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November 12, 2024

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FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant

FERC on Nov. 1 rejected a proposed amendment to Talen Energy’s interconnection service agreement (ISA) with PJM and PPL that would have allowed for the expansion of co-located load at its Susquehanna nuclear plant in Pennsylvania (ER24-2172).

The amendment would have let a 300-MW data center owned by Amazon Web Services — already operating behind the fence at the nuclear plant — expand from 300 MW to 480 MW. Controversy around the proposed expansion contributed to FERC hosting a technical conference on co-located load Nov. 1. (See related story, FERC Dives into Data Center Co-Location Debate at Technical Conference.)

The order was approved by only Commissioners Mark Christie and Lindsay See: Chair Willie Phillips dissented, while Commissioners David Rosner and Judy Chang did not participate. The majority found that the changes would have led to reliability concerns and novel legal issues. FERC can accept ISAs that do not conform with Order 2003, but parties filing such deals face a high legal burden to justify and explain that the changes are necessary, they said.

Many of the nonconforming provisions of the proposal relied heavily on the generally applicable PJM Guidance Document, which is not part of the RTO’s tariff, so FERC has not approved it, the majority said. In a footnote, the commissioners said they made no determination on whether the document is just and reasonable.

“This raises questions regarding whether PJM intends to offer these terms to all similarly situated interconnection customers,” FERC said. “We conclude that these provisions demonstrate that PJM has not met its burden to show that these provisions are necessary for any interest unique to the interconnection of the Susquehanna customer facility.”

The record indicates other data centers are considering similar deals with other nuclear plants, which shows the provisions from the document do not meet FERC’s standards for alternatives to Order 2003.

“This filing leaves multiple important questions unresolved,” FERC said. “Nevertheless, given that we have already found that PJM has failed to meet its burden, as described above, we need not further opine on whether PJM has met that burden with regard to the proposed nonconforming provisions herein, or otherwise address the amended ISA.”

Phillips argued that because the ISA is the first of its kind, it presents the sort of specific reliability concerns and novel legal issues that justify its acceptance.

“In failing to accept the agreement, we are rejecting protections that the interconnected transmission owner says will enhance reliability while also creating unnecessary roadblocks to an industry that is necessary for our national security,” Phillips wrote.

PJM showed that the extra 180 MW of demand would not require any transmission upgrades and the provisions included “several important, reliability-based belts and suspenders,” Phillips said. Those provisions would have ensured that no power flowed from the grid to the data center, provided generator shutdown and automatic tripping data to PPL, and notified PJM and PPL of equipment malfunctions.

Phillips also argued that failing to approve the amended deal puts national security at risk, as there is a clear bipartisan consensus that maintaining leadership in artificial intelligence is vital to the national interest.

“Maintaining our nation’s leadership in this ‘era-defining’ technology will require a massive and unprecedented investment in the data centers necessary to develop and operate those AI models,” Phillips wrote. “And make no mistake: Access to reliable electricity is the lifeblood of those data centers. I am deeply concerned that in failing to demonstrate regulatory leadership and flexibility, we are putting at risk our country’s pole position on this critically important issue. That is simply unacceptable.”

Data center co-location brings up a host of challenging, multifaceted issues that FERC will have to wrestle with, which is why it held the technical conference, Phillips wrote. “But the technical conference casts a far wider net than the matter that is before us today and was never intended to defer judgment on this application, which I believe has thoughtfully and creatively addressed the factors that justify approval of these nonconforming provisions. …

“We are on the cusp of a new phase in the energy transition, one that is characterized as much by soaring energy demand, due in large part to AI, as it is by rapid changes in the resource mix. Ensuring reliable and affordable supplies of electricity throughout the coming period of increasing demand and changing supply will require pragmatic leadership that facilitates that transition. If we instead throw up roadblocks to that transition, as I am concerned today’s order does, we will only deprive our country of the resources needed to ensure our continued economic prosperity and national security.”

In a concurrence, Commissioner Christie emphasized the rejection was without prejudice and that Phillips’ arguments about national security are unproven by the record before FERC.

He agreed that co-location arrangements present complicated issues that could have huge impacts on reliability and consumer costs, which is why FERC held its technical conference.

“Given these ramifications, the commission truly needs to ‘get it right’ when it comes to evaluating co-location issues,” Christie said. “And make no mistake. Were we to approve this proposal at this time, as the dissent advocates, we would be setting a precedent that would be used to justify identical or similar arrangements in future cases.”

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SPP Board Approves $7.65B ITP, Delays Contentious Issue

LITTLE ROCK, Ark. — SPP’s Board of Directors has approved the grid operator’s “historic” $7.65 billion package of transmission projects but delayed a decision on a need date for two of the 89 projects after stakeholders pushed back on staff’s staging recommendations. 

Stakeholders argued that the two projects in question be staged as soon as possible, with two working groups voting to classify winter-weather projects as persistent operational solutions in approving winter-weather need dates. 

Staff recommended using analysis and staging methodology consistent with the tariff and transmission planning manual. They added a Year 2 winter-storm model late in the planning process to calculate December 2028 need dates for the two projects. 

Following more than three hours of discussion over two days among themselves and with staff and stakeholders, the directors on Oct. 29 took a Solomonic approach by agreeing to delay a decision on the projects’ need dates to no later than their Dec. 9 board meeting. They rejected the original proposal to set the deadline before their February meeting. 

Until then, stakeholders will continue the staging discussion in the working groups. The Markets and Operations Policy Committee (MOPC), which endorsed the 2024 Integrated Transmission Plan (ITP) with 95% approval, also plans to hold a conference call before the December board meeting. 

Evergy’s Derek Brown, chair of the Transmission Working Group, said the disconnect between staff and stakeholders emerged over the projects’ need dates. That led stakeholders to endorse the larger projects that make up much of the transmission package’s size. 

“We have the models and the inputs, and we spent months building those to support the justification for when these projects are needed … and that got us to the five-year model,” he told directors and stakeholders. “We have projects coming in service. We have load growing. We have generation retiring. We need to look out at least five years to be able to right-size the solutions. So, when we looked at that five-year model, surprise! Things get worse. 

“At least from a transmission planning standpoint, all those projects are part of the packaged solution, so they should all have need dates as soon as possible. If the system had shown things get better in Year 5 and we don’t need all of those projects, we wouldn’t be recommending them today.” 

“Nothing’s ever easy, and it probably shouldn’t be with this large of a portfolio,” said SPP’s Casey Cathey, vice president of engineering. He noted that the Integrated Transmission Planning (ITP) manual does not have processes for creating historical winter weather models or to determine a need date for projects from past events. 

Because staff’s winter-weather models were based on previous extreme conditions during February 2021 and December 2022, stakeholders voted to stage projects as persistent operational projects.  

“It became apparent about two months ago that not only is the winter-weather staging not outlined in the manual … but it’s not easily defendable when you look at the governing language,” Cathey said, pointing to multiple sections in the manual and tariff. “If you map all of that, you have to use a Year 2 model to interpolate and determine what the staging needs are.” 

The two projects in question are the Tobias-Elm Creek 345-kV transmission line on the western side of SPP’s footprint, an 85-mile segment valued at $887.46 million, and the 154-mile, $484.09 million Buffalo Gap-Delaware 345-kV line from Kansas into Southwest Missouri. The projects were identified in the Winter Storm Uri and Elliott models, respectively. 

The first project is expected to increase transfer capability from SPP North to SPP South and decrease the chances for load shed. The second brings a new EHV source into Missouri to support system voltage and transfers from SPP. 

Three other projects related to the winter storm projects were given need dates of December 2025 or upon being issued a notification to construct. 

The 2024 ITP portfolio is SPP’s largest in both size and value in its 20 years as a transmission planning coordinator, it said. The plan includes 89 transmission projects, representing 2,333 miles of new transmission and 495 miles of rebuilds — including 1,900 miles of the RTO’s first 765-kV lines — to address increasing load growth and changes in the region’s generating fleet. SPP expects the portfolio’s benefits to exceed costs by a ratio of at least 8-to-1. 

Despite the package’s cost, MOPC approved the ITP with 95% approval and little discussion of staging. The issue has since bubbled up in the working groups. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.) 

The Members Committee approved the board’s motion to delay the staging date for the two projects in their advisory vote, 17-5 with one abstention, with renewable interests providing the opposed votes. They also cast four votes against the portfolio’s approval, expressing concern over the lack of transparency into delayed projects. 

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WINDPOWER: Equinor Exec Gives Insight on Empire Wind

ATLANTIC CITY, N.J. — The company planning an 810-MW wind farm off the New York coast gave an update on its projects at Offshore WINDPOWER 2024. 

The annual conference staged by American Clean Power offered a snapshot of the young U.S. offshore wind industry, from its setbacks to its triumphs to the potentially major challenges the upcoming presidential election could present. 

Equinor’s Empire Wind can be seen as a microcosm of these fluctuations — it benefited from strong state and federal support, received key federal approvals, won a state Offshore Wind Renewable Energy Certificate (OREC) contract for both of its phases, saw that contract become financially untenable, severed the Equinor-bp joint venture behind Empire, put Phase 2 on hold and won a replacement contract for Phase 1 at a much higher $155/MWh. 

Notably, Equinor has begun construction of what may be the most visible piece of offshore infrastructure in the nation: an offshore wind hub on the New York City waterfront. 

Molly Morris, Equinor’s president of Renewables Americas, sat down with American Clean Power CEO Jason Grumet for an update. 

“The South Brooklyn Marine Terminal is a 73-acre piece of land right in the heart of Brooklyn. It has the most amazing view of the Manhattan skyline,” she said. “About 63 acres of the land is what we call our staging port. So this is where we will house all the components for our turbines.” 

equinor

American Clean Power CEO Jason Grumet listens to Equinor President Renewables American Molly Morris at ACP’s Offshore WINDPOWER 2024 in Atlantic City, N.J., on Oct. 30. | © RTO Insider LLC 

Grumet noted that transitions such as the one underway in the energy industry are exhilarating at the start and satisfying at the end. It is the middle that can be hard.  

Morris did not disagree. 

“I will say that the last few years have been the hardest of my career — this has been an incredible journey over the last 24 months,” she said. “We hopefully have seen the inflection point and [are] starting to really see improvements. We see it a bit in the economics, although it’s still very challenging. So I don’t want to paint too rosy a picture.” 

The new OREC contract was key, Morris said. “That gave us that launching pad, and really since then, it’s been full speed ahead.” 

Grumet asked about the dichotomy within Equinor — it has been an offshore wind developer for 15 years but has been a major offshore producer of oil and natural gas for much longer. It plans to expand fossil production over the next decade and is “recalibrating” its portfolio of early-phase renewables to cut costs.  

Morris herself spent more than 20 years in oil and gas, most of it with Equinor. She said the company has a strong commitment to offshore wind but also sees a decadeslong need for fossil fuel. 

“We’re really trying to transition into what we call a broad energy company,” Morris said. “So we’re expanding into low-carbon solutions, which is hydrogen, carbon capture and storage, and, of course, renewables.” 

Grumet noted the optics of this. 

“There are certainly some advocates who don’t like the fact that companies with fossil histories are actually leading the clean energy transition,” he said. 

“We have people within our own company that don’t love that we’re trying to build renewables, and that’s OK,” Morris replied. “We also have people who work in renewables that don’t like that.”   

Grumet also noted the value that experienced, well-capitalized companies (such as oil majors) can bring to a new power sector. 

“We love to build very complicated things offshore, and this is what we have done for decades,” Morris said. “So we’re trying to use that strength that we have and bringing that into the offshore wind space.” 

Grumet asked how Equinor’s early offshore wind efforts overseas 15 years ago compared to its attempt to get up and running in the United States. 

“Of course, with any new industry, you’re going to have challenges,” Morris said.  

“There are some fundamental differences between Europe and the U.S. in terms of transmission and points of interconnection, so that is slightly different. I will say, though, the project director that we have for the Empire Wind project, he is a Norwegian, very experienced project director, and he always says to me, ‘There’s the U.S. factor that does make things more challenging.’ And again, I think it’s just being in a new industry that needs to work through the kinks.” 

Grumet noted the impending potential for a “careening federal political environment” and asked Morris for her assessment of state politics. 

“Overall? Very positive,” she said. “You know, the states really are who are driving offshore wind right now. They’re the ones that are putting solicitations up. They’re the ones setting climate targets. We have a very strong partnership with New York state, where we have our offtake for the Empire project. 

“It hasn’t been easy on either side, but there’s very strong commitment from New York, from New Jersey, the entire East Coast, and I think that has been critical.” 

An Equinor spokesperson said later via email that Empire Wind 1 has been sanctioned internally and a final investment decision is expected this year, after financing is finalized. Equinor also is seeking a partner to replace bp. 

The Brooklyn project already is in progress and is a major undertaking. Equinor has not publicized its budget, but Skanska, the construction manager, has said its contract alone totals $861 million. More than 1,000 people have worked on the site in the past six months of construction. 

Preparatory work has begun there for Empire Wind’s point of interconnection, and most work on the port itself is expected to be complete by the first quarter of 2026 — in time to receive the first shipment of turbines from Vestas and perform pre-assembly work in preparation for their installation offshore starting in the summer of 2026. 

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NM PRC Issues ‘Guiding Principles’ for Electricity Market Participation

As New Mexico utilities prepare to choose either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+, the state’s Public Regulation Commission has issued a set of principles intended to guide their decision. 

The commission voted 3-0 on Oct. 31 to adopt the guiding principles, which emphasize customer benefits, transparency, stakeholder involvement and tracking of greenhouse gas emissions. 

The guiding principles — which apply to Public Service Co. of New Mexico (PNM) and El Paso Electric Co. (EPE) — are advice rather than a mandate for steps to take in choosing a day-ahead market. And they don’t preclude PNM from making a market choice this quarter, as the utility has said it intends to do, commissioners said. 

“To be clear, there are no requirements in this document,” Commissioner Gabriel Aguilera said. “And there’s nothing in this document that stops PNM from announcing a decision.” 

EPE has said it hopes to make a day-ahead market decision by the third quarter of 2025. 

Some parties had recommended that the commission conduct a rulemaking to establish a process and requirements for market participation. Commissioners opted not to do so, saying they didn’t want to create barriers to PNM making a day-ahead market decision this year. Rulemaking is still an option for the future, the commission said. 

5 Principles

The first of the commission’s five guiding principles is that the primary driver of any market decision must be customer benefits, with economic and reliability benefits as a priority.  

The commission provided a list of factors to use in determining whether a particular market decision will benefit customers. Those include the market’s expected footprint, its governance, and the cost and ease of market entry and exit. 

Other factors are how transmission rights and congestion costs would be handled, and whether EDAM, Markets+ or the status quo show the best results in a cost-benefit analysis. 

In the second principle, the commission said a utility’s market participation should allow for sufficient tracking and reporting of greenhouse gas emissions to demonstrate compliance with the state’s Energy Transition Act. 

Thirdly, the commission said, the day-ahead market should have a fair and transparent decision-making process that “facilitates diverse and meaningful stakeholder engagement and considers stakeholder input fairly.” 

A fourth principle states that a utility’s decision to join a regional market should include stakeholder input. The utility should make the study assumptions and results it is relying on available to regulators and stakeholders. 

In the final principle, the commission asked utilities to provide updates on their market participation, including any major changes to the market and opportunities for stakeholder involvement.  

After a utility has joined a day-ahead market, the commission would like quarterly reports for the first two years and annual reports thereafter. 

Yearlong Process

Adoption of the guiding principles comes after the PRC opened a docket in August 2023 to examine factors PNM and EPE should consider when deciding whether to participate in a regional day-ahead market or RTO.  

The commission held a series of workshops to discuss market participation. During an Aug. 29 workshop, The Brattle Group presented results of a study conducted for PNM and EPE, showing the utilities’ projected benefits from joining either EDAM or Markets+.  

The study modeled a scenario in which three Arizona utilities — Arizona Public Service, Salt River Project and Tucson Electric Power — join Markets+. 

Even with the Arizona utilities in Markets+, projected annual benefits for PNM would be $20.5 million if it joined EDAM, compared with $8 million from participating in Markets+. For EPE, projected benefits were $19.1 million a year for EDAM versus $9.1 million for Markets+. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+.) 

Aguilera, who led the proceeding, said the process leading to the guiding principles had been successful in creating a forum where utilities, commissioners and stakeholders could learn what each other was thinking in terms of regionalization. 

“The last thing that I wanted was a surprise filing or unexpected press release from the utilities announcing they are joining ‘X’ day-ahead market,” he said. 

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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.