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July 4, 2024

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FERC, NERC Review January Winter Storm Performance

The North American electric and natural gas systems survived this year’s Arctic storms with no major incidents, demonstrating significant progress from the performance issues in previous severe winter events, FERC and NERC staff said at the commission’s open meeting this week. 

However, the presenters said there still is considerable room for improvement and both industries continue to face challenges from extreme cold weather and the impacts of climate change. 

The winter storms, also known as Gerri and Heather, began on Jan. 10, according to Chanel Chasanov from FERC’s Office of the General Counsel. Gerri entered the picture first, moving through the Pacific Northwest, across the Rocky Mountains and into the Midwest, and then up through the Great Lakes region and into southern Canada on Jan. 13. That same day, Heather developed, also beginning in the Pacific Northwest but taking “a more southern route” through Texas, Oklahoma and Tennessee before sweeping into the Mid-Atlantic and ending in Canada on Jan. 17.  

Both Gerri and Heather brought “frigid cold, high winds, heavy snow and in some places freezing precipitation,” Chasanov said. But while the cold weather caused some challenges to gas and electric reliability, there was no operator-initiated load shed and generators reported fewer derates and outages than in other recent cold weather events such as winter storm Uri in 2021 and 2022’s Winter Storm Elliott. 

FERC, NERC and the regional entities launched a review in February of the electric grid and natural gas system’s performance during Gerri and Heather in order to determine the progress made since the “unacceptable” performance during Elliott. (See FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’.) Chasanov said that because there were no major incidents to focus on, the team chose “a more qualitative approach” informed mainly by voluntary interviews with grid operators and staff presentations than the quantitative approach favored in previous years. 

The report found that conditions during the storms generally were less severe than those seen in Uri and Elliott, which contributed to the system’s performance. For example, entities encountered less freezing precipitation than in the previous incidents and did not see wind turbine blades ice up to the extent they did in Elliott.  

However, presenters noted that the hardest-hit area in January was the Pacific Northwest, where Chasanov said winters typically are mild and utilities “had limited operational experience in dealing with these … conditions” compared to their counterparts in the Eastern Interconnection. Entities in this region reported the temperatures of Gerri and Heather represented a “one-in-30-years cold event,” with record lows experienced in parts of Oregon and Washington. 

Matt Lewis, NERC’s manager of event analysis, said “neighboring reliability coordinators and balancing authorities worked closely” on their winter response measures before and during the storms, holding daily conference calls beginning seven days before the onset of severe weather. 

“These entities noted that this practice provided a higher level of situational awareness than they experienced during Uri and Elliott and improved their ability to make more informed reliability decisions,” Lewis said. “Additionally, based on lessons learned, one grid operator’s executive team met daily during Gerri and Heather to communicate operating plans … from staff [in] generation and transmission operations to the control center in natural gas scheduling.” 

Robert Clark from FERC’s Office of Electric Reliability said the performance of the natural gas system “validates the important recommendations and lessons learned from” the reports on Uri and Elliott, as well as the joint report on black-start resource availability released last December. (See FERC Black Start Report Pushes Gas-electric Coordination.)  

While the storms “triggered a rise in natural gas demand, coupled with a nearly simultaneous plummet in … production” as seen in previous events, Clark said gas entities proactively reached out to the public to communicate current operating conditions and appeal for conservation. Utilities also worked to prevent outages by increasing pipeline pressures ahead of time to ensure the presence of gas where needed, including for electric generation. 

“The natural gas system experienced fewer disruptions during Gerri and Heather as compared to Uri and Elliott,” but the experience of January “demonstrated the benefit of advanced preparations, diversity of natural gas supplies, [and] natural gas storage and reinforce the need to continue implementing the recommendations from” previous reports, Clark said. 

FERC Chair Willie Phillips thanked the presenters, joking that the positive news allowed him to wear his “happy face,” rather than the “determined face” he used for previous winter storm reports. He emphasized that winter preparedness “remains a priority” for the commission and called for stakeholders to continue implementing the recommendations issued after Uri and Elliott, while reiterating his support for an organization to ensure reliability in the natural gas industry. 

In a statement, NERC CEO Jim Robb said the report indicated “the industry prepared and got ready for the Arctic cold” ahead of January’s storms. 

“I am confident that the winter reliability requirements in [NERC’s] cold weather standards are providing clarity and the winter preparation support NERC and the regional entities are providing is making a difference in generation performance during cold weather events, but as the chairman notes, there is still much left to do,” Robb added. 

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EPA Power Plant Rules Squeeze Coal Plants; Existing Gas Plants Exempt

Coal-fired power plants nationwide will either have to close by 2039 or use carbon capture and storage or other technologies to capture 90% of their emissions by 2032 under EPA’s long-awaited final rule issued April 24. 

The 1,020-page document actually contains four different, “severable” rules: 

    • the repeal of the Affordable Clean Energy rule that the agency issued during the Trump administration; 
    • greenhouse gas emission guidelines for existing coal plants; 
    • new source performance standards for gas-fired plants built after May 23, 2023; and 
    • revisions to the performance standards for coal plants that undergo a large modification, matching the new emission guidelines. 

Absent from the package are emissions guidelines for existing natural gas plants, as EPA proposed in May 2023. (See EPA Proposes New Emission Standards for Power Plants.) The agency first announced the change to its proposal in February. (See EPA to Strengthen Emissions Regs for Gas Power Plants.) 

During a press conference April 24, EPA Administrator Michael Regan said those guidelines have been delayed because of feedback from both industry and environmental groups, which pushed the agency to “do better.” 

The agency has opened a docket and issued “framing questions to gather input about a more comprehensive approach to reduce greenhouse gases of existing gas combustion turbines in the power sector,” Regan said. “We are committed to expeditiously proposing GHG emission guidelines for those units … and we’re going to do it in a very transparent and engaging way.” 

An EPA analysis estimates the rule could cut 1.3 billion metric tons of power-sector carbon dioxide emissions by 2047 and provide climate and health benefits totaling $370 billion, or about $20 billion per year. 

“In 2035 alone, that means preventing 1,200 premature deaths, 870 hospital visits, 360,000 avoided cases of asthma symptoms, 48,000 avoided school absences and 57,000 lost workdays,” Regan said April 25 at a public announcement of the rules at Howard University in D.C. 

Anticipating pushback from the electric power sector and fossil fuel organizations, Regan said the CO2 rule will not only protect public health but also allow the power sector to “confidently prepare for the future by enabling strategic long-term investment and establishing an informed, multiyear planning strategy.” 

“Despite what you will hear and what they will say, we can do it all while ensuring the power sector can provide affordable, reliable electricity for the long term,” he said. 

In addition to the CO2 rule, EPA issued pollution-reduction standards for wastewater and coal ash produced by power plants and updated the Mercury and Air Toxics Standards. 

“Each of these rules contains transparency requirements, so that the emissions, the discharges and the compliance data are made available to the public, ensuring that power plants are held responsible and accountable for their activities,” Regan said. 

“The U.S. is closing in on its goal to cut greenhouse gas emissions in half by 2030,” the Natural Resources Defense Council posted on X. “Now, the EPA needs to finish the job and limit emissions from already built gas power plants that continue to threaten communities and our planet.” 

Altered Deadlines

The final rules push up some compliance deadlines and extend others compared to last year’s proposal.  

For example, the deadline for coal plant closure or CCS abatement was 2040 in the proposed rule, and new baseload natural gas plants originally had until 2035 to reduce emissions by the 90% requirement, as opposed to 2032 in the final rule. 

The rule also provides different compliance levels for existing coal plants depending on whether they intend to operate past Jan. 1, 2039: 

    • Plants intending to operate past 2039 will have until Jan. 1, 2032, to cut their emissions to a level based on a presumption that they will install a CCS system capable of capturing 90% of their emissions.  
    • The emission cuts for plants planning to close by Jan. 1, 2039, will be based on a presumption that they will shift their fuel mix to 40% natural gas by Jan. 1, 2030. 
    • Plants with a demonstrable commitment to shutting down before Jan. 1, 2032, will be exempt from the rule. 

States will also be able to issue “variances” for individual plants that have “fundamentally different circumstances than those considered by EPA and … cannot reasonably achieve [the] required degree of emission limitation,” according to an agency summary. 

The standards for new natural gas plants also vary based on a plant’s expected operation level: 

    • Baseload plants intending to generate at least 40% of their maximum annual capacity will have to comply with two standards: a first phase based on efficient design and operation, and a second phase assuming 90% carbon capture by Jan. 1, 2032. 
    • Intermediate-load plants planning to operate at 20 to 40% of their maximum capacity will only have to comply with the efficient design and operation standards. 
    • Plants expecting to operate at less than 20% of their maximum capacity — mostly peaker plants — will have to comply with a standard that assumes their use of low-emitting fuels. 

The different levels for coal and natural gas are intended to reflect “the fact that the longer-running and more heavily utilized a power plant is, the more cost-effective it will be to install controls for CO2 emissions.” 

States will be required to submit their plans for complying with the final rule within two years of its publication in the Federal Register. Regan said the rule allows for flexibility in state plans, for example, allowing coal and new natural gas plants to exceed the EPA limits if needed to provide short-term emergency power, for example, during an extreme weather event. 

State plans can also allow for longer-term flexibility if a coal plant scheduled to shut down is kept in operation to ensure utilities or transmission operators can supply regional reliability. States may also seek one-year extensions to comply with specific standards because of “unexpected delays with control technology implementation that are outside the owner or operator’s control,” according to the summary. 

The CCS Issue

The rule acknowledges concerns raised by environmental justice and community groups about EPA’s promotion of CCS as a best system of emissions reduction (BSER) under Section 111 of the Clean Air Act.  

While still an emerging technology, CCS has received a range of federal support, with the Department of Energy funding several demonstration projects. These projects also may receive generous tax credits from the Inflation Reduction Act. 

EPA argued its carbon pollution standards are “performance standards and do not require the installation or operation of any particular technology. Individual owners and operators will decide how best to meet the requirements laid out in the rule. … 

“EPA is committed to implementing its programs and working with federal partners to ensure that where CCS is deployed, it is implemented in a way that considers community input and is protective of public health, safety and the environment.” 

Many of the criticisms lobbed in response to the final rules focused on CCS. 

“The path outlined by the EPA today is unlawful, unrealistic and unachievable,” Jim Matheson, CEO of the National Rural Electric Cooperative Association, said in a statement. “The rule mandates the widespread adoption of technology that is promising but not ready for prime time.” 

“CCS is not yet ready for full-scale, economywide deployment, nor is there sufficient time to permit, finance and build the CCS infrastructure needed for compliance by 2032,” said Dan Brouillette, CEO of the Edison Electric Institute. 

The Electric Power Supply Association said the package “relies on unavailable technology and will stymie much needed investment in new, more efficient and cleaner power resources as older units retire.” 

“While EPSA welcomed the EPA’s announcement that it had removed existing gas plants from its proposed emissions regulations, the final rule released today is still a painful example of aspirational policy outpacing physical and operational realities,” CEO Todd Snitchler said. 

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Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day

[EDITOR’S NOTE: This story was updated on April 26, 2024, to include comments made by MISO officials and stakeholders during a teleconference.]

MISO said its second seasonal capacity auction returned sufficient capacity in all zones except a portion of Missouri, where prices soared to more than $700/MW-day in fall and spring.  

Save for Missouri’s Zone 5, all local resource zones cleared at $30/MW-day in the summer, $15/MW-day in the fall, $0.75/MW-day in the winter and $34.10/MW-day in the spring. MISO published results at the close of business April 25. 

Zone 5 — which contains local balancing authorities Ameren Missouri and the city of Columbia, Mo.’s Water and Light Department — cleared at the $719.81/MW-day cost of new entry (CONE) for generation in the spring and fall, then followed other zones in clearing at $30/MW-day in the summer and $0.75/MW-day in the spring.  

MISO said its auction showed Zone 5 didn’t have enough capacity to meet its local clearing requirements in the shoulder seasons and that large coal retirements played a factor in the capacity deficiency. CONE, the equivalent value of building new generation, is the maximum price MISO’s tariff will allow the auction to clear.  

MISO said while the auction indicates it will meet most of its 2024/25 planning year resource adequacy requirements, “pressure persists with reduced capacity surplus across the region and a shortfall in Zone 5.” MISO’s planning year begins June 1 with the summer season.  

“Once again, our seasonal construct worked as designed by identifying the highest risk periods on the system,” MISO President and COO Clair Moeller said in a press release. “These results continue to provide real-world examples of the urgent and complex challenges to the electric grid in the MISO region.” 

The grid operator said year-over-year, capacity surpluses in MISO receded by 30% in summer, especially in MISO Midwest. The opposite was true in winter, where all zones are due to experience higher surpluses than last winter.  

This fall, Zone 5 is set to experience an 872-MW shortfall; in 2023, it experienced a 2.4-GW surplus. Zone 5’s local clearing requirement for fall rose by more than 2 GW year over year.   

Overall, MISO said it experienced a 4.6-GW capacity surplus this year, down from last year’s nearly 6.5-GW surplus.  

Last year, MISO zones cleared mostly at $2/MW-day in winter, $10/MW-day in summer and spring, and $15/MW-day in fall. Zone 9 in Louisiana and southeast Texas was an outlier and cleared at $59.21/MW-day in fall and $18.88/MW-day in winter due to price separation to meet requirements. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.) 

MISO was required to meet a total 135.7-GW summer planning reserve margin requirement. Its 9% summer 2024 planning reserve margin is higher than the 7.4% annual planning reserve margin used in last year’s Planning Resource Auction (PRA). (See MISO Crunching Data for 2nd Seasonal Capacity Auction.)  

“Retirements, reduced imports and higher requirements are insufficiently offset by new capacity,” MISO reported, adding a warning that its withering surplus, paired with the ongoing clean energy transition and new load demands, will continue to strain resource adequacy. 

MISO said only load-serving entities that entered its PRA without enough capacity to meet their resource adequacy requirements are exposed to auction clearing prices. The RTO said the auction’s impacts on consumer costs “will depend upon the shortfall amount and other factors, such as wholesale purchase agreements or retail rate arrangements with state regulators.” 

“This year’s results amplify the need and urgency for MISO’s efforts around resource availability and market redefinition,” Moeller said. “We will continue working with our member utilities and states to hone regional planning processes and market mechanisms to meet the needs of our evolving fleet.” 

MISO said its proposals before FERC to install a sloped demand curve in the auction and to accredit capacity based on generators’ expected availability, alongside its ongoing work to stimulate critical generating attributes, should help states ensure resource adequacy. 

MISO’s Independent Market Monitor has reviewed the offers and results of the 2024 PRA and has certified the results. 

A ‘New Risk Paradigm’

During an April 26 teleconference to discuss auction results, Senior Director of Resource Adequacy Durgesh Manjure said the auction results show MISO is entering “a new risk paradigm.”

Manjure said the planned closure of a coal plant by fall affected Zone 5’s capacity supply, seemingly referencing Ameren Missouri’s Rush Island, which is slated close by mid-October per a court order for years of illegal air pollution. (See Court: Ameren Still Without Remedy for Years of Rush Island Air Pollution.)

He said Missouri’s capacity picture also is “aggravated” by planned generation maintenance outages in the zone during fall.

“We do believe we’re at the front end or early stages of this evolving risk,” Manjure said, calling the reliability dangers “embryonic.” He said the “unsurprising” effects of generation retirements, increasing planning reserve margins and shrinking imports will continue to intensify.

“And all of this was insufficiently offset by new capacity,” Manjure said of the 2024/25 results.

“We believe the changes we see this year in results are very important. These results signal the need for continued due diligence in our region,” Director of Resource Planning Scott Wright said, referencing the reduction in the Midwest region’s capacity surplus.

Sustainable FERC Project’s Natalie McIntire asked if generation owners in Zone 5 can shift planned maintenance outages to free up generation in the fall.

“It’s really up to the asset owner … and frankly, after-the-fact changes, we haven’t dealt with those before. We’ll have to see,” Majure said.

He added that the auction results are “only a piece of the puzzle” and that MISO has been in a shortage situation before for its entire Midwest region in the 2022/23 planning year. In that case, MISO didn’t experience a loss-of-load scenario, he said. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Manjure said Zone 5’s shortage doesn’t “immediately” mean shortfalls in the fall and spring, pointing out that imports and non-firm energy can assuage the situation.

This is the second year MISO has separated its capacity auction by season. FERC in 2022 gave the RTO the go-ahead to establish four seasonal capacity auctions with separate reserve margins. (See FERC OKs MISO Seasonal Auction, Accreditation.)

MISO will discuss the auction results again at its May 22 Resource Adequacy Subcommittee meeting.

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NEPOOL Transmission Committee Briefs: April 25, 2024

The NEPOOL Transmission Committee has voted to approve updates to ISO-NE’s Order 2023 compliance proposal to account for Order 2023-A.  

Order 2023-A, issued in late March, made some minor changes to the original order in response to rehearing requests and extended the compliance deadline. (See FERC Upholds, Clarifies Generator Interconnection Rule.) 

“None of these changes appear to materially impact the New England Order No. 2023 compliance proposal,” ISO-NE wrote in a memo responding to the order. “The revisions, however, will need to be taken into account in the compliance proposal and the incremental changes to it will need additional NEPOOL votes.” 

ISO-NE now plans to submit two filings to FERC on May 14: its Section 206 compliance proposal and a Section 205 filing that would align the procedures for small generators and elective transmission upgrades with the new cluster process. 

“While this filing is an integrated proposal, its components are independent to allow for the commission to direct changes,” said Al McBride of ISO-NE. 

The updates would push back the timeline for ISO-NE’s initial “transitional cluster study.” The RTO now proposes an “eligibility date” of June 13, which would be the due date for interconnection customers to have a valid interconnection request (IR) to be eligible for the transitional cluster.  

“The ISO will not accept IRs submitted after the eligibility date until the first cluster entry window opens in 2025,” McBride said. 

ISO-NE now plans to proceed with late-stage system impact studies until Aug. 30, with the aim of limiting the number of projects that need to enter the transitional cluster study. If these studies are not complete by this Aug. 30 deadline, the projects still could enter the transitional cluster. 

The timeline for the capacity network resource (CNR) group study, which is aligned with the schedule of the 2024 interim reconfiguration auction qualification process, will not be moved forward. This interim process would allow new resources that complete their system impact studies by June 30 to qualify for reconfiguration auctions through the 2027-28 capacity commitment period. 

“Aside from the transitional CNR group study, the timeline for the remaining Order No. 2023 transition items has been updated to account for the delay caused by Order No. 2023-A,” McBride said.  

The updated proposal passed April 25 with no objections and now heads to the Participants Committee for a vote on May 2.  

DASI Conforming Changes

Dennis Cakert of ISO-NE outlined ISO-NE’s proposal to change the tariff definition of “self-schedule” to conform with its day-ahead ancillary services initiative (DASI). 

“The ISO proposes to modify the definition of “self-schedule” to state that self-scheduled (SS) external transaction (ET) purchases (imports) are priced at the offer floor and SS ET sales (exports) are priced at the external transaction cap in the [day-ahead market],” Cakert noted. 

The Transmission Committee will vote on the proposed changes May 16.  

FERC Denies Waiver Request

Also on April 25, FERC denied a waiver request by Moscow Development Co. (MDC) related to a missed deadline to withdraw an interconnection request to receive a partial refund on its $50,000 initial deposit (ER24-1295). 

MDC argued it received incomplete information at the scoping meeting, causing it to miss the deadline. The company requested a waiver to let ISO-NE return the unapplied part of its deposit. 

ISO-NE supported the request, noting that “without the waiver, the ISO cannot return the unused portion (approximately $48,000) of the deposit to MDC.” 

However, despite ISO-NE’s support, FERC denied the request “on the basis that it is prohibited by the filed rate doctrine.” The filed rate doctrine prohibits the commission from making changes to previously filed and approved rates. 

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CAISO Receives FERC Approval to Increase Soft Offer Cap

FERC has approved CAISO’s request to increase its capacity procurement mechanism (CPM) soft offer cap from $6.31/kW-month to $7.34, which CAISO states would better reflect inflation, labor rights and higher bilateral capacity prices (ER24-1225).The increase also would better position the ISO to maintain reliable grid operations in the summer, the order reads. 

The soft offer cap, referenced when load-serving entities bid offers into the market to resolve resource adequacy deficiencies, is based on fixed operation and maintenance costs, ad valorem taxes and insurance costs of a reference unit, plus a 20% adder. 

According to its tariff, CAISO is required every four years to conduct a stakeholder process and evaluate whether to update the CPM soft offer cap. In May 2023, the California Energy Commission provided CAISO with a study demonstrating CAISO’s soft offer cap doesn’t adequately reflect fixed costs and should be increased to $7.34/kW-month.  

“CAISO contends that the proposed soft offer cap is also high enough to ensure contributions to fixed cost recovery and low enough to provide appropriate market power mitigation,” the April 25 FERC order states. “CAISO adds that the proposed soft offer cap will create greater incentives for resources to accept voluntary CPM designations.” 

Motions to intervene were filed by consumer advocacy organization Public Citizen, Calpine, Pacific Gas and Electric, the California Department of Water Resources’ State Water Project, the city of Santa Clara and the Northern California Power Agency. CAISO’s Department of Market Monitoring filed comments supporting the tariff provision. 

“DMM supports the proposed tariff revision to better position the CAISO to maintain reliable grid operations and increase incentives for resources to accept voluntary CPM designations,” DMM’s letter to FERC reads. “In addition, accepting the amendments will allow for the CAISO and its stakeholders to focus on a more comprehensive set of changes needed in the overall CPM and resource adequacy framework.” 

CAISO plans to implement the changes by early June. 

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Wildfire Litigation Poses Threat to Xcel Energy

Xcel Energy said it expects to incur a financial loss from Texas wildfires that could have a “material adverse effect” on the company’s bottom line. 

The Minneapolis-based company has acknowledged distribution poles belonging to its Southwest Public Service Co. subsidiary sparked the February Smokehouse Creek fire in the Texas Panhandle north of Amarillo. The fire, the largest in state history, consumed more than 1 million acres before being contained. 

“I’ve been to the Panhandle, and I’ve witnessed the impacted areas,” Xcel CEO Bob Frenzel told financial analysts April 25 during the company’s first-quarter earnings call. “I can speak for the entire Xcel Energy team when I say that we are saddened by the losses and we will stand with the Panhandle community as we recover, rebuild and renew that area as we have for over 100 years.” 

Xcel has disputed claims that it acted negligently in maintaining and operating its infrastructure. It faces 15 lawsuits from the fire and is processing the 46 loss claims it has received. The company recorded a pretax charge of $215 million to cover losses before insurance. 

But if the company is liable and must pay damages, the amount could exceed insurance coverage of roughly $500 million for 2024 wildfire losses and “could have a material adverse effect on our financial condition, results of operations or cash flows.”  

The Texas House of Representatives created an investigative committee on the wildfires and has held several public hearings. It plans to issue a report in early May. 

Frenzel said the $215 million loss is a preliminary estimate that reflects the low end of a range and is subject to change. He said Xcel is responding to the wildfire risk by accelerating pole inspections and cutting power to lines during dangerous weather, among other measures. 

“Like all utilities, we are experiencing profound changes in weather- and climate-related impacts on our operations,” Frenzel said. “As a result, we must continue to evolve our operations for these unparalleled dynamics.” 

Xcel reported earnings of $488 million ($0.88/share) for the first quarter, compared with $418 million ($0.76/share) in the same period last year. The company said the results reflected increased infrastructure investment recovery and lower operations and maintenance expenses, partially offset by increased interest charges and depreciation. 

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Entergy Earnings Call Focuses on La. Resilience Plan, Nuclear Outage and Settlements

Entergy’s CEO touched on several recent developments on a first-quarter earnings call April 24, including the utility’s recently approved grid-hardening plan for Louisiana, an outage at the Waterford 3 nuclear plant and New Orleans’ acceptance of a settlement concerning Grand Gulf nuclear station.  

Entergy CEO Drew Marsh said Entergy over the quarter made strides in “risk reduction efforts that will benefit our key stakeholders” during the call.  

Entergy reported first-quarter earnings of $230 million ($1.08/share) compared to first-quarter 2023 earnings of $311 million ($1.47/share).  

Entergy CFO Kimberly Fontan said the lower-than-expected earnings can be attributed to mild weather, planned generator maintenance outages and lower sales to cogeneration customers, among other factors.  

Marsh framed the Louisiana Public Service Commission’s April 19 approval of the utility’s $2 billion grid-hardening plan in the state as a positive development.  

“A more resilient grid will also serve as a catalyst for growth as it bolsters confidence for customers seeking to locate or expand in our service area,” he said.  

The PSC approved Entergy Louisiana’s plan just four days after the utility submitted it; consumer advocate groups blasted the process as rushed and only in Entergy’s interest. (See Louisiana PSC Adopts Nearly $2B Entergy Resilience Plan.)  

Marsh said the plan includes 2,100 transmission and distribution projects that will be crucial to communities, and Entergy Louisiana plans to start work immediately. 

Marsh noted Entergy Louisiana also filed for PSC approval of its Bayou Power Station, a $411 million, 112-MW “quick-start, nonbaseload” natural gas power station. He called it an “innovative solution to meet the power needs in a challenging area on the edge of the Eastern Interconnect.” 

The power plant is planned to sit atop a barge in a southern Louisiana canal and could rise with storm surges.  

Marsh drew attention to the New Orleans City Council on April 18 agreeing to a $252 million settlement to resolve its longstanding allegations of mismanagement and poor performance at the Grand Gulf nuclear station in in Port Gibson, Miss. 

The city council settled with Grand Gulf operator and Entergy subsidiary System Energy Resources, Inc. on three fronts: $116 million to resolve allegations around SERI’s mismanagement; $138 million to settle allegations of dubious tax accounting; and $500,000 to lay concerns over reliability to rest. 

“This agreement is consistent with SERI settlements with Mississippi and Arkansas, both of which were approved by FERC and determined to be fair and reasonable. … With the addition of New Orleans, SERI has resolved roughly 85% of its litigation risk,” Marsh said.  

Rod West, president of Entergy utility operations, said Entergy has a shot at pursuing a settlement with Louisiana “in the near term” over Grand Gulf operations now that New Orleans’ litigation is over.  

The Louisiana PSC has been a holdout on a settlement, maintaining ratepayers are owed hundreds of millions of dollars because Entergy mishandled plant operations, undertook an expensive and excessive plant expansion, and engaged in improper accounting and tax violations that shifted costs to ratepayers. (See Former Employee Details Failures at Entergy’s Grand Gulf.)  

Marsh also delivered an update on the offline Waterford 3 nuclear generating station in St. Charles Parish. He said the plant is “working to recover” from a shutdown following a transformer failure. He said the failed transformer was 20 years old, halfway through its expected lifespan.  

“Early indications point to equipment failure as the cause,” Marsh told shareholders.  

In the meantime, Entergy plans to outfit Waterford 3 with an interim, spare transformer to bring the plant to 90% capacity over the summer until a fully compatible replacement transformer arrives, Marsh said.  

“We’re working diligently to bring the plant back online in the coming weeks,” he said.  

Finally, Marsh said Entergy utilities will submit by the end of May six projects furthering the clean energy transition for funding consideration from the U.S. Department of Energy’s Grid Resilience and Innovation Partnership program. Entergy received letters of encouragement on six of the eight preliminary proposals it submitted late last year. Marsh said federal support stands to lower customers’ capital costs. (See Entergy Highlights Data Center and Industrial Load Growth in Q4 Earnings.)  

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Prices, Load Down in MISO March Operations

MISO energy prices plunged on record-low natural gas prices in March while the RTO managed a comparatively lower, 68-GW average systemwide load.  

March average load was lower than MISO’s 71-GW averages in 2022 and 2023, MISO reported.  

The footprint peaked for the month at 84 GW on March 19, lower than March 2023’s 89-GW peak and in line with previous March peaks in 2021 and 2022.  

Real-time locational marginal prices were about $20/MWh for the month as the footprint experienced $1/MMBtu natural gas and $2/MMBtu coal prices. Real-time prices were lower than March 2023’s $26/MWh and less than half of 2022’s $42/MWh.  

MISO’s average 48 TWh of supply came from a mix of 19 TWh of natural gas, 11 TWh of wind, 10 TWh of coal and 7 TWh of nuclear generation. The system again set an all-time solar generation record March 23 when arrays supplied 5.3 GW, or 6% of load at the time. MISO solar generation peaks have become commonplace as more solar projects clear the interconnection queue.  

The RTO averaged 49 GW of daily generation outages over March, more than March 2023’s 45-GW average. 

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Participants ‘Unwaveringly Committed’ to WRAP, WPP CEO Says

DENVER — Western Resource Adequacy Program (WRAP) participants still strongly support the program despite recently appealing to delay its “binding” penalty phase by one year based on concerns about capacity shortages, Western Power Pool (WPP) CEO Sarah Edmonds said April 24. 

But Edmonds acknowledged the appeal clearly signals the RA situation in the West is much more critical than previously thought. 

“[Participants] are still unwaveringly committed to WRAP, which is good news for us, because our belief in the urgency and the need for the program has not changed,” Edmonds said during a panel discussion at the spring joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) in downtown Denver. “If anything, it’s only increased in this era of heightened reliability risks and NERC [and] WECC assessments warning us for quite some time that we have a serious issue that we’re facing,” she said. 

Edmonds’ comments came two days after the WRAP’s Resource Adequacy Participants Committee (RAPC) issued an April 22 letter saying program members would postpone binding operations to summer 2027 because some of them confront “significant new headwinds” in securing sufficient energy resources to meet their capacity obligations and avoid heavy penalties in the WRAP’s FERC-approved tariff. (See WRAP Participants Seek 1-Year Delay to ‘Binding’ Operations.) 

The letter cited problems with new resources’ supply chains, forecasts for faster-than-expected load growth and “extreme weather events” that have challenged assumptions about the volume of resources needed to maintain grid reliability as key reasons the delay is required. 

“The RAPC letter is an illustration of the fact that we are shorter than we thought as a collective, and there is not critical mass. And in terms of WRAP, we are facing more resource inadequacy going forward,” Edmonds said. 

Participants are looking to “revisit” WRAP “transition provisions” providing “discounts” to penalties and offer measures “that make it easier to become binding in this program,” Edmonds noted.    

WRAP entities face a May 31 deadline to commit to the binding phase beginning in summer 2026, but stakeholders determined the program would not obtain a “critical mass” of participation by that time, she said. 

The WRAP’s tariff allows WPP to commence binding operations anytime between 2025 and 2028. Participants will work to position the program for participants to commit in May 2025 for the summer 2027 binding phase, a change requiring stakeholder approval. 

“I hope that’s the last marker,” Edmonds said.  “Summer of 2028 is the very last moment — that’s when everyone in this program who’s still there needs to be fully binding.” 

Edmonds said the nonbinding phase of the program still offers “a lot of value.” 

“We’re essentially in an informational stance where we’re going through a lot of the processes — the forward-showing, planning process — and then essentially setting up an operational program that can track how it would really look in real life if we were in this program,” she said.  

“We could do better on all those pieces in terms of the quality of the data that we’re receiving from participants, the amount of data the Western Power Pool is permitted to see in the tariff, and how we can then explain that data and turn that data into information that’s useful for the region,” she added. 

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FERC Sticks with MISO on Queue Penalties over Clean Energy Groups’ Rehearing Attempt

Clean energy groups were unsuccessful with FERC in their challenge of automatic withdrawal penalties in MISO’s interconnection queue.  

The commission decided April 25 that MISO is clear to continue use of an automatic and escalating penalty structure despite a joint rehearing request from the American Clean Power Association, the American Council on Renewable Energy, the Solar Energy Industries Association and Clean Grid Alliance (ER24-340).  

“Commission precedent and the record in this proceeding demonstrate that interconnection withdrawals create a generalized harm in MISO that more than inconveniences remaining interconnection customers in MISO’s interconnection queue,” FERC wrote to justify MISO’s penalty setup.  

Under the penalty schedule, MISO can keep 10% of a developer’s per-megawatt milestone fees at the queue’s first decision point, 35% by the second decision point, 75% by the time their project reaches the third and final phase of the queue and, finally, 100% if they drop out during the negotiation stage of the generator interconnection agreement. 

The penalty fees were imposed early this year as part of a package of rules meant to downsize MISO’s interconnection queue and discourage speculative projects. This week, MISO announced it received 123 GW of project proposals under its 2023 queue cycle, less than the 171 GW it fielded in 2022. (See MISO Reports 123-GW Roster for 2023 Interconnection Queue Cycle.)  

The clean energy groups had argued the penalties would have a chilling effect on generation entering the MISO queue because the fees would rack up before developers receive meaningful study results from the RTO on the feasibility of their projects. They argued FERC treaded on its own philosophy that penalties shouldn’t discourage interconnection customers from lining up projects or withdrawing them in an orderly fashion. (See Clean Energy Groups Seek FERC Re-evaluation of Automatic Penalties in MISO Queue.)  

However, FERC said the penalties will persuade developers to withdraw nonviable projects “before MISO has expended significant resources studying such requests.” It also said its precedent doesn’t necessarily prohibit automatic fines.  

“We find that neither the establishment of an automatic withdrawal penalty nor the amount of the penalty creates a barrier to enter MISO’s interconnection queue; rather, such a penalty reinforces an existing consequence of withdrawing an interconnection request,” FERC said. “While it is true that [penalties] may discourage the submission of speculative interconnection requests or encourage earlier withdrawals to avoid higher penalties, those outcomes are not unreasonable barriers to entering the interconnection queue.” 

FERC also agreed with MISO that automatic forfeitures will serve as an “appropriate mechanism to disincentivize speculative interconnection requests from entering the queue.”