest days,” under a certain set of circumstances, “we may not have enough on demand dispatchable generation to cover the gap between when the sun sets – we lose the solar – and when our wind generation picks up.”

For his part, Vegas noted that “we saw several peak demand records set last year. Our all-time peak was set last summer on July 20 at over 80,000 megawatts of demand. And as we continue to experience substantial growth in population with more businesses moving to Texas, and a rapidly growing economy, the demand for energy is growing at a rapidly increasing pace.”

Compared to last year, “our models estimate that this summer’s peak could be about 6,000 megawatts greater than last summer’s. However, we’re only expecting a nominal increase of about 850 megawatts of thermal capacity since last summer.”

He said that the majority of new generation capacity that has been added since last summer in ERCOT continues to come from intermittent resources.

“On the renewables front, we’re expecting about a thousand more megawatts of wind capacity and about 3,400 megawatts of solar capacity compared to last summer’s SERA,” Vegas said.

“As a result, we are expecting to have to rely more on renewables during peak conditions than we ever have before,” Vegas said. “And as a result of this dynamic, this summer could have tighter hours than last summer with a higher risk of emergency operations.”

Details from SERA report

Assuming that the ERCOT region experiences typical summer grid conditions, ERCOT anticipates that there will be sufficient installed generating capacity available to serve the system-wide forecasted peak load for the upcoming summer season, the grid operator said on May 3.

The base summer peak load is 82,739 MW. This load amount is based on average weather conditions at the time of the summer peaks for years 2007 through 2021 and does not incorporate ERCOT’s summer 2023 weather outlook.

The peak load also incorporates load adjustments to account for incremental solar rooftop system additions as well as the interconnection of large loads (such as crypto-mining facilities) to Transmission Service Provider networks and individual generating units.

Over 97,000 MW of summer-rated resource capacity is expected to be available for the summer peak load. This includes 688 MW of planned thermal resources and 372 MW of planned solar resources forecasted to be available by July 2023. The total resource amount also includes 3,544 MW of installed battery storage capacity, with 447 MW of the installed total assumed to be available for dispatch prior to the highest summer net load hours. 

This capacity estimate serves as a proxy for the amount expected during a tight reserve hour for the upcoming summer and is an interim availability assumption to be used until a formal capacity contribution method is adopted for future SARA reports.

ERCOT noted that a 568 MW coal unit changed its operations from year-round to summer only. The total amount of capacity associated with units operating only during the summer now stands at 704 MW, which is the highest amount since summer 2016.

ERCOT and thermal generation owners are closely monitoring the potential impacts of the U.S. Environmental Protection Agency’s March 15th approval of its “Good Neighbor Plan” for reducing cross-state emissions of ozone-forming nitrogen oxides.

Several generation owners in the ERCOT region indicated the potential that certain generators may face operational constraints in complying with the program’s provisions as soon as July 2023.

Texas, Louisiana and other parties filed a motion with the Fifth Circuit court to stay the EPA’s regulatory action due to potential reliability impacts. On May 1, 2023, the court granted the motion to stay the EPA action.

The summer SARA includes a typical thermal generating unit outage assumption of 5,034 MW. This outage assumption is based on historical outage data for the last three summer seasons (2020, 2021, 2022).

The summer SARA includes two Risk Scenario tabs: Base & Moderate Risk Scenarios, and Extreme Risk Scenarios. The most severe Risk Scenario assumes a high peak load, extreme unplanned thermal plant outages based on historic observations, and extreme low wind power production.