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November 18, 2024

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Entergy CEO: Nuclear, Carbon Capture in Equation to Handle Industrial Growth

Entergy CEO Drew Marsh said the utility’s third quarter contained yet more prep work for large industrial customers and development for carbon capture alongside more nuclear and solar generation.    

Marsh estimated Entergy’s compound annual growth rate in industrial sales at 11 to 12%, 300 basis points higher due to a large new industrial customer that recently signed a 15-year electric service agreement with Entergy Louisiana.  

“We don’t disclose specific customer details without their consent, so we can’t provide additional information at this time,” Marsh said during an Oct. 31 earnings call.  

Marsh said the major customer will bring economic activity to a portion of northern Louisiana “that has been economically disadvantaged for decades.”  

Although no docket in the case is available yet at the Louisiana Public Service Commission, Entergy has shared a redacted version of its application for approval of generation and transmission to host an “economically transformative” $5 billion investment the unnamed customer is looking to site in Richland Parish. The utility hopes to build three new combined cycle combustion turbines and a 500-kV line.  

Entergy reported third-quarter earnings of $2.99/share and third-quarter net income of $644.9 million, down year-over-year due to 2023’s exceptionally hot summer in the South.  

However, Marsh said Entergy had a “very productive quarter” marked by higher industrial sales and growing demand for clean energy. 

Marsh said other large industrial customers increasingly are looking to Entergy for zero-carbon energy offerings.  

“Collectively, this means that our preliminary capital plan through 2028 is $7 billion higher than on Analysts’ Day, driven by new transmission as well as incremental new generation investment, including renewables,” he said. 

At Entergy’s annual Analysts’ Day in June, the utility announced a $33 billion, five-year capital plan.  

Marsh noted that Entergy Arkansas’ 100-MW Walnut Bend Solar farm, built in partnership with Invenergy, was placed in service during the quarter, and Entergy Arkansas also closed on its 180-MW West Memphis Solar and 250-MW Driver Solar facilities.  

Marsh said Entergy now has nearly 800 MW of solar resources in service and close to 2.6 GW of solar projects “in process, approved or under regulatory review.”  

Marsh said Entergy plans to build even more customer-driven renewable energy sources, mentioning Entergy Louisiana’s request for proposals to acquire 3 GW of new solar. 

He also noted that Entergy Mississippi announced plans this quarter to build a 750-MW dual-fuel, combined cycle plant, its first new natural gas power station in 50 years. He said the plant will be hydrogen ready and designed to be outfitted eventually with carbon capture technology.  

Marsh said Entergy is gearing up for carbon capture and storage (CCS) to take a role in the clean energy transition and is in “active discussions with customers about “a variety” of low-carbon generation solutions, including carbon capture.  

Marsh said Entergy Louisiana continues its front-end engineering and design study to evaluate the technical and financial feasibility of installing carbon capture at the Lake Charles Power Station, with the company enlisting the help of Crescent Midstream.  

“Once completed, the learnings from this work will benefit future CCS projects. Ultimately, we believe CCS is a critical technology to comply with eventual federal emissions requirements, to help our customers meet their decarbonization objectives and for us to achieve our 2050 net-zero commitment,” Marsh said.  

Marsh indicated Entergy is ready to partake in the nuclear revival taking hold in the country.  

Entergy believes nuclear power will factor heavily in its path to net-zero emissions by 2050 and is “well-positioned to evaluate and ultimately pursue new nuclear options,” Marsh said.  

Marsh said Entergy is actively exploring potential nuclear plant uprate projects that could add as much as 300 MW in capacity at the utility’s Arkansas and Louisiana nuclear plants. 

Marsh also brought up that Entergy since 2007 has held an early site permit from the Nuclear Regulatory Commission for a potential new reactor at its Grand Gulf nuclear site and invoked the utility’s memorandum of understanding with Holtec International to evaluate small modular reactors.  

During the past quarter, the Louisiana Public Service Commission unanimously approved a $95 million settlement with Grand Gulf owner and Entergy subsidiary System Energy Resources to resolve all complaints related to Grand Gulf’s past performance lags. It also unanimously approved an agreement to divest Entergy Louisiana’s share of Grand Gulf energy and capacity to Entergy Mississippi. (See Entergy Touts Louisiana Settlements, Beryl Response in Q2 Earnings.)  

Entergy has submitted additional filings to the Mississippi Public Service Commission and FERC to approve the divestiture. 

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BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits

New findings from a much-anticipated study have “not shifted” Bonneville Power Administration staff’s recommendation that the agency choose SPP’s Markets+ over CAISO’s Extended Day-Ahead Market (EDAM), BPA said Oct. 31 — despite results showing greater financial benefits from EDAM.

“Right now, the economic analysis from production cost model studies leans toward EDAM and the additional analysis from E3 [Energy and Environmental Economics] provides more context and nuance that will be factored into our final decision,” Rachel Dibble, BPA vice president of bulk marketing, said in a press release announcing publication of the study, which is posted on the agency’s website.

Release of the E3 analysis comes three weeks after The Brattle Group published a study — not commissioned by BPA — estimating that, by 2032, the agency would earn $65 million in benefits from participating in EDAM versus an $83 million net loss in Markets+. (See Brattle Study Finds EDAM Gains, Markets+ Losses for BPA, Pacific NW.)

“We continue to believe Markets+ is a superior market design for Bonneville and our customers, which includes a truly independent governance model,” Dibble said, reemphasizing a point agency staff made in issuing its “leaning” in favor of the SPP market in April. (See BPA Staff Recommends Markets+ over EDAM.)

Dibble said BPA “understands the gravity” of its day-ahead market decision “and remains committed to an open and transparent evaluation of market options.”

BPA plans to discuss the results during its Nov. 4 day-ahead market participation workshop, the first such meeting since announcing it would delay its market decision until 2025 and since the resignation of the executive leading its day-ahead efforts, former Director of Market Initiatives Russ Mantifel. (See BPA Markets+ Support Intact Despite Exec’s Resignation, Agency Says.)

The new study consists of “supplemental production cost modeling analysis and sensitivities of cost benefit results regarding BPA’s potential participation” in either market, BPA said in its release.

The analysis builds on the 2023 Western Markets Exploratory Group (WMEG) study E3 performed for BPA last year. (See Study Shows Uneven Benefits for California, Rest of West in Single Market.)

The 2023 study offered a mixed picture, with BPA expected to incur financial losses compared with the status quo from participating in either market due to an expected sharp reduction in wheeling revenues. BPA questioned that finding, contending that most of those revenues derive from long-term contracts likely to be maintained for the foreseeable future. By restoring those wheeling revenues into the study’s modeling, BPA found it would realize gains from participating in either market and that its net benefits from EDAM would exceed those in Markets+ by nearly $106 million annually.

Supplemental Scenarios

The 2023 WMEG study for BPA examined two scenarios, including an “EDAM Bookend” case in which the entire West participates in the EDAM, and a “Main Split Footprint” scenario, which assumed EDAM membership for only PacifiCorp, Los Angeles Department of Water and Power, Balancing Authority of Northern California, Turlock Irrigation District and Imperial Irrigation District, with the rest of the West joining SPP’s Markets+. Both scenarios were measured against a “Business as Usual” (BAU) case in which CAISO’s Western Energy Imbalance Market retains its current membership and day-ahead trading in the West outside CAISO continues to occur in the bilateral market.

A presentation prepared by E3 for BPA’s Nov. 4 workshop shows the new supplemental study retains the BAU and Main Split cases, while the EDAM Bookend case is renamed “Westwide Market” and refers to a scenario in which nearly all of the Western Interconnection, excluding British Columbia and Alberta, participates in a single, unspecified market.

The supplemental also includes three other scenarios:

  • “Alt Split 2NV,” in which the EDAM includes California, NV Energy, PacifiCorp and the entire Pacific Northwest, including BPA.
  • “Alt Split 4A,” in which the EDAM includes California, NV Energy, PacifiCorp, Portland General Electric, Seattle City Light and Idaho Power, all of which either have committed to or are likely to join the CAISO market.
  • “Non-CA Westwide M+,” in which only California entities participated in EDAM while the rest of the West joins Markets+.

The study estimates BPA’s benefits under each scenario for 2026, 2030 and 2035.

In its press release, BPA said the analysis shows “a wide range of outcomes, with results pointing to Markets+ providing lower load costs and EDAM providing greater generation revenue potential driven by higher prices.”

The agency said the results show “EDAM having greater volatility in benefits than Markets+, although most scenarios still pointed to EDAM having the greatest generation revenue potential. The results also show market benefits declining for both markets in future timeframes, with EDAM depicting a greater decline in benefits, but still maintaining more net benefits than Markets+.”

Slide 18 in the E3 presentation plots out those findings, showing that under the Westwide Market scenario, BPA would realize $251 million in net benefits in 2026, declining to $192 million in 2030 and to $147 million in 2035.

Under the Alt Split 2NV scenario, BPA would earn net benefits of $196 million in 2026, falling to $169 million in 2030, but returning to close to the 2026 level in 2035.

The Non-CA Westwide M+ scenario shows BPA realizing $207 million in benefits in 2026, $182 million in 2030 and $177 million in 2035, although that scenario is unlikely given utilities’ existing and tentative commitments to EDAM.

BPA’s worst outcomes occur in the Alt Split 4A scenario, in which it would see $30 million in benefits in 2026, but incur $23 million and $28 million in costs, respectively, by 2030 and 2035.

The study also includes sensitivity cases for each scenario in 2026 to estimate benefits under “dry hydro” and “stress load” conditions.

“Dry hydro regional conditions reduce quantity of generation that BPA has to sell but increases regional prices; BPA net costs are least sensitive to these changes in Alt 4A,” E3 notes in its presentation.

E3 said also stress load conditions are applied for only two weeks a year and have only “modest impact” for BPA’s net annual costs, although estimated prices “may not reflect full potential scarcity conditions.”

Other sensitivity cases cover improved market-to-market (M2M) coordination between EDAM and Markets+ over time and increased transmission availability between the Northwest and Southwest in the future.

“The results provide BPA with another data point in its day-ahead market decision and will be shared at a Nov. 4 workshop,” BPA said. “Other factors the agency is evaluating include governance, attribution of greenhouse gas emissions to the federal system, statutes and reliability.”

Initial Reactions

Michael Linn, director of market analytics for the Public Power Council (PPC), which has urged BPA to join Markets+, told RTO Insider that while the PPC still is reviewing results of the supplemental analysis, its “preliminary view” is that BPA’s participation in a day-ahead market will provide benefits to the agency’s customer base of publicly owned utilities.

Linn said the various scenarios show “the production cost benefits to BPA can vary wildly depending on a range of assumptions.”

“Varying market footprints and hurdle rates appear to show a two-market footprint with BPA in Markets+ can produce benefits at levels similar to BPA participating in EDAM,” he said. “These results reinforce PPC’s perspective that while production cost studies are important and show directional benefits of day-ahead market participation, when determining the best path for BPA and preference customers, it is equally important to place significant emphasis on real-world differences in market design and governance that have real impacts but may not be readily quantified or reflected in production cost studies.”

Seattle City Light (SCL), which largely has been alone amongst Northwest publicly owned utilities in urging BPA to join EDAM, had a different take.

“BPA has a fiduciary obligation to carefully weigh the variables and impacts to its customers before making any market decision,” an SCL spokesperson said in an email. “BPA’s own analysis shows that Markets+ is $221M in fewer benefits for BPA and its customers. BPA’s statement that the updated E3 results have not shifted its recommendation to join Markets+ indicates that customer benefits impacts are not an important consideration in its [day-ahead market] decision.”

The spokesperson said SCL, which operates its own balancing authority area, has yet to decide on a day-ahead market and will make a choice only after receiving its own benefits study results from The Brattle Group later this year.

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SE Renewable Energy Conference Hears Blunt Talk on Trump

CHARLOTTE, N.C. ― Mississippi Public Service Commissioner De’Keither Stamps has the results of this year’s presidential election all figured out, he told the audience at the Southeast Renewable Energy Conference on Oct. 29.

“If former President Trump wins this election, a bunch of folks will lose their mind,” Stamps said. “If Vice President Harris wins this election, a bunch of folks will lose their mind. Sit back and prepare for a bunch of folks to lose their mind.”

With early voting underway in many Southeastern states, the upcoming election loomed large over the three-day event, with many viewing it as potentially the most consequential ever for the renewable energy industry.

“There’s more excitement about this election than I can remember in my lifetime. More people are paying attention,” agreed Keith Martin, a partner at Norton Rose Fulbright who specializes in tax and renewable energy policy. “Maybe ‘excitement’ is the wrong word; maybe it’s anxiety, which makes it hard to understand this phenomenon of the undecided voter. These two candidates could not be more different.”

Martin’s yearly presentations on the current state of federal tax and energy policy are considered a highlight of the conference, and his predictions on the fate of the Inflation Reduction Act and other federal energy policies were blunt and to the point.

If Kamala Harris wins, “the Inflation Reduction Act should remain a very strong tailwind for the renewable sector,” he said.

But should Donald Trump take back the White House, “look for a Day 1 order telling executive agencies to stop issuing guidance and to stop spending money on the [IRA].”

Further, should Republicans take control of both houses of Congress, Martin expects them to “cannibalize parts of the Inflation Reduction Act to pay for extending the 2017 Trump tax cuts that expire at the end of next year.”

After lobbying by House Republicans whose districts have benefited from the IRA, House Speaker Mike Johnson has said rolling back the law would be done with a scalpel, not a sledgehammer. “However, if we see a Trump wave … there’ll be a lot of testosterone in the room, and it could be more of a hammer rather than a scalpel,” Martin said.

“Congress is facing a serious math problem next year,” he said. “Extending the 2017 tax cuts will cost $4.6 trillion,” but even if the IRA were repealed in full, it would only provide about $630 billion.

Martin’s list of the IRA funds most at risk included the tax credits for new and used electric vehicles and $60 billion that the Internal Revenue Service has been slated to receive to modernize computers and hire more staff.

Funding for the Department of Energy’s Loan Programs Office will also be a target, Martin said. “Expect to see a halt in that program, although they will fund commitments that have already been made.”

Keith Martin, Norton Rose Fulbright | © RTO Insider LLC 

But the most consequential for the industry could be Republican efforts to accelerate the phaseout of the IRA’s investment and production tax credits for solar, wind, energy storage and other forms of clean energy. “Those tax rates are not expected to currently start phasing out until some time in the mid-2040s,” Martin said. “There’s a lot of speculation in Washington that if the Republicans are in charge, those phaseout dates would start sometime in the 2020s.”

To “Trump proof” projects, developers must start construction “on as many projects as possible by year’s end in order to put themselves in the position to be able to claim tax credits on projects under the existing tax code sections,” Martin said. “This only works if projects are completed by the end of 2028.”

Those who can’t start construction this year should at least have a binding contract, which could allow their projects to be grandfathered in, or essentially protected, from any changes to the law, he said.

Martin said any rollback of the IRA would probably have to be done through a Republican budget reconciliation bill, similar to the one the Democrats used to pass the law in 2022. Such bills only require a simple majority in the Senate to pass, as opposed to the 60 votes typically required for controversial legislation.

Trump and Transformers

With such uncertainty ahead, many tax equity investors ― key players in the financing of large renewable energy projects ― are “starting to demand protection against changing law risk,” Martin said. “Many of the provisions we’re seeing require the deal [to] be repriced if there’s an adverse change in law as late as February 2026. Most people think that’s when this process will have played out.”

Martin further cautioned that Trump could reinstate his 2020 executive order making it illegal for U.S. companies to import equipment used on the bulk power system if the secretary of energy, in consultation with other key administration officials, decides such equipment could harm the grid. Biden let the order lapse, but a reinstatement could affect the supply chain for critical equipment, such as transformers, Martin said.

Mississippi PSC Commissioner De’Keither Stamps | © RTO Insider LLC 

The U.S. has been experiencing a major shortage of transformers, with utilities and power generators seeing wait times of two to four years, according to a recent report from the National Infrastructure Advisory Council. In 2023, Canada, Mexico, China and other Asian nations led a World Bank list of countries that are selling electric transformer components to the U.S.

The election could also affect IRA tax credits ― such as the 45V production tax credit for green hydrogen ― that the IRS has yet to finalize or that require further clarification. Martin expects the IRS to issue “some sort of signaling document” on 45V in November, but a final rule is not expected until January.

Qualifying for the credit could mean that starting in 2028, electricity used for making green hydrogen will have to be renewable and matched hour for hour with production. “That’s not really possible to do at this point, so it’s hard to finance anything,” he said.

The conference balanced this federal uncertainty with the momentum building in Southeastern states for the growing link between renewable energy and economic development, including clean energy manufacturing and data centers.

Commissioner Stamps again provided a concise analysis of what’s going to happen after the election. It’s not about red or blue states or saving the planet, he said. Businesses coming into Mississippi want a diversified mix of generation, with renewables, which could mean tripling or quadrupling renewable energy in the state.

“You don’t get economic development without renewables,” he said.

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Western Utility CEOs Reflect on Evolving Energy Markets

SACRAMENTO, Calif. — Leaders of four large utilities reflected on the evolution of Western markets and looked toward the future at CAISO’s Stakeholder Symposium on Oct. 30, emphasizing a shift toward more collaboration as large industry players choose which day-ahead market to join.

CAISO also announced the 10-year anniversary of the Western Energy Imbalance Market (WEIM), using it as a catalyst for conversation on what’s to come.

“How should we be thinking about the evolution of the markets in the West?” Lisa Grow, president and CEO of IDACORP and Idaho Power, said while moderating a panel at the symposium. “There are a lot of topical issues that we’re all thinking about and that surround the day-ahead market formation.”

Sitting on the panel was Cindy Crane, CEO of PacifiCorp; Tracey LeBeau, CEO of the Western Area Power Administration (WAPA); Dawn Lindell, CEO of Seattle City Light; and Caroline Winn, CEO of San Diego Gas & Electric (SDG&E).

PacifiCorp committed to join CAISO’s Extended Day-Ahead Market (EDAM) in April; Seattle City Light has signaled its intent to join; and SDG&E will join by default via its membership in CAISO. WAPA announced plans in October to study the benefits of joining.

PacifiCorp and SDG&E feel confident in the transition from WEIM to EDAM, citing CAISO data showing $6 billion in benefits from the WEIM since its inception and $1.4 billion in benefits in a fully implemented EDAM.

“We’re all in about creating more savings for our customers, and as we think about the grid development in the West and all of the investments that still need to be made for climate change, the clean energy transition and electrification, our customers need the savings to help offset some of those costs,” Winn said. “I just can’t think of a better time to really pursue EDAM.”

Studies done for PacifiCorp also demonstrated substantial benefits for customers by joining EDAM, Crane said.

“We just recently updated our EDAM study, and those studies have done nothing but substantiate that this is the best move for these markets in the West,” Crane said. “We firmly believe that EDAM will be a very successful and advanced energy market, and that it’s going to be what provides the ability for the sector to achieve and overcome the challenges that we currently have.”

Cindy Crane, CEO of PacifiCorp | © RTO Insider LLC 

Some utilities indicated interest in EDAM but have not yet committed. In October, a group of Arizona cooperatives that account for 70% of WAPA’s Desert Southwest load announced a plan to study the benefits of joining EDAM. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.) The Brattle Group is doing a study for Seattle City Light that will evaluate the benefits of joining EDAM or SPP’s Markets + that is expected to be published in December.

For those that have yet to formally commit, leaders agree that choosing a market that will bring the most value and connectivity to customers, as well as accelerating decarbonization efforts, is top of mind.

“We’re in the throes of our decision-making, and customer-benefit analysis will be key in deciding what market we go to,” Lindell said.

‘The Fewer Seams, the Better’

Market seams are bound to be an inevitable challenge, as it may be more difficult to trade power to and from balancing authority areas operating in different day-ahead markets.

The CEOs emphasized the importance of collaboration through seams agreements, especially to support each other through increasingly frequent extreme weather events.

“We’re committed, first and foremost, to making sure that we have seams agreements in place,” Crane said. “But [seams] do create a loss of efficiency in the system. And seams agreements don’t overcome the loss of efficiency.”

WAPA shares a seam with MISO, and while LeBeau said it isn’t ideal, “it’s been going pretty well.” She pointed to the relationship that has been developing between MISO and SPP as a good example of collaboration for the West to follow.

Lindell agreed that the “fewer seams, the better,” pointing again to the inefficiencies they create, as well as the rise in risk for speculative trading and overall increased costs.

“We all operate parts of, I think, the most complex machine that humans have ever built, and it requires collaboration and coordination,” Winn agreed. “There’s some competition that’s built into the markets, for sure, but having spent most of my life in this industry, it’s such an honor to be able to serve in that way and provide such a basic service that everyone relies on.”

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Exelon Reports 80% Increase in Data Center Forecasts in Q3 Earnings

Estimates of data center growth across Exelon’s service regions have increased by about 80% since the year began, executives said during the utility’s third-quarter earnings call. They predicted steady growth in transmission upgrades and a regulatory battle to define the grid service costs applicable to data centers that co-locate with generators. 

Exelon CEO Calvin Butler said it now forecasts 11 GW of high-probability data center load, up from 6 GW at the start of 2024. While that presents an opportunity for growth, he stressed that getting that load interconnected must be done in a coordinated, thoughtful and efficient manner to yield “transparent, forward-looking planning and ratemaking.” 

That goal underlies its advocacy at FERC, PJM and legislatures to ensure that co-located load configurations pay for any grid services they benefit from and are studied for any reliability implications. (See Exelon, Constellation at Loggerheads over Data Center Co-location.) 

Data centers seek to co-locate with several nuclear generators in their search for carbon-free power, including Constellation’s Calvert Cliffs Nuclear Power Plant in Maryland, Limerick Nuclear Power Plant in Pennsylvania and Talen’s Susquehanna Nuclear Plant. 

Exelon COO Michael Innocenzo said co-located configurations can have several impacts on the grid that would not be recognized under the proposals from Constellation and Talen. Those include ancillary services the load benefits from by nature of drawing off a generator that itself is interconnected, as well as grid upgrades that may be prompted by removing that capacity from PJM’s system. 

“Our whole position has just been — if they can co-locate, if they can get in there quick and get in there doing what they want to do, we support that. We just want to make sure that it has the appropriate transparency on what they are doing. We want to make sure that we have the appropriate studies done to make sure that we are addressing resource and reliability and adequacy currently, and we also want appropriate rate design to be able to cover for those costs, either now or in the future,” Innocenzo added. 

More generation also will be needed to meet that load growth, which Butler said will require changes to PJM’s capacity market structure to ensure increasing costs don’t compromise the goal of efficiently meeting demand. While Exelon is not advocating for an expansion of regulated generation, he said it’s engaging in discussions with other utilities and regulators on the subject. 

“And I do appreciate PJM’s leadership to put forward interconnection and various capacity and market reforms. And it’s just another example that the PJM stakeholder process is just not working. And we will continue to support them as well as other federal and regional agencies to get that done,” Butler said. 

Quarterly Earnings on Pace with Projections

Earnings continued to be on track to meet the utility’s guidance of $2.40 to $2.50 earnings per share, with quarterly earnings 4 cents higher compared to the same period last year because of the timing of ComEd’s distribution earnings. Higher distribution and transmission rates increased earnings another 3 cents, which were equally offset by higher interest rates. 

Final orders on rate bases for ComEd and PECO are expected from the Illinois Commerce Commission and Pennsylvania Public Utilities Commission within the next few months, which would cover about half of Exelon’s total base. Butler said the utility plans to make $34.5 billion in capital investments between 2024 and 2027, increasing its rate base by about 7.5%. 

The use of multiyear plans in several states offers additional transparency and affordability for consumers and allows Exelon to build on its long-term plans more effectively, Butler said. 

Exelon CFO Jeanne Jones said the utility’s transmission projects already are leading to cost savings for consumers, with upgrades to bring the Vienna-Nelson from 138 kV to 230 kV running two years ahead of schedule. Once that’s complete, Indian River Unit 4 will be able to finish its deactivation, potentially leading to an early end to a reliability-must-run contract with NRG Energy to keep the generator operational. If that agreement were to terminate two years early, Jones said it would save ratepayers nearly $100 million, more than 1.5 times the cost of the transmission upgrades. (See PJM OC Briefs: July 11, 2024.) 

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Xcel Welcomes Load Growth from Data Centers

Xcel Energy CEO Bob Frenzel welcomes the coming wave of data centers, despite the increased demand they will place on the grid. 

Frenzel told financial analysts during the company’s third-quarter earnings conference call Oct. 31 that Xcel has nearly 9 GW of “opportunities” before 2030 in the customer pipeline. He said the company expects about a quarter of those projects will secure contracts during the next five years. 

“The scale of this pipeline gives us the ability to thoughtfully negotiate agreements that deliver the energy and capacity needed to important new customers in the region [and ensure] that new data center load that’s brought onto our system benefits all customers,” Frenzel said. “It drives load growth to our increasingly decarbonized energy system, generates economic growth in vitality in our communities and delivers on the national imperative to support a domestic data center industry.” 

As the large loads come looking for transmission and generation service, Frenzel said, they highlight a different need. 

“We, as a country, [and] we, as an industry, need to be accelerating our ability to develop both transmission and generation to serve the load that we think is going to come. It’s meaningful load. If you can provide it across the entire country, it seems manageable as you get into very specific load pockets; it comes with a lot of need and a lot of speed that’s needed,” he said. 

“We’re starting to see this energy transition we’ve been talking about and working on for the past five years really start to accelerate. We’re proactively removing our coal plants from the system and replacing them with cleaner and, in some cases, lower-cost generation resources,” Frenzel added. “I think that is an opportunity for us to mitigate cost increases across the entire country as we transition both our transmission and generation footprint for the next generation.” 

The Minneapolis-based company reported third-quarter earnings of $682 million ($1.21/share), compared with $656 million ($1.19/share) in the same period in 2023. 

Xcel also introduced its new five-year, $45 billion investment plan, with a focus on four key areas, Frenzel said: clean energy, customer electrification, new load growth, and safety and reliability. 

The company’s share price was up nearly 6% on Oct. 31 at $66.81, a $3.76 gain from its previous close. 

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Rosner Hopeful for Consensus on Order 1920 Rehearing

FERC Commissioner David Rosner hopes that the rehearing order on Order 1920 will win broader support than the 2-1 split vote that produced the original.

Speaking at the WIRES Fall Member Meeting, Rosner said that based on the comments in the docket and discussion with his colleagues, many stakeholders agree on some modest changes to the original that are still in line with its intent to expand the transmission grid.

“I’m really hopeful that we can get five votes on a rehearing order, but I don’t know, we’ll see what happens,” Rosner said. “I mean, all I can really guarantee is one vote, but I’m committed to work through that.”

One area Order 1920 did not address much was interregional transmission, Rosner said, adding that he would be happy to implement anything Congress manages to pass. Expanded authority over interregional transmission is part of the Energy Permitting Reform Act that cleared the Senate Energy and Natural Resources Committee this summer and could move forward in a lame duck session after the election. (See Manchin-Barrasso Permitting Bill Easily Clears Committee.)

NERC CEO Jim Robb’s argument at the recent FERC reliability technical conference that interregional transmission can help the grid deal with emerging issues resonated with Rosner, he said. (See FERC Grills Grid Stakeholders on Reliability.)

“I think interregional is really important,” Rosner added. “I also don’t have any updates on commission action on that, but I will leave it at, I think it’s really important. … We have a good record open already on this, and we have lots to think about.”

Supply Chain’s Impact on the Grid

While FERC has plenty of work to do on its own to ensure grid reliability, some issues largely fall outside of its purview, which includes supply chain disruptions, such as during the COVID-19 pandemic, noted Hailey Siple, director of national security policy for the Edison Electric Institute.

The first weeks of the pandemic were some of the busiest of Siple’s career, she said, as she had to work to help manage the industry’s response.

“While we were doing that, that is the first time that I remember really sitting down and thinking about supply chain, the energy supply chain in particular, as a national security threat,” Siple said. “And I think the conversation changed very much at that point. So, we had really no immediate impacts those first couple weeks or months, but a few months down the road, we had first one of our chief procurement officers come and say, ‘Hey, we’re seeing some long lead times.’”

EEI started to hear from more and more of the industry that the pandemic was stretching supply lines thin, so it started working to help address the issue along with the rest of the industry and the Department of Energy.

“There is a fantastic relationship between industry and not just EEI, but all segments of the industry, and the Department of Energy through the Electricity Subsector Coordinating Council,” Siple said. Once the worries about the supply chain were known, ESCC set up a team to work on the issues, she recalled.

Now DOE itself has set up its Office of Manufacturing and Energy Supply Chains to help coordinate the issue, said its chief strategy officer, Arthur Haubenstock.

“A good chunk of what we are programming is in transmission, because it is the lifeblood of our energy system, and will increasingly be so as we work on industrial decarbonization, which is another area that our office is responsible for,” he added.

The need to get energy supply chains right will also be important to deal with the strains being placed on the grid, whether it is from climate change or increased demand, Haubenstock said.

Increased demand from data centers, and the utilities looking to plug them into the grid, has been a huge change for Siemens Energy, one of the main suppliers of electric transmission infrastructure, said Anthony Zito, the company’s director of sales operations.

Customers are increasingly aware of the strains and trying to book equipment a decade ahead of time for sites that are not even on the drawing board now, Zito said. But with the need for data centers, the equipment will definitely be used.

“We had one data center customer that, four years ago, we were the sole supplier to them globally,” Zito said. “We now can’t serve more than 20% of what they say their need is for the next couple years.”

Demand is so high, some data center developers and utilities have approached Siemens to buy out all its capacity for the next five or 10 years, he added. The firm has declined such offers because of the risk that a single customer’s business plans could change.

“What happens if they go bankrupt, or they decide they’re not building anymore, and now you’ve alienated every other customer, every other utility, data center customer, renewable customer?” Zito said. “So, we look at sort of a mitigation strategy to spread the love around.”

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Entergy to Pay SERC $141K for Standard Violations

FERC has approved a settlement between Entergy and SERC Reliability carrying a $141,000 penalty for violating NERC reliability standards, the commission said this week. 

NERC filed the settlement with the commission Sept. 30 in its monthly spreadsheet notice of penalty (NP24-13). It was the only settlement the ERO filed publicly for the month, though NERC also filed a separate, nonpublic spreadsheet NOP involving violations of the Critical Infrastructure Protection standards. Information on CIP violations is not typically disclosed to the public for security reasons. 

FERC said in an Oct. 30 filing that it would not further review the agreement, leaving the penalty intact.  

Entergy’s settlement with SERC stemmed from a violation of PRC-005-6 (Protection system, automatic reclosing and sudden pressure relaying maintenance). The utility self-reported the infringement to the regional entity June 2, 2022. 

While performing scheduled relay maintenance at the Hot Springs substation in Arkansas, Entergy workers discovered that scheduled maintenance and testing activities had not been performed on four panels at the substation. An investigation determined the panels had been “inadvertently suspended in the substation work management system (SWMS)” during the installation of a new high-voltage line relay panel.  

The scheduled maintenance and testing had last been performed in 2013 and should have been repeated no later than Dec. 31, 2019. After Entergy discovered the oversight, it completed the testing April 9, 2022. 

Following the detection of this infringement, Entergy performed an extent of condition review and in February 2023 found 208 additional relay panels that had been suspended under similar circumstances to the Hot Springs panels. Of these, two panels at the Mabelvale substation still were suspended in the SWMS and were five years overdue for scheduled maintenance and testing, despite remaining in service. The utility performed the required service by April 13, 2023. 

In a third instance, Entergy was reviewing a list of potentially overdue work in September 2022 and found that “it failed to complete an … impedance test” on a battery at the Pintail 138-kV substation that should have been done by the previous month. The utility had scheduled the test for March 2022, but rescheduled it several times; by the time it completed the test Sept. 13, 2022, it had exceeded NERC’s mandate of 18 months between tests. 

Entergy’s final instance of noncompliance was discovered in August 2023, when the utility’s area planner realized required maintenance on two panels at the Independence substation was past due. Upon review, the utility determined the panels had been mistakenly designated as “N/A” (not applicable) in regard to PRC-005-6. An additional incorrectly designated panel was found at the Little Rock Gaines substation. Maintenance and testing at both substations’ overdue panels were completed by Dec. 14, 2023. 

SERC identified the causes of the violation as “ineffective communication, ineffective internal controls, deficient process [and] procedure, and ineffective training program.” The RE said the noncompliance constituted a “moderate risk” to grid stability, noting that the failure to complete required maintenance and testing activities “could result in protective system failures and misoperations impacting a [large] portion of the transmission system.”  

Entergy’s mitigation plans included completing the missing maintenance and testing at all affected panels, developing a SERC critical functions checklist for planners and schedulers, updating the work management process for transmission lines and substations, and establishing metrics to show “how many SERC tasks have gone past the Entergy target date.” SERC noted that the utility reported mitigation activities were completed July 25, 2024, although the RE had not yet verified completion at the time of filing. 

When determining the penalty, SERC “considered Entergy’s PRC-005 compliance history to be an aggravating factor.” The RE observed that Entergy has five prior relevant instances of noncompliance, four of which involved similar causes and mitigations that SERC suggested could have helped prevent the most recent instances. Mitigating credit was applied for Entergy’s cooperation throughout the investigation, its self-reporting of the violations in a timely manner, its acceptance of responsibility and its agreement to settle the matter. 

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WINDPOWER: Lessons Learned from Early Offshore Efforts

ATLANTIC CITY, N.J. — The Bureau of Ocean Energy Management has decreased its offshore wind permitting times 20% as it gains experience and works to expedite development of the clean energy sector. 

BOEM Director Elizabeth Klein shared the news as she joined other federal regulators and a manager at a leading offshore wind developer for a discussion on lessons learned from early U.S. offshore wind projects. 

There has been a lot to learn, certainly, as well as ample opportunity to learn from setbacks as the industry tries to gain traction in the United States. 

“We’ve examined our permitting processes because we want to make sure that we are being as efficient as possible while also creating durable decisions,” she said Oct. 29 at Offshore WINDPOWER 2024. 

The most recent of these updates were announced the same day Klein spoke: BOEM debuted its new POWERON acoustic monitoring program to protect biodiversity in offshore wind lease areas, and it signed a memorandum with the Department of Defense to collaborate on their reviews of development proposals. 

“There is just an incredible amount of effort, there’s an incredible amount of work that I think we can all be very proud of,” she said. 

The Biden administration this year rebranded the Federal Permitting Improvement Steering Council as the Permitting Council. Executive Director Eric Beightel said it has sought to improve communication and understanding across the many federal agencies involved in offshore wind permitting and avert potential conflicts among a diverse set of core missions. 

“I think that that is a very powerful tool that is underutilized in government, and that we’re anxious to do more of it,” he said. “At the end of the day, the goal for me is to work ourselves out of a job — that we’ve instituted these sorts of best practices, these open lines of communication in such a way that it just becomes more normal.” 

Janet Coit, assistant administrator for NOAA Fisheries, said her agency has been involved in marine mammal protection work for all 10 of the federally authorized offshore wind projects to date. 

“Many of the folks who work at NOAA Fisheries were an office of one or two people, and we’ve also — as well as the industry — had to staff up, had to look for ways of providing more specific and clear guidance, and learned a lot along the way,” she said. 

Protection of marine mammals, especially whales, is a key target for offshore wind foes, so it is critical to produce science-based decisions that will withstand litigation, Coit said. 

The most prolific U.S. offshore wind developer, Ørsted, has encountered many teaching moments as it put steel in the water. 

“Spoiler alert: Things don’t always go as planned when you hit the field, when you hit the water,” said Patty DiOrio, who leads the Danish company’s North American offshore project development team. “So I’ll be talking about some lessons learned. … We’re getting better and better with every position that we install.” 

Some highlights from the four speakers: 

    • Little things like making sure agencies are talking to the right people at other agencies sound simple but do not always happen. — Klein 
    • Making the Notice of Intent checklist and FAST-41 processes work in concert is important, and getting the Permitting Council involved in the process early makes it more effective. — Beightel 
    • Having a large enough staff and budget is critical. — Klein 
    • Clarity, predictability and consistency by regulators are all good, but flexibility is critical, because weather, supply chain hiccups and other factors can change the best-laid plans. — DiOrio 
    • Good communication allows problems to be addressed early, before they fester. — Beightel 
    • Timely onshore grid upgrades are a priority, because they represent an unknown cost factor for developers. — DiOrio 
    • Mitigation of effects on fisheries should be thought out regionally rather than project by project. — Coit 
    • The Permitting Council is investing millions in artificial intelligence technology to speed administrative review of comments and documents so staff can concentrate on the necessary analytic work. — Beightel 
    • NOAA Fisheries is hiring people to meet a recommendation by developers to have dedicated project coordinators. — Coit 

DiOrio seconded this last point: “You cannot overstate how key they are. They really just keep the gears in motion, and it makes a huge, huge difference.” 

Panel moderator Ted Boling, a partner at law firm Perkins Coie, asked DiOrio if she thought the federal government is responsive. 

“Do you see your lived experience with installation being reflected in the way federal agencies are approaching mitigation, monitoring, the plan of operation?” he asked. 

“I think we’re getting there. I really do. We’ve gotten good collaboration when things happen,” she responded. 

Boling lobbed an audience question at Klein: “There is a phrase, ‘Don’t let the perfect be the enemy of the good.’ It can feel like that standard of approval is perfection. Can we move to good enough?” 

Klein recalled another regulatory learning curve, when early large-scale solar energy projects were proposed in the United States. 

“You know, at the beginning, everything can feel new, and it’s like every single environmental review is really difficult and eventually you get to a point where you can benefit from efficiencies, you can use existing environmental documents.” 

But now is not the time to cut corners and risk a setback through opponents’ litigation, she said. 

“The hope is always that this will become more routine, and it won’t feel so hard to get every single project review across the finish line, because there will be standardization across the industry in some aspects, and it will feel less difficult.” 

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ISO-NE Study Lays Out Challenges of Deep Decarbonization

Deep decarbonization of the New England grid will pose major challenges related to resource adequacy and market administration, ISO-NE concluded in the final report of its Economic Planning for the Clean Energy Transition (EPCET) study, released Oct. 24.

The RTO emphasized the importance of developing dispatchable zero-carbon resources to ensure reliability during extended periods of low wind and solar generation, and said new mechanisms likely will be needed to support dispatchable resources that run only in extreme scenarios.

ISO-NE previously outlined its key findings at its Planning Advisory Committee in August, when it told stakeholders it plans to consider “future market rule enhancements to support the ongoing reliability and economy of the region’s grid.” (See ISO-NE: New Mechanisms May be Needed to Ensure Future Grid Reliability.)

One of the main issues New England will face as it approaches full decarbonization is increasing variability of both demand and supply, with electrified heating and intermittent renewables both highly impacted by extreme weather events, ISO-NE wrote.

“The magnitude of the annual peak will vary dramatically from one year to the next, depending on how cold or how mild a winter the region sees,” ISO-NE wrote. “As a result, some resources needed to maintain reliability during the harshest conditions may only run once every few years.”

Without significant dispatchable resources, decarbonization will require a significant overbuild of wind, solar and batteries, which would come at a significant cost to consumers and have a large land-use impact, ISO-NE said.

The RTO estimated the region would need to add a staggering 97 GW of renewable capacity by 2050 to meet state goals, equating to an average annual addition of 1,293 MW of offshore wind, 268 MW of onshore wind, 955 MW of solar and 952 MW of batteries.

As the proliferation of renewables eliminates power system emissions from increasing amounts of the year — first in the spring and fall seasons, followed by the summer and eventually the winter — the value of new renewables will decrease, the modeling found.

“Fundamentally, as decarbonization accelerates, but remains highly correlated with the seasons, zero-carbon resource additions will produce surplus energy for increasing periods of time, and their cost per MWh will rise,” ISO-NE said.

The declining value of additional renewables will correspond with the increasing need for dispatchable resources and long-duration storage, ISO-NE said. The RTO found 100-hour batteries — such as those planned for development in Maine — will become particularly valuable as the region approaches 2050.

“However, even with a significant penetration of 100-hour batteries, the later years of this sensitivity still experience stretches of time when 100-hour batteries become depleted and significant fuel-secure dispatchable generation is needed to satisfy demand,” ISO-NE said.

To address these gaps, ISO-NE highlighted low-carbon fuels such as synthetic natural gas (SNG), clean hydrogen and renewable diesel, as well as small modular reactors (SMRs), as potential options.

The RTO specifically modeled SNG, noting that it could make use of the existing gas transmission network, while hydrogen likely would require significant amounts of new storage and transportation infrastructure.

It found that including 19,637 MW of SNG resources “achieves the states’ 2050 decarbonization targets while requiring 37% less new renewable capacity,” with high SNG fuel costs offset by the diminished need to overbuild renewables.

ISO-NE also modeled the effects of including SMRs, finding that “a renewable-dominant build-out that also includes 15.1 GW of SMRs achieves the states’ 2050 decarbonization targets while requiring 57% less new renewable capacity.”

The RTO emphasized that cost projections for SMRs remain highly uncertain, but estimated the inclusion of SMRs could reduce overall capital costs by 33% relative to the base case, and said the SMR case still outperformed the base case when the model doubled the SMR cost assumption.

Projected tons of carbon per day | ISO-NE

The report did not include a focus on how increased interregional transmission could affect the system. Multiple studies have found increased transmission between Québec and New England to reduce the cost of deep decarbonization in the Northeast by enabling Québec’s hydroelectric resources to balance out intermittent renewables. (See Québec, New England See Shifting Role for Canadian Hydropower.)

Massachusetts Institute of Technology researchers have found that increased bi-directional transmission between the U.S. and Canada would cut overall decarbonization costs by reducing the need to overbuild renewables. The researchers estimated that 4,000 MW of additional transmission between New England and Québec would reduce the overall costs of full decarbonization by 17-28%.

ISO-NE also noted that increased demand flexibility, which has been a top priority for consumer and climate advocates in the region, likely would not provide significant benefits during extended winter periods of low wind generation.

“While EV charging or heating could be delayed by a few hours, heating in particular cannot be delayed for longer time periods,” ISO-NE wrote.

Minimum Load Concerns

The RTO also noted the proliferation of behind-the-meter solar could create minimum-load issues for resources that are not able to quickly ramp down their production.

“All weather years in the modeled 2032 system experience days in which the net load falls below this threshold,” ISO-NE found.

It noted that flexible load — such as demand from electric vehicle charging — could be incentivized to alleviate these issues, or the region could increase its exports if other regions are not facing similar conditions.

Market Challenges

Beyond the technical challenges of developing adequate dispatchable zero-carbon resources to support system reliability, significant changes to the current market structures likely will be needed to support these resources, ISO-NE said.

While the energy market currently is ISO-NE’s largest market “by a large margin,” RTO projects overall revenue from the capacity market and from state power purchase agreements (PPAs) to surpass the energy market by 2035. Meanwhile, the proliferation of resources with PPAs — which often still can profit when bidding negative prices into the energy market — could threaten the viability of baseload resources that lack PPAs.

“Baseload nuclear resources are at particular risk of exposure to periods of negative [locational marginal prices], since they cannot increase or decrease their output quickly,” ISO-NE said.

Meanwhile, dispatchable resources needed to ensure reliability may not be used at all within a given year, putting more pressure on the capacity market to provide them with the necessary revenue. ISO-NE officials previously expressed apprehension about relying too heavily on the capacity market, which frequently is subject to intense stakeholder debates.

“Current market rules and other revenue structures may not scale well in a renewable-heavy grid, and the ISO is exploring alternate market structures within its jurisdiction,” ISO-NE wrote.

ISO-NE CEO Gordon van Welie has frequently expressed his support for developing a price on carbon within the wholesale markets but has said this would require full support from all six New England states. The EPCET study noted that zero-carbon dispatchable resources likely would need a price on carbon, or some other incentive, to compete economically with fossil alternatives.