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April 9, 2025

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BPA Flooded with Comments on Draft Day-ahead Market Decision

The Bonneville Power Administration elicited nearly 150 comments in response to the March 6 draft policy outlining its decision to join SPP’s Markets+ rather than CAISO’s Extended Day-Ahead Market.

BPA’s tentative decision in favor of Markets+ offered little surprise to Western electricity sector stakeholders involved in the development of day-ahead markets in the West.

Still, the draft’s release ended nearly two years of speculation about a potential surprise — or whether the agency might succumb to political pressure and delay its choice to let developments play out around the West-Wide Governance Pathways Initiative’s efforts to bring more independent governance to CAISO’s markets. (See BPA Selects SPP Markets+ in Draft Policy.)

The torrent of comments have (so far) offered few surprises as well, with supporters of each market staking out the many of the same positions they’ve voiced since BPA kicked off its day-ahead market participation stakeholder process in July 2023.

RTO Insider’s round-up of the comments is by no means a comprehensive one, but we have sought to include many from key players in the industry and important constituencies. Additional comments were being posted to the BPA site throughout the day, and we will continue to review them for inclusion in future articles.

BPA officials have said they will respond to the comments and expect the agency to issue its final record of decision in early May.

‘Compelling’ Choice

Unsurprisingly, the consumer-owned utilities (COUs) that make up BPA’s base of “preference” customers largely supported the draft policy and urged the agency to finalize its decision without delay.

A common thread among the COUs backing the draft policy was the market governance issue, with some contending the Markets+ framework provides an independent governance structure that EDAM lacks.

For example, Gary Huhta, general manager at Cowlitz County Public Utility District, urged BPA “to proceed without delay” instead of waiting for the Pathways Initiative to wrap up “development of a partial independent governance structure.”

Pathways is developing a “regional organization” (RO) that will assume governance over EDAM and CAISO Western Energy Imbalance Market.

“BPA’s choice of Markets+ over CAISO’s EDAM is compelling, as its superior independent governance, uniform resource adequacy requirements, [greenhouse gas] design and a congestion revenue mechanism that promotes transmission investments,” Huhta wrote.

Snohomish County PUD shared Huhta’s sentiment. Snohomish noted that for Pathways to succeed, the California Legislature would have to support the initiative. And even if lawmakers back the proposal, Pathways “would not achieve full independence due to the remaining significant intertwining of CAISO and the new regional organization, including shared staffing and a shared tariff.”

“Under the proposal, CAISO would retain the dual roles of a participating balancing authority for one part of the footprint and the market operator for the full footprint that could result in a conflict of interest,” Snohomish contended. “Given the magnitude of trade likely to occur within day-ahead markets, and the potential influence of market rules and market operations over the allocation of costs and benefits of market participation, Snohomish has a strong preference for the fully independent governance structure of Markets+.”

Snohomish is also one of the signatories to the so-called “issue alerts” published recently to highlight the purported advantages of Markets+ over EDAM. (See 7th ‘Issue Alert’ Highlights Markets+ Footprint.)

The Western Public Agencies Group (WPAG), which consists of 27 COUs in Oregon and Washington, supported the draft policy. The organization noted that the policy comes as utilities prepare to sign new long-term provider-of-choice contracts slated to go into effect in 2028 and set the conditions under which BPA sells federal power to customers.

“BPA’s proposal to participate in a day-ahead market is the type of strategic progression needed to meet the moment and to secure the region’s long-term future,” WPAG wrote. “What is more, based on BPA’s extensive analysis, Markets+ appears to be the market for the job.”

Vancouver, Canada-based energy trader Powerex, a key Markets+ backer, said it “strongly supports” BPA’s draft policy, writing that it “reflects thorough analysis, extensive stakeholder input and a clear understanding of the long-term structural, operational and economic implications of organized day-ahead market participation.”

The company said also that it agrees with BPA’s conclusion that the SPP market is the best option “to protect the value” of the federal hydroelectric system and “uphold its statutory obligations, and promote a durable, fair and transparent market platform for Bonneville, its customers and the region.”

‘Ignores the Facts’

But the region’s two largest consumer-owned utilities by number of customers — Seattle City Light and Eugene Water and Electric Board (EWEB) — stood out among COUs in opposing BPA’s draft decision.

“BPA’s decision to join Markets+ does not comply with the agency’s statutory obligation to provide ‘the lowest possible rates to consumers consistent with sound business principles.’ Rather, BPA’s premature decision ignores the facts presented by its own record and analysis,” City Light wrote in comments that extended to 114 pages.

City Light reiterated the key concerns it expressed in a letter to BPA Administrator John Hairston last November after the agency played down the value of the results of a study it had commissioned to compare the potential economic benefits of participating in either market. (See Markets+ Leaning ‘Alarming,’ Seattle City Light Tells BPA.)

“BPA’s own economic analysis indicates that joining the California Independent System Operator’s Extended Day Ahead Market offers the largest benefits to its customers, followed by choosing to not join any day-ahead market,” the Seattle utility said.

City Light said Markets+ “is worse for BPA customers than EDAM by $165 million to $221 million annually — and these losses persist indefinitely into the future,” while continued participation in the WEIM only would provide $79 million to $130 million in greater benefits than joining the SPP market.

The utility also contended that “all available analysis” indicates that Markets+ will not provide the “well connected and integrated market footprint of diverse loads and resources” needed to deliver the maximum benefits for BPA customers.

“BPA’s decision eschews objective analysis and chooses which factors it elevates based on whether they support its preferred outcome. This is not consistent with sound business principles,” City Light said.

Oregon-based EWEB said it agreed with BPA about the need for independent market governance but contended that issue should not be the “sole factor” in the agency’s decision and “must be carefully weighed alongside the critical elements of transmission connectivity and market footprint.”

EWEB expressed concern about what it said are “the inefficiencies associated with a smaller, disconnected market like SPP’s Markets+.”

Like City Light, EWEB encouraged BPA to continue participating in the WEIM over joining Markets+, giving the agency time “to observe the ongoing evolution of EDAM and its progress toward independent governance.”

“By waiting, BPA can make a more informed, strategic decision that not only aligns with its operational goals but also strengthens regional collaboration. This measured approach ensures that BPA chooses the best long-term market option for both its stakeholders and the broader region,” EWEB wrote.

‘Narrow Set of Interests’

The draft policy also found little support among environmental organizations, with many urging BPA to pause or withdraw its draft decision.

In a joint letter, Earthjustice, the Northwest Energy Coalition and Idaho Conservation League said the proposed decision violates the National Environmental Policy Act and the Pacific Northwest Electric Power Planning and Conservation Act.

The trio argued that BPA failed to consider the environmental impacts of its choice in violation of NEPA, noting that the agency has committed “up to $40,000,000 as part of the collateral for a bank loan to support the development of Markets+. The promise to pay these funds is irrevocable, and they will be forfeited if BPA withdraws from Markets+. This commitment of resources prior to any environmental review is contrary to NEPA.”

The groups argued BPA violated the latter act by ignoring the “substantial cost savings of a decision to join EDAM” and instead prioritizing Markets+’s governance design. They pointed to two production cost studies showing that EDAM could provide significant savings for BPA customers under certain scenarios. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)

In urging BPA to withdraw its draft policy, the groups wrote that the agency’s “response to public input has been minimal, and its decision-making process has been opaque and appears more focused on catering to a narrow set of interests rather than the broader public good. BPA, however, has a legal duty to serve the best interests of the entire Pacific Northwest, including, among others, the region’s energy, environmental and economic interests.”

Other environmental groups similarly opposed the draft decision. Save Our Wild Salmon Coalition, Sierra Club, Oregon Clean Grid Collaborative and Renewable Northwest all opposed the draft decision in separate letters.

The Washington BlueGreen Alliance, a coalition of labor unions and environmental groups, said BPA did not “fully consider” how its decision would affect not just preference customers, but the Northwest region at large.

“We are concerned that the BPA draft decision to join Markets+ is based on an inadequate analysis of each day-ahead market’s governance structure and economic costs to the region, which will have significant consequences for our region’s climate policies and workers,” the group said.

They also argued that the “fragmented nature” of the Markets+ footprint is likely to result in a less reliable system or require customers to pay more to ensure uninterrupted delivery.

“Substantial increases in BPA’s costs have a direct effect on industrial manufacturing growth and job creation in our states. These costs will likely be passed on to ratepayers, and the impact will be felt most acutely by large energy users, such as industrial and commercial ratepayers,” the group wrote.

Tribal Perspectives

Many of the region’s tribes had their own reason to oppose BPA’s decision and urge postponement, saying they were unable to provide informed — and legally required — consent because of the agency’s lack of “government-to-government consultation” with tribal representatives.

“The federal government’s trust responsibility obligates BPA to ensure that tribes are full partners in managing the lands and resources that are our ancestral inheritance,” the Snoqualmie Tribe in Washington wrote, adding that “tribal values, priorities and rights must be integrated into the” day-ahead market.

Washington’s Yakama Nation urged BPA to delay until it “has engaged in full in meaningful consultation” with the tribe to ensure that participation in a day-ahead market does not “negatively impact” the Yakama’s treaty-reserved resources and rights.

The Confederated Tribes of the Umatilla Indian Reservation expressed similar concerns, pointing to potential risks to its members’ fishing rights on the Columbia River from changes in BPA’s operations.

The Alliance for Tribal Clean Energy echoed those concerns, while also contending BPA’s decision was “rushed.”

“BPA’s accelerated timeline precludes the thorough evaluation of alternative market options that might better align with tribal interests and environmental considerations,” the alliance wrote.

Tech Views

Tech companies and data center developers, including Google, Amazon, Microsoft and Rivian, signed a letter by the Clean Energy Buyers Association asking BPA to postpone its decision.

The companies contended more analysis is needed to consider studies that show a “wide range of potential outcomes, especially the potential for increased systems costs, creates confusion and significant uncertainty for ratepayers.”

“Retail customers in Bonneville’s service territory deserve greater assurance that participation in a [day-ahead market] will not drive undue costs, ultimately borne by ratepayers,” the companies wrote.

They also wrote BPA should wait until the outcome of Pathways, while noting that staffing issues at BPA pose challenges. (See BPA to Restore 89 ‘Probationary’ Staff, Agency Confirms.)

Amazon, which has invested billions of dollars toward the development of data centers in Oregon, issued a separate letter. The company said BPA’s justification for its draft policy “is not sufficient to meet the important threshold of ratepayer protection, particularly in light of other market options available, some of which have been reported by Bonneville studies to save customers hundreds of millions compared to the Southwest Power Pool’s Markets+.”

The company said BPA should hold off on joining a day-ahead market and remain in CAISO’s WEIM while it evaluates its options.

‘Seamless’ Market

CAISO weighed in as well, noting the estimated $97 million in benefits BPA has earned since joining the WEIM in 2022 and pointing to that market’s contribution to increasingly coordinated transmission flows across the Northwest, which it said has resulted in $1.5 billion in estimated benefits for the entire region.

“The seamless real-time operational market created between the Pacific Northwest and other WEIM balancing areas in the West has also become an invaluable tool in supporting system reliability, especially during stressed system conditions, which have increased in frequency and intensity in recent years,” CAISO wrote.

CAISO also questioned BPA’s treatment of the governance issue in its draft, saying the document does “not fully present and consider the enhancements to the ISO’s market governance that will take effect upon implementation” of the Pathways Initiative’s “Step 1” changes to that governance.

The ISO said BPA’s draft additionally neglected to discuss “limitations” SPP has placed on the governance authority of the Markets+ Independent Panel, an issue important for “comparative governance analysis.”

“While the [Markets+] tariff contemplates that the SPP board will give significant deference to the MIP’s decisions, the SPP board nonetheless retains broad authority to overturn such decisions,” CAISO wrote.

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Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies

President Donald Trump signed a series of executive orders April 8 that seek to keep existing coal-fired power plants running, ease regulations and permitting for coal mining, and remove “unlawful and burdensome” state laws that impede the industry. 

The president also issued a proclamation that coal plants be exempt from the latest iteration of the Mercury and Air Toxics Standard, which the White House said will ensure they are not prematurely closed. 

“For four long years, Joe Biden and congressional Democrats tried to abolish the American coal industry,” Trump said at a White House ceremony flanked by coal miners. “They did everything in their power — while he was awake, which wasn’t much — shutting down dozens of coal plants, upending coal leases on federal lands, and putting thousands and thousands of coal miners out of work.” 

Trump ordered the secretary of energy to use Federal Power Act Section 202(c), which is meant to be used as a backstop to keep plants running for reliability even if that violates environmental rules, in a much broader way than previously used. 

The president also called on the Department of Justice to go after “unconstitutional” state laws that limit the use of domestic energy resources, including coal and other fossil fuels. 

The final order is titled “Reinvigorating America’s Beautiful Clean Coal Industry” and includes measures to open more federal land to coal mining. 

The White House’s fact sheets tied to the announcements cite the recent return to demand growth from the expansion of data centers, which are expected to drive up overall demand by 16% in the next five years. They also call coal “essential” to the power grid, making up 16% of total generation, which is down from 52.8% in 1990, according to the Energy Information Administration. 

Coal generation has been on a steady decline since 2007 when it produced 2,016 billion kWh, falling to just 675 billion kWh in 2023, according to EIA. 

“It is highly unlikely, in fact, probably zero probability, that anyone will ever build a new coal plant,” energy consultant Alison Silverstein said in an interview. 

Coal generation is more expensive to build than natural gas, which is facing stiff competition on its own from renewables in the markets. The best any policies can do would be to keep coal plants running longer, and that means going against decades of efforts to clean up the grid, Silverstein said. 

Silverstein wrote a report for the Department of Energy in Trump’s first term when then-Energy Secretary Rick Perry submitted a Notice of Proposed Rulemaking with FERC that would have had grid operators pay coal plants their full operating costs. Her report said that was not needed, and FERC voted the proposal down unanimously 5-0 after several of Trump’s appointees had taken office. 

FERC is not the focus of the current efforts, though some of the executive orders indicate the cabinet secretaries could consult with the agency as the policies are implemented. 

The executive order on “Strengthening the Reliability and Security of the United States Electric Grid” directs Energy Secretary Chris Wright to “streamline, systemize and expedite” the Department of Energy’s process for issuing orders under Section 202(c). It gives the secretary 30 days to review and analyze forecasted reserve margins for all regions of the bulk power system regulated by FERC to identify those with margins “below acceptable thresholds as identified by the secretary.” 

DOE will have to release that analysis in 90 days and then use it to identify at-risk plants of 50 MW or above. It will then use its 202(c) authority to prevent them from leaving the grid, or from converting fuel sources if that leads to a net reduction in generating capacity. 

Recent uses of Section 202(c) have focused on maintaining reliability in extreme weather, and in many cases it was only in effect for days, according to DOE. A famous case from 20 years ago kept a plant in Alexandria, Va., open to avoid blackouts in D.C., including the White House (EL05-145). 

One issue that will have to be addressed is what compensation any coal plants required to stay online are due. Most of the existing coal fleet is already uncompetitive and most are inefficient, Silverstein said. 

“Keeping them running is costing the local utility ratepayers money because it is more expensive to buy coal production and to keep the coal plants running than it is to buy in the market from renewables or gas,” Silverstein said. “So, the thing that they are doing is essentially keeping these plants going by raising everybody’s costs.” 

“Protecting American Energy from State Overreach” directs the Department of Energy to go after state policies that “target or discriminate against out-of-state energy producers.” The order specifically calls out climate policies enacted by California, New York and Vermont. 

“These laws and policies also undermine federalism by projecting the regulatory preferences of a few states into all states,” the order says. “Americans must be permitted to heat their homes, fuel their cars and have peace of mind — free from policies that make energy more expensive and inevitably degrade quality of life.” 

The order calls on Attorney General Pam Bondi to identify all such state laws and to prioritize challenges to laws purporting to address climate change, environmental justice, carbon or greenhouse gas emissions, and funds to collect carbon penalties and taxes. “The attorney general shall expeditiously take all appropriate action to stop the enforcement” of such state laws and file a report in 60 days on those efforts, which will include recommendations for additional executive actions or legislative measures.” 

Reactions to the executive orders were mixed, with some saying they will help maintain reliability and others saying they are bad for the environment and consumers. 

National Renewable Electric Cooperative Association CEO Jim Matheson and co-op executives from around the country were at the White House in support of Trump’s actions. NRECA members own at least part of 79 coal units with 21 GW of capacity, and 11 of them, totaling 3 GW, are currently scheduled to retire between now and 2030. 

“At a time when electricity demand is skyrocketing, we need to be adding more always-available energy to the grid, not shutting down power plants that have useful life left,” Matheson said in a statement. “Electric co-ops provide reliable power to communities across the country. Today’s announcements help drive home smart energy policies that will support efforts to keep the lights on at a price families and businesses can afford. We thank the administration for recognizing the continued importance of always-available resources in the nation’s energy mix.” 

Rep. Julie Fedorchak (R-N.D.), who was president of the National Association of Regulatory Utility Commissioners before assuming office this year, also praised the action, having introduced a resolution warning about growing demand and retiring plants April 7. 

“At a time when reliable baseload power is being shut down without adequate replacement, his executive orders are exactly what we need,” Fedorchak said. “With electricity demand from AI and data centers surging, the U.S. urgently needs always-available power — and that’s what coal provides, especially the mine-mouth coal power we produce in North Dakota.” 

Environmental Defense Fund Director Ted Kelly blasted the orders, saying that they could not overcome the market realities faced by coal. He also took issue with the use of FPA Section 202(c) and vowed to oppose the White House’s efforts. 

“That law is designed for, and limited to, sudden emergencies creating an immediate risk of blackouts or other grid instability, such as storms, wildfires or sudden major infrastructure failures,” Kelly said. “It is time-limited for the same reason, and it further limits any power generation that conflicts with environmental laws or regulations to the minimum hours needed to address the emergency. Changes to the power system over time, like load growth driven by data centers or power plant retirements driven by economics, are properly addressed by planning and action by utilities and their regulators — not by irrational and unlawful emergency actions.” 

Based on the market realities and likely challenges from EDF or Democratic state attorneys general, Silverstein predicted this second-term effort to bail out coal would wind up much like the failed NOPR from Trump’s first term. 

“This particular effort, I think, is going to have more grandstanding impact than actual impact,” Silverstein said. “I think it will affect a few coal plants and a few coal-mining and coal-plant communities, and it’s going to raise costs for everybody. But it’s hard to imagine any data center wanting to sign a contract with a 60- to 80-year-old coal plant.” 

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Texas RE Offers Compliance Help for New Registrants

With new registrants entering the Texas Reliability Entity’s system at an ever-increasing rate, staff from the regional entity stressed the importance of adhering to NERC’s reliability standards at an April 8 webinar.

Speaking to attendees of the webinar, part of the regular Talk with Texas RE series, Cybersecurity Principal William Sanders said the organization has noted a significant increase in the number of new registrants over the past few years, from 31 in 2022 to 53 in 2024. Most of the new additions were generator owners, he continued, reflecting the “large amount of generation being built” in the Texas Interconnection.

Texas’ recent generation additions have come at “an incredibly rapid pace,” ERCOT CEO Pablo Vegas told the grid operator’s Board of Directors in December. Solar resources and battery storage accounted for 83% of the 1,775 active interconnection requests at the time. (See ERCOT Faces Uphill Battle to Meet Large Loads.)

Sanders said the accelerating pace of registration prompted Texas RE to reach out to these incoming entities. Whether they are builders of new generation resources or purchasers of existing assets, many of them may be responsible for following NERC’s standards for the first time, he said. Noting that “Texas RE’s violation data is different from the rest of the interconnections, just because of how many new entities we have,” Sanders said the RE wanted “to make sure that [new registrants] have everything in place they need to be successful.”

To best serve their target audience of prospective generation builders or purchasers, Sanders and his co-presenter Alex Petak, enforcement attorney at Texas RE, focused their presentation on standards violations most often recorded within 31 days, one year, or two years of registration. Sanders covered NERC’s Critical Infrastructure Protection (CIP) standards, while Petak handled the suite of standards grouped under the Operations and Planning (O&P) label. Both discussed the most-violated requirements and best practices to prevent infringements.

Among the CIP standards, Sanders said the most-recorded violation is of requirement R2 of the CIP-003 family, the currently enforceable version of which is CIP-003-8 (Cybersecurity — security management controls). This requirement mandates that entities “with at least one asset … containing low impact [grid] cyber systems shall implement one or more documented cybersecurity plan(s)” for those systems.

Sanders reviewed the mandatory components of such cybersecurity plans, which comprise:

    • Cybersecurity awareness: Staff must be trained on cybersecurity best practices at least every 15 months.
    • Physical security controls: Any physical barriers, such as fences, locks and security cameras, between intruders and cyber assets.
    • Electronic access controls: Firewalls and other obstacles to online intruders.
    • Cybersecurity incident response plans: Plans must be tested at least once every 36 months.
    • Transient cyber asset and removable media: Safety protocols for USB drives and other physical media that can be added to or removed from a computer.

Other CIP violations frequently recorded within the first two years of registration include requirements R1 and R2 of CIP-002 (Cybersecurity — BES cyber system categorization). These require GOs to identify assets that contain low-impact grid cyber systems and review and update those identifications every 15 months.

“If your organization only has one generation facility, this may seem fairly straightforward. You obviously know about the generation asset [around] which your entire company is built,” Sanders said. “However, that documentation does need to exist, and for entities who are purchasing generation assets, you might have multiple generation facilities under a single [registration], [and] we need to have surety that you are aware of each of those facilities.”

In his O&P presentation, Petak noted that “facility ratings come up a lot in the early days,” with violations of NERC’s FAC family of standards comprising more than 20% of noncompliances that begin within 31 days of registration.

He reminded attendees that requirements R1 and R2 of FAC-008 (Facility ratings) mandate that GOs maintain documented methodologies for determining facility ratings, while R6 requires how those ratings are to be implemented and maintained. All three requirements are among the most frequent violations within the first month of registration, with R6 topping the list.

However, after the first 31 days, the biggest share of infringements shifts to NERC’s modeling (MOD) requirements, particularly MOD-026-1 (Verification of models and data for generator excitation control system or plant volt/var control functions) and MOD-027-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions).

Noncompliance with these standards usually is associated with requirement R2 of each one, which require GOs to have models in place for the applicable system functions. Petak noted that a common complaint among GOs is that “the deadline sneaks up on them in some way, or they were not tracking the deadline well enough,” and they or their third-party contractors lacked time to complete the verification.

“Having some sort of tracking software can definitely help out” with meeting the deadlines, Petak said. “In fact, most of the mitigating activities that we see when we’re processing these noncompliances involve the entity initiating some sort of software into their compliance program. So doing it before the noncompliance comes up would be ideal.”

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ERCOT: 60 GW in Additional Demand by 2031

ERCOT unveiled a long-term load forecast for 2031 on April 8 that adjusts projections provided by transmission providers and accounts for the uncertain nature of data centers and other large users. 

The numbers still are staggering. Even reducing the amount of utilities’ projected loads based on historical data, the study forecasts demand to reach 145 GW in 2031. That is less than transmission providers’ projections of 218 GW in 2031. 

The grid operator’s current peak demand is 85.5 GW, set in August 2023.  

“Several people are looking forward to [this], with bated breath,” Bill Flores, chair of ERCOT’s Board of Directors, told COO Woody Rickerson before he presented the adjusted methodology to the directors. 

The new treatment of load projections is a result of state legislation passed in 2023 (House Bill 5066) that updated regional transmission planning rules and required ERCOT to consider prospective loads identified by transmission providers. Previously, state laws prohibited the grid operator from factoring in load that was not financially committed or signed. 

The legislation also directs ERCOT to file an annual report quantifying the capability of existing and planned generation and load resources. Staff plan to meet that requirement by using their semiannual Capacity, Demand and Reserves (CDR) report, as they did in December 2024 by using the TSPs’ load forecast. 

ERCOT COO Woody Rickerson | ERCOT

However, that CDR revealed negative planning reserve margins as early as 2026. (See ERCOT’s Revised CDR Report Met with Doubts.) 

“We’re going to pivot away from using that forecast in this year’s May CDR,” Rickerson told the board. He noted the legislation’s “most impactful difference” was ERCOT accepting transmission providers’ officer-attested letters, which he attributes to much of the future data center load growth. 

The adjusted load forecast is based on three adjustments:  

    • delaying the in-service date by 180 days for all new large loads;
    • reducing new data center demand to 49.8% of the requested forecasts;
    • reducing officer-attestation loads to 54.55% of forecasts.

Rickerson said the reductions represent a “measured percentage of power being used” versus the forecasts. 

“An important part to keep in mind here is that this is a forecast based on the most recent data we have, and we’ll continue to update that as we move forward,” he said. “Those numbers were derived from loads that had been forecasted that we can now see and measure. Those numbers, as we move forward, can change as forecasts become more accurate.” 

The problem, Rickerson said, is how to count the large loads (75 MW or more) that data centers, hyper-scalers and crypto miners are planning.  

The board questioned Rickerson on the accuracy of data provided by transmission providers.  

“Data centers are not something that we were forecasting or looking at four, five years ago, so this is new information. How fast it builds out is something we’re all going to learn together,” he said. 

Rickerson said the quality of data needs to be adjusted “based on just the leading edge of historic numbers.” As ERCOT gets more of those numbers, he said, the grid operator’s adjusted load forecast and the transmission providers’ aggregate projections likely will merge into one. 

ERCOT CEO Pablo Vegas said Senate Bill 6, an omnibus energy bill being considered in the 2025 Legislature, includes provisions addressing the inputs into transmission providers’ forecasts. 

The ISO will begin incorporating the adjusted load forecast in transmission planning, resource adequacy and outage coordination analyses. Rickerson said a good-cause exception may be required from the Public Utility Commission. 

There could be some good news in the future over the escalating demand ERCOT faces. 

Pia Orrenius, a senior economist with the Federal Reserve Bank of Dallas, followed Rickerson’s presentation by saying the Texas economy is “likely slowing.” 

“[Business] outlooks have recently turned pessimistic,” she told the board, noting surveys of Texas businesses are “flashing some warning signs.” 

“Growth is likely to slow further … and will probably slow further than we’re currently forecasting,” she said. “The main reason is tariffs. They’re going to lead to higher prices. Consumption and investment will slow and possibly decline.” 

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MISO Fast Lane Proposal Disadvantages IPPs, Retail Choice States, Critics Tell FERC

MISO’s proposal to use a temporary “fast lane” in its interconnection queue to speed up necessary resource additions would give utility-owned generation preferential treatment, according to protesters’ comments filed with FERC on April 7, with a group of former commissioners saying it should be a nonstarter.

The RTO filed its proposal to install the fast lane by the beginning of summer with FERC on March 17. (See MISO Says Queue Fast Track Design Settled, Ready for FERC.) The plan would have projects designated as essential by regulators traversing a separate queue equipped with dedicated, individual studies instead of the cluster-style studies MISO uses in its ordinary queue (ER25-1674).

MISO staff have said its current interconnection procedures are not up to the task of processing new projects expeditiously because of a buildup of projects with study delays. The grid operator has proposed using the special process for the next four years to overcome capacity deficits.

The plan drew a letter from eight former FERC commissioners — Democrats and Republicans alike — to express “deep concern.” The group, which includes past Chairs Richard Glick, Neil Chatterjee, Joseph T. Kelliher and Pat Wood III, said creating a special, expedited interconnection study treatment in the queue “presents the opportunity for self-dealing by utilities to advance their affiliated generation.”

The former commissioners said the fast lane’s process, in which a proposed generating facility must either be owned by a load-serving entity or have a power purchase or similar agreement with proof of load, appears unworkable. The group pointed out that independent competitive generation projects have historically been unable to finalize offtake terms and arrangements in contracts until they are assigned network upgrade costs in the queue. They called the plan a threat to FERC’s policy of open-access transmission.

They also questioned whether regulators would use an independent process or seek to avoid undue discrimination when selecting projects for special study treatment. They said PJM and CAISO’s recent adoption of queue expressways differ from MISO’s, which is “not narrowly tailored and allows affiliated generation to receive preferential treatment.”

“It has been nearly 30 years since FERC first planted the flag of open access when the commission issued Order No. 888. We have come too far to reverse course now, especially when, as other regions have demonstrated, more narrowly tailored options to expedite the generator interconnection process for resource adequacy purposes are available,” warned the former commissioners, which also include James Hoecker, Donald Santa, Nora Mead Brownell and John Norris.

States Divided

Support for the proposal among MISO’s states fell along retail choice lines.

The Illinois Commerce Commission said it believed the fast lane would discriminate against retail choice jurisdictions and give preferential treatment to vertically integrated states. While state identification of need would work for those that use integrated resource plans, it wouldn’t work for Illinois, which relies on competitive markets to ensure resource adequacy, the ICC said.

Illinois is MISO’s only true retail choice state; Michigan allows up to 10% of a utility’s retail electric sales to be purchased from alternative suppliers.

“Unless the proposal is amended, the projects in Illinois will be at a disadvantage,” the ICC argued. MISO’s proposal as is does not contain “workable language” to include Illinois or Michigan in short-term reliability considerations, it said.

Rolling out the special queue lane in a staggered manner wouldn’t be a solution, either, the ICC said, because by the time MISO established specialized rules for Illinois, the state would have suffered “irreparable economic harm” from the delay.

Vistra, which operates resources in downstate Illinois’ Zone 4, agreed. The company said the fast lane would bestow undue preference for generation in vertically integrated states, violating the Federal Power Act, and give LSEs a leg up over independent power producers.

Vista said MISO is failing to ensure the fast lane would be limited to interconnection requests needed to meet resource adequacy or reliability requirements. The company argued that a request from a regulatory authority to study a resource does not mean it will meaningfully contribute to resource sufficiency.

“If MISO is going to take the exceptional step of allowing select resources to bypass the queue in the name of meeting near-term reliability needs, then there must be a reasonable basis for concluding that these resources can meet the specific reliability needs identified by MISO,” Vistra said.

The Michigan Public Service Commission expressed concern that the plan could worsen “inherent inequities” unless applicants for expedited treatment show they have analyzed whether existing projects in the queue could solve the resource adequacy problem they seek to address. Absent that step, MISO could facilitate discriminatory practices and “do grave harm to fundamental principles of open-access transmission that have been core tenants of FERC’s regulatory framework since the issuance of Order 888 in 1996,” the PSC said.

It also said it doubted MISO’s commitment to bringing projects online as soon as possible because its plan includes a three-year grace period beyond its proposed three-year-out commercial operation date for expedited projects.

Earthrise Energy, which also owns generation in southern Illinois, said FERC should direct MISO to amend its filing so it includes a separate plan for Illinois and Michigan.

But the proposal drew plenty of support from vertically integrated states, including two governors.

Missouri Gov. Mike Kehoe, whose state turned up a capacity deficit in MISO’s 2023/24 Planning Resource Auction, said it is “committed to swift action to meet the needs of this moment.” He said that the express lane can help the industry meet unprecedented load growth reliably.

Indiana Gov. Mike Braun also supported the fast lane, saying it’s “essential for energy development” in his state.

“We are committed to providing reliable, affordable energy to all Hoosiers, but we cannot move as swiftly as necessary without MISO being equally as swift,” Braun wrote. MISO is right to recognize it needs urgency and a unique means to manage a confluence of accelerated load growth, a rash of resource retirements and lagging resource additions.

The Organization of MISO States framed the plan as a “necessary but limited mechanism” to maintain reliability across the footprint. OMS said most of its members support “enabling an alternative pathway other than the standard queue to meet immediate resource adequacy needs.”

The Arkansas, Louisiana, Mississippi and Texas commissions supported the proposal. Entergy operating companies, which make up the lion’s share of MISO South, were similarly on board.

Entergy Texas noted that it needs to bring its Legend and Lone Star gas plants — worth 1.2 GW collectively — online by 2028 to serve growing demand. Entergy Louisiana noted that it needs three new gas plants of its own at 2.26 GW to serve a new Meta data center. Entergy Arkansas said MISO’s queue backlogs “unreasonably impede” new generation coming online.

Questions over Fairness for IPPs

IPPs predicted that the fast lane, which wouldn’t use a megawatt cap to limit entries, would soon form a “second, unmanageable queue that would paralyze the MISO interconnection process.”

They also echoed Vistra’s concerns that regulators could make errors deciding which projects are essential and questioned “MISO’s decision to delegate many of the key terms and conditions of interconnection service to state and local regulatory authorities outside of FERC’s jurisdiction and leave those processes ripe for arbitrary and unduly discriminatory outcomes in violation of the FPA.”

They echoed the former FERC commissioners’ discrimination arguments and said the plan would put those developing competitive generation at a disadvantage while creating opportunities for LSEs to engage in self-dealing.

Public interest organizations, including the Sierra Club, Natural Resources Defense Council and Union of Concerned Scientists, called the proposal a “queue-jumping mechanism for preferred projects.”

Alliant Energy battery storage in Portage, Wis. | Alliant Energy

“In MISO’s own telling, such a proposal is necessitated by MISO’s failure to maintain a process that timely processes interconnection requests from new generation. And as a result of this failure, MISO now claims that it needs to create a separate interconnection process to ensure that these preferred projects are able to come online by the time they are needed for grid reliability,” the groups said. They added that MISO was missing a “technical quantification” of its RA need in its proposal.

NextEra Energy said the “gravity of harm that will be caused … cannot be overstated” and predicted that the proposal would give vertically integrated utilities free rein to “self-build their own generation solutions, bypassing gigawatts of independent generation stranded in MISO’s legacy interconnection queue.”

The Coalition of Midwest Power Producers (COMPP) lambasted the filing as well. It said MISO didn’t quantify its resource inadequacy and wrongly omitted Michigan’s Zone 7 and Illinois’ Zone 4 from the plan. COMPP said together, those two zones contain about 31 GW of load, just 3 GW less than the whole of MISO South. It asked FERC to reject the filing.

The Clean Grid Alliance (CGA) said the expedited proposal is redundant because MISO already has efforts underway to speed up its queue, including study automation help from tech startup Pearl Street, higher fees and the capping of annual entrants at 50% peak load.

CGA said expedited generation would be allowed to claim transmission capacity that otherwise could be available for projects in the traditional queue, causing harm to developers. It also said MISO didn’t seem to be considering that some of its 56 GW with signed generator interconnection agreements would overcome delays to come online and handily manage a projected shortfall of a few gigawatts. (See MISO Members Grapple with 54 GW in Incomplete Gen, Predict Storage Expansion.)

“Rather than meaningfully parsing out data from its queue and even attempting to match queued generation to sub-region resource adequacy shortfalls, MISO merely makes conclusory statements and cites to its reports that claim there is a resource adequacy shortfall,” CGA argued.

LSEs: RA Needs Above All

Michigan-based Consumers Energy said that even though the 1,603-project, 296-GW interconnection queue appears to be able to deliver on resource adequacy, more than 70% of projects drop out of the queue.

Consumers said the high withdrawal rate, coupled with supply chain, permitting and study delays, translates into waiting times for projects that regularly exceed three years. On the other hand, a fast lane is a “tool that can help identify necessary projects and provide a path for a limited number of these resource adequacy projects to get connected in time to meet customer needs.”

Duke Indiana said the fast track would be a solid plan, pointing out that NERC’s 2024 Long-Term Reliability Assessment indicated that MISO may experience a 4.7-GW shortfall in 2028 “if the current expected generator retirements occur without the addition of significantly more generation.”

DTE Energy, Alliant Energy, Ameren and WEC Energy Group likewise filed in support, all stressing MISO’s resource adequacy needs.

Transmission owners said the proposal is “tailored” to avert conflicts between expedited projects and those in the queue’s usual definitive planning phase by allowing both to be processed in tandem. TOs also said the plan is “intentionally targeted and time-bound with a built-in sunset date, at the latest, by the end of 2028.”

MISO has acknowledged its stakeholders are concerned over the potential for discrimination between generation projects and whether a need really exists to create a dedicated fast track in the queue. But staff maintain the proposal is necessary and won’t be unduly preferential.

“We have a significant resource adequacy need we’ve been projecting for a few years,” MISO’s Andy Witmeier said at a Dec. 6, 2024, workshop. He pointed to the warnings MISO delivers on a quarterly basis in front of its Board of Directors.

Witmeier said MISO is confident that it has enough “inherent barriers” in place to the fast lane that there won’t be a “mad rush” where developers enter projects “willy nilly.” He said projects must be recognized and accepted by a state to meet a known need before they are able to gain entry.

“MISO has always been open to queue reform and trying to make the process better … and more efficient for all users,” Witmeier said, noting that in the five years he has worked on the queue, the RTO has continually made improvements.

He said it is prepared to hire additional consultants, contractors or temporary personnel to take on the additional work of the fast lane, resulting in higher processing fees for interconnection customers, though it should be straightforward. MISO won’t create special studies; it will just conduct its usual interconnection studies on a condensed timeline by focusing on a single generating unit, he said. “We know how to study interconnection requests.”

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MISO Discards Interim Participation Option from Order 2222 Plan

MISO on April 7 announced it will scrap its plan to use an existing demand response participation category to get aggregators of distributed energy resources participating on a limited basis a few years ahead of its full implementation of FERC Order 2222 in 2030.  

During a DER Task Force meeting, MISO counsel Michael Kessler said the RTO decided that trying to bend the interim plan to all Order 2222 requirements as FERC recommended would be “unduly burdensome.” Kessler said MISO plans to inform FERC by July that it will abandon its DR participation idea rather than try to make it fully compliant with the rule. 

FERC accepted MISO’s second try at Order 2222 compliance Jan. 16, granting the RTO until mid-2029 to prepare before fully accepting DER aggregators into its markets in 2030. (See FERC Permits 2030 Finish Date for MISO Order 2222 Compliance.) 

The commission accepted MISO’s explanation that its underlying computer systems need work over the next four years. However, it told the RTO its plan to allow DER aggregations in its markets earlier in a two-phase rollout needed to be either deleted or revised significantly. 

MISO proposed to use a two-stage approach to Order 2222 compliance. First, it would use an existing DR resource participation category to get DER aggregations participating sooner — albeit on a limited basis — and providing energy, contingency reserves and capacity through behind-the-meter generation or controllable load. MISO would have begun registering DER aggregations under its DRR Type I model by Sept. 1, 2026, and would have allowed participation to begin by June 1, 2027. DER aggregations would have been limited to 1 MW or larger under the model. 

But in its Jan. 16 order, FERC said MISO’s proposed 1-MW size threshold is too large, as Order 2222’s minimum for participation is only 100 kW.  

The commission also said MISO’s DR placeholder doesn’t address the coordination, data requirements or means to discourage double-counting of resource contributions required under Order 2222. It decided the RTO missed the mark on using an existing participation model to eke out partial compliance. 

FERC gave MISO 180 days to either explain how the DRR Type I participation model could comply with Order 2222 or strike the first phase of participation from its compliance plan. MISO decided over the last few weeks that it would not salvage that aspect for a separate filing to allow DER aggregations to provide some services by the middle of 2027. 

Kessler said MISO attempting to make its planned, interim step complaint with Order 2222 would likely require the same system changes that aren’t doable until full compliance with the rule in late 2029 through mid-2030. 

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Federal Briefs

Venture Global’s Calcasieu Pass LNG Facility Gets FERC Approval

FERC last week approved U.S. LNG developer Venture Global to commence service on the remainder of the facilities at the Calcasieu Pass LNG Terminal in Louisiana, according to a filing. 

Venture Global recently asked FERC for permission to begin operations at its entire Calcasieu Pass LNG export facility and TransCameron pipeline project, the final step before moving to commercial operations. 

More: Reuters 

FERC Approves Pipeline Extension

FERC last week approved a 122-mile natural gas pipeline expansion cutting through East Tennessee. 

The Ridgeline pipeline will stretch from Smith County to the TVA’s Kingston power plant. To fuel the plant, Enbridge’s pipeline company plans to extend its pipeline all the way to Roane County. 

Construction is set to begin in the fall and be completed by fall 2026. 

More: WATE 

BLM Extends Public Comment Period for Oregon Lithium Project

The Bureau of Land Management last week extended the public comment period for a lithium exploration project in Oregon to April 25. 

BLM has been reviewing Jindalee Resources’ proposal to explore federal land for lithium since 2022. The agency published its resulting environmental assessment in late March and gave the public just five days to review and comment. BLM received more than 1,500 comments in those five days. 

The proposal includes drilling at more than 260 sites across 7,200 acres of sagebrush desert in Malheur County, near the Oregon-Nevada border, in search of lithium. 

More: OPB 

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State Briefs

REGIONAL 

SouthCoast Wind Contract Delayed for a Third Time

SouthCoast Wind and utility companies in Rhode Island and Massachusetts last week announced a three-month extension to finish contract negotiations for the 147-turbine wind farm planned south of Martha’s Vineyard and Nantucket. 

The new June 30 deadline marks the third delay since Rhode Island and Massachusetts jointly unveiled plans in September to buy power from SouthCoast Wind following a solicitation that included Connecticut. Supply chain delays and inflationary pressures have driven up developer costs, prompting some companies, including SouthCoast, to renege on existing pricing agreements in hopes of a more lucrative deal. That has put more pressure on utilities and ratepayers to cover the rising expenses. 

More: Rhode Island Current 

COLORADO 

Polis Signs Bill Recognizing Nuclear as Clean Energy

Gov. Jared Polis last week signed a bill that will have the state recognize nuclear energy as “clean energy.” 

This year’s bill passed the Legislature with bipartisan support, with a 43-18 vote in the House and a 29-5 vote in the Senate. 

Nuclear energy production in Colorado has been dormant since 1989, when the state’s only nuclear power plant, Fort St. Vrain in Weld County, ceased operations.  

More: The Aspen Times 

IOWA 

MidAmerican Energy Seeks New Natural Gas Fee

MidAmerican Energy last week filed a request with the Utilities Commission seeking approval to add a 0.4% capital investment charge to the bill of residential gas customers. 

MidAmerican spokesman Geoff Greenwood said the charge, which would add about 17 cents to the average residential bill, would “cover costs that Mid-American has already paid out that are associated with certain natural gas system costs.” 

More: Radio Iowa 

MARYLAND 

Gov. Moore Issues Executive Order that Could Delay EV Sales Penalties

Gov. Wes Moore last week issued an executive order that could delay initial penalties for EV manufacturers who do not meet sales goals under a prescriptive state plan that is supposed to take effect next year. 

The order will maximize the Department of Environment’s enforcement discretion “to ease compliance” with the rule – including by declining to enforce penalties for model years 2027 and 2028. Moore’s order stated that President Donald Trump’s tariffs and actions on electric vehicles, including rescinding funding for charging infrastructure, also pushed Maryland to intervene to assist manufacturers. 

Maryland adopted Advanced Clean Cars II, which requires EVs to account for 43% of cars sold in the state by a manufacturer in the 2027 model year. The number grows to 51% in 2028, eventually reaching 100% by the 2035 model year. The state also adopted a similar rule for larger vehicles such as trucks. Moore’s order also opens the door for the DOE to avoid enforcing penalties on those vehicles for model years 2027 and 2028, unless the agency releases an assessment on the rule by Dec. 1. 

More: Maryland Matters 

MASSACHUSETTS 

DPU Acts Against National Grid over Billing, Service Issues

The Department of Public Utilities last week took action against National Grid, limiting how much it can collect from customers after months of billing failures and fining the company millions of dollars for service issues in 2023. 

The DPU told National Grid in its letter that it was not allowed to bill customers for several months of energy usage, saying, “For each customer who has not received a bill since the beginning of the peak season, the company shall waive charges for any usage occurring more than 60 days prior to the date the company sends the customer its next bill. For customers who did not receive a bill for more than 60 days, the company shall either waive collection of amounts owed for usage more than 60 days prior to the date of said bills or, if the customer has already paid, the company shall credit or refund such sums to each customer.” 

The DPU also fined National Grid $15 million “for service quality failures in 2023.” 

More: WBTS 

MONTANA 

Senate Committee OKs Bill to Give Governor Power to Appoint 3 PSC Members

A bill that aims to give the governor and the Senate the power to appoint and confirm three of the Public Service Commission’s five members passed the Energy, Technology and Federal Relations Committee with a 9-4 vote. 

Currently, all five members are elected by voters in five separate districts and can serve two four-year terms back-to-back. If the bill were to be signed into law, only two of the members would be elected by voters in the state’s two congressional districts. The other three would be appointed by the governor and would need confirmation by two-thirds of the Senate. 

A similar bill introduced in the House earlier this year failed to get out of committee. 

More: Billings Gazette 

PENNSYLVANIA 

Scranton Approves 1st Solar Farm

The Scranton Zoning Board last week voted 3-2 to approve what will be the city’s first commercial solar farm. 

Bear Peak Power of Denver will construct the 3.2-MW farm with 6,580 solar panels on 13.7 acres. 

Further reviews could take 12-18 months, with construction beginning after that. If so, it could be until late 2026 or early 2027 before the facility is operational. 

More: The Times-Tribune 

VIRGINIA 

Mecklenburg County Favors Solar Project

The Mecklenburg County Planning Commission last week voted 7-5 to recommend a special exception permit for the 7 Bridges Solar project. 

The 80-MW project is slated for 499 acres. 

The recommendation advances to the county Board of Supervisors, which is expected to take up the matter May 12. 

More: SoVaNow.com 

WYOMING 

PacifiCorp Changes Plans for Dave Johnston Coal Plant

PacifiCorp last week altered its plans for the Dave Johnston coal-fired power plant while solidifying plans to stop burning coal at the Naughton power plant by the end of this year. 

Rather than fully retiring two of four coal-burning units at the Dave Johnston plant in 2028, the utility now plans to convert those units to natural gas in 2029 and continue their operation. A third coal unit will be shut down in 2027, as previously planned, and the fourth, which had no retirement date, will now be converted to natural gas in 2030. 

The company’s plans for the Jim Bridger plant and the Naughton plant didn’t change. Two of four coal units at Jim Bridger were converted to natural gas last year, and the company still plans to retrofit the other two units there with carbon capture technology by 2030 or 2032. At Naughton, the first of three coal units was converted to natural gas in 2020. PacifiCorp confirmed it still plans to take the two remaining coal units offline by the end of this year and resume operating them on natural gas in 2026. 

More: WyoFile 

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Company Briefs

Delta Utilities Acquires CenterPoint’s Distribution Companies Serving La., Miss.

Delta Utilities last week announced it has acquired CenterPoint Energy’s three regulated natural gas local distribution companies that serve Louisiana and Mississippi. 

The sale includes around 12,000 miles of main pipeline serving about 380,000 customers. 

No financials were disclosed. 

More: KSLA 

Brookfield Nears $9B Deal for Colonial Pipeline

Brookfield Asset Management is said to be putting the final touches on a deal to acquire Colonial Pipeline, the largest U.S. fuel transportation system, for more than $9 billion including debt, according to people familiar with the matter. 

Colonial’s pipeline system stretches more than 5,500 miles from Houston to New York’s harbor. It moves more than 100 million gallons of fuel daily, including gasoline, jet fuel, diesel and heating oil, according to its website. 

A deal could be formally announced in the coming weeks, barring any last-minute snags, the sources added. 

More: Reuters 

APA Solar Invests $19.5M in Ohio Expansion

APA Solar, a solar racking company, last week announced it is planning to build a new 30,000-square-foot headquarters building in Ridgeville Corners, Ohio. 

The company said it will invest $19.5 million and hire 133 people as part of the expansion. The investment follows an upgrade in 2023 in which the company invested $10 million to expand its Henry County manufacturing facility. 

Construction of the headquarters is expected to be completed in early 2026. 

More: pv magazine 

Lithium Americas Reaches Final Investment Decision for Thacker Pass Mine

Lithium Americas last week said it has reached a final investment decision for constructing the first phase of the Thacker Pass lithium mine in Nevada. 

The Thacker Pass project is a joint venture between Lithium Americas and U.S. automaker General Motors. Phase 1 of the project is expected to be completed in late 2027. Once open, it is expected to produce 40,000 metric tons of battery-quality lithium carbonate per year in its first phase, enough for up to 800,000 EVs. 

More: Reuters 

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Industry Must Share Risk Over Nuclear-Powered Data Centers, Experts Say

LA JOLLA, Calif. — As the U.S. Department of Energy explores using federal land for data centers powered by nuclear energy, experts say public-private risk sharing will be crucial to making nuclear viable. 

The DOE on April 3 issued a request for information related to developing data centers on federal land, with 16 potential sites identified as “uniquely positioned for rapid data center construction, including in-place energy infrastructure with the ability to fast-track permitting for new energy generation such as nuclear,” according to a news release. 

The issue of nuclear energy and data centers also was discussed in La Jolla, Calif., during the joint spring conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) on April 4.  

WECC’s 2024 Western Assessment of Resource Adequacy (WARA) found that annual demand in the Western Interconnection will grow from 942 TWh in 2025 to 1,134 TWh in 2034. That 20.4% increase is more than four times the 4.5% growth rate from 2013 to 2022 and twice the 9.6% growth forecast in 2022 resource plans. (See West to See ‘Staggering’ Load Growth, WECC Report Says.) 

WECC said large loads are a major factor in the rapid demand growth, including data centers, factories and cryptocurrency mining. Electrification also plays a role.  

While there is widespread support for nuclear energy, which holds the potential to supply large amounts of baseload emissions-free electricity, there is a need for risk sharing, especially in the beginning as the industry navigates costs, construction cycles, regulations and other challenges, said Marcus Nichol, executive director of new nuclear at the Nuclear Energy Institute. 

“The utilities that might own and operate and build these, they’re willing to take on some risk,” Nichol said. “We’re actively working with them to help reduce the risk so that it’s more manageable. But they need help to be able to take this on.” 

Nichol noted that there are federal tax incentives in place, and U.S. Sen. Jim Risch (R-Idaho) introduced the Accelerating Reliable Capacity Act in December to accelerate investment in commercial nuclear projects by minimizing cost overrun risk. 

States also are “looking at their own state-tailored policies to be able to help contribute to taking on some of the risk,” Nichol said. Some data center developers also are looking to “contribute and take on some of the risk as well,” Nichol added. 

Meta, Microsoft and Amazon all have announced plans to power data centers with nuclear technology. (See Meta Seeks Nuclear Partners; AWS Boosts Efficiency.) 

For example, Constellation Energy plans to reopen Three Mile Island Unit 1 under a power purchase agreement with Microsoft to sell about 835 MW to serve the company’s data centers. (See Constellation to Reopen, Rename Three Mile Island Unit 1.) 

Amazon, meanwhile, has committed $1 billion to early stage development work, said Nate Hill, head of energy policy at Amazon. 

“From Amazon’s perspective, we’re willing to put our capital at risk to help get some of these early stage projects off the ground,” Hill said. “Because, I mean, when you think about it, like some of the costs of these projects could be more than the market cap of some utilities. So, there’s going to have to be risk sharing.” 

Katie Rogers, manager of reliability assessments at WECC, noted that the numbers could change as WECC learns more about how much of the demand will be realized. 

Still, the industry must move toward holistic grid planning and share the burden, Rogers said. 

“It feels very much like that we maybe need to have a different approach to how we plan the grid, and maybe not looking at, you know, one person carrying or one subset of people carrying all the risk if it has broader implications to the grid,” Rogers said. “It needs to be looked at holistically with everything.”