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February 26, 2026

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Indiana Commission Opens Affordability Inquiry into Utilities

The Indiana Utility Regulatory Commission opened an investigative inquiry into the state’s major utilities in response to increasingly steep residential electric and gas bills.

IURC Chair Andy Zay, who has been on the job for six weeks, promised a “transparent and public discussion” on affordability and rising rates. He said the “environment we’re living under” is a product of rate cases that were decided three to four years ago and whose full impact is now being felt.

“I think affordability is defined every … month by Hoosiers when they receive that bill,” Zay said during a Feb. 25 press conference.

The IURC will hold a hearing March 24, with representatives of all five major utilities in the state called to appear. They are asked to present on energy affordability, bill transparency and how they could bring down mounting costs in the near term.

Zay said the IURC is going to proceed as quickly as it can. He said he plans to personally meet with ratepayers while collecting information in the field. The inquiry could morph into a formal investigation with a case number, Zay said, and could also set off a re-examination of existing law.

To submit a commentary on this topic, email forum@rtoinsider.com.

“There may be legislative concerns that come out of this inquiry,” Zay said. “As you know, we do not make policy here at the commission. We’re the implementors of policies.”

However, Zay said, he wants ratepayers to know that “we have their back” to help ensure there are enough energy resources for economic growth at the most affordable rates possible.

Including Zay, the IURC comprises three new commissioners, appointed by Gov. Mike Braun in December 2025. Zay is a former state senator.

Indiana’s major regulated investor-owned utilities include AES Indiana, CenterPoint Energy, Duke Energy Indiana, Indiana Michigan Power and Northern Indiana Public Service Co. Of those, NIPSCO has raised rates most dramatically in recent years. (See Consumer Group Says NIPSCO Affordability Crisis Direct Result of Indiana Laws.)

The IURC’s 2025 Electricity Residential Bill Survey found the average NIPSCO customer using 1,000 kWh in July shouldered an over-90% increase in their bill from 2016 to 2025. The U.S. Energy Information Administration also reported that NIPSCO in 2024 charged the second-highest residential customer rate among all electric utilities that reported data. NIPSCO’s rate is about 30% higher than Indiana’s median residential rate.

A day before the inquiry announcement, IMP announced it would file a rate decrease with the IURC this summer. The utility said it could lower base electric rates because of higher revenue from an influx of large load customers, including Google’s data center in Fort Wayne.

Zay said the press conference was unprecedented because the commission is “not typically an outward-facing agency” and it is not the agency’s “style … to get involved in these issues.”

However, he said the commission’s Consumer Affairs Division has received a “volume” of complaints, as well as correspondence from state representatives.

Zay said the commission took a few months to decide how to address fast-rising rates because it was examining what role it could play in short-term solutions. He said until now, most of the IURC’s work is reactionary based on the cases that come before it.

“It’s time for us to participate in two ways: one, be reflective of decisions we’ve made in the past and change the tone or create a tone of how we’re going to look at cases going forward, and two, [decide] what we can do in the short term,” Zay said.

He cautioned that the commission is challenged not only by affordability concerns, but also by reliability, resilience and environmental considerations.

“Those are difficult to define in a financial sense. And that’s in no way to excuse or dodge anything,” he said.

Former Commissioner Praises Probe

Regulatory Assistance Project principal Sarah Freeman, who exited the IURC in October 2025 after nine years as a commissioner, said the inquiry is an “important step in making energy regulation — and thus affordability concerns — more open, accessible and accountable to the public.”

“Energy regulation and ratemaking are getting the public attention they’ve always deserved, but the reason why is deeply unfortunate,” Freeman said in a statement to RTO Insider. “Every Hoosier deserves to be able to afford life’s necessities, and it’s unacceptable that anyone has to make impossible choices like whether to heat their home or feed their family.”

Freeman commended the IURC for hearing concerns and acting on them. She said the recent passage of Indiana’s House Bill 1002 — which would link rates to performance benchmarks like affordability and reliability — provides “an opportunity for the commission to really dig deep and figure out how to make reliable energy cheaper for Hoosiers.”

But Indiana consumer and environmental advocacy organization Citizens Action Coalition has said laws the state enacted in 2023 and 2025 have rendered the IURC powerless to do anything but endorse rate hikes.

Freeman did not comment on whether she was unable to rein in rate increases because of state law.

A Reckoning for Past Laws?

Indiana House Democrats released a joint statement welcoming the inquiry; they also said blame can be attributed to legislation passed over the past 15 years.

“The truth is, legislation passed by the Statehouse Republican supermajority is why Hoosiers are facing massive spikes in their utility bills today. An investigation without an honest assessment of these policies will be incomplete,” they said.

Democrats said the existing unaffordability crisis originated in 2013 with Senate Enrolled Act 560, which created a charge that allowed utilities to recover 80% of the costs of system improvements without having to establish a rate case. They also cited subsequent laws that ended Indiana’s energy efficiency program, terminated net metering, stuck customers with coal ash cleanup costs, allowed construction work in progress (CWIP) recovery and shut out transmission-building competition through a right of first refusal for incumbent utilities.

Nearly a month before the IURC’s announcement, a group of 16 House Republicans sent a letter to Zay detailing “a significant rise in the number of emails, phone calls and letters from our constituents regarding their NIPSCO bills.”

They said NIPSCO’s rate statistics in particular are “concerning” and requested an investigation into whether “rates have become unreasonable or unjustly discriminatory.”

The Republicans asked the IURC to get to the bottom of what investments and operational expenses of the last decade have led to the increases, compare rates among other state utilities and those in peer states and identify steps to curb rising energy rates.

“We want to thank all who have reached out to us about the hardships that they have faced due to these high NIPSCO bills, and we will continue to advocate that Indiana’s regulatory framework properly balances the five pillars of energy policy: affordability, reliability, resiliency, stability and environmental sustainability,” they wrote.

They did not address whether past laws that allowed automatic charges and trackers influenced the predicament.

Meanwhile, in neighboring Illinois, lawmakers have introduced the Utility Transparency Act (HB4781/SB3497), which could prohibit utilities from passing on certain internal costs to customers, including corporate and legal fees, advertising, trade group membership dues and insurance to protect shareholders. It represents the state’s tactic to counter its own spate of electric and gas bills that have recently doubled.

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APS Would See Greater Savings in EDAM, Analysis Finds

Arizona Public Service would save $110 million/year by joining CAISO’s Extended Day-Ahead Market (EDAM) rather than SPP’s Markets+, a new analysis has found, even if other Arizona utilities remained with Markets+.

The analysis by Aurora Energy Research for the Environmental Defense Fund, released Feb. 9, looked at day-ahead market participation by APS, Tucson Electric Power and Salt River Project. All three, along with Unisource Energy Services, announced their plans to join Markets+ in November 2024.

TEP would save an estimated $8.1 million/year by joining EDAM even with APS and SRP participating in Markets+, Aurora’s analysis said. In contrast, SRP would see a cost increase of $4 million/year or more by joining EDAM instead of Markets+.

The annual figures are averages for 2027 to 2040. Aurora based its market footprints on commitments made to join either EDAM or Markets+, and in some cases which direction an entity seems to be leaning. Included in the EDAM footprint are NV Energy, which is awaiting state regulatory approval for its EDAM choice; Idaho Power, which is deemed a likely EDAM participant; and Seattle City Light, which has expressed interest in EDAM.

The analysis assumes the Western Area Lower Colorado (WALC) balancing authority area remains uncommitted to either day-ahead market. WALC — which spans parts of Arizona, California and Nevada — is run by the Western Area Power Administration’s Desert Southwest Region, which in March 2024 pulled out of the second phase of Markets+ development after determining it would see few benefits from joining a day-ahead market. (See WAPA DSW Cites Lack of Benefits in Markets+ Withdrawal.)

Aurora also looked at an Arizona-wide scenario in which APS, TEP, SRP and WALC participated in EDAM. In that case, the entities would save $115 million/year on average compared to APS, TEP and SRP joining Markets+ and WALC staying uncommitted.

“Choosing a West-wide market is one critical step in managing affordability and strengthening grid resilience,” Alex Routhier, senior policy adviser with Western Resource Advocates, said in a statement. “Utilities must evaluate all available options and choose the market that will deliver the greatest cost savings and reliability benefits to Arizonans.”

Governance Questions

EDF said EDAM “is poised to be the largest and most resource-diverse market in the region.” Following the passage of California Assembly Bill 825 in 2025, EDAM will be governed by a new independent Regional Organization for Western Energy — a step that might alleviate some concerns about independent governance — and CAISO will operate the market itself.

But Nick Myers, chair of the Arizona Corporation Commission, said he still has issues with EDAM.

“Should EDAM decide to address the governance and resource adequacy issues in a manner that is acceptable to others, which means providing a level playing field for all states, then I can envision a scenario where we could re-evaluate” the utilities’ participation in Markets+, Myers said in a statement to RTO Insider. “But until that time, Arizona is unlikely to choose a market that disproportionately favors California interests to the detriment of Arizona customers.”

Myers said he had not yet fully reviewed the Aurora report. He noted that Arizona utilities have their own studies showing that customers could benefit from either market.

In announcing its plans to join Markets+, SRP said it was drawn to its governance structure, which promotes independence, transparency, inclusivity and stakeholder-driven decision-making. (See 4 Arizona Utilities Commit to Joining Markets+.)

Resource adequacy was another factor in the utilities’ decision. SPP will require Markets+ participants to join the Western Power Pool’s Western Resource Adequacy Program.

APS said it did not participate in the Aurora study. Instead, the company performed “a rigorous evaluation of all market options,” factoring in reliability, affordability, customer protections and governance.

“The analysis indicates that Markets+ provides the greatest long-term value for our customers,” APS said through a spokeswoman. “We continue to be excited about customer benefits as we prepare to participate in Markets+ in late 2027.”

Costs and Savings

If APS joined EDAM while TEP and SRP stayed with Markets+, APS’ production costs would increase because of the need for more thermal generation in response to decreased thermal imports from SRP, according to the report. But bilateral trading costs would fall as overall import volumes decrease and access to renewables grows in the wider EDAM footprint.

APS’ congestion and wheeling revenues would increase because of greater use of transmission capacity from trade with PacifiCorp East and Public Service Company of New Mexico (PNM).

TEP’s savings from joining EDAM rather than Markets+ are in part from a $25 million decrease in production costs, as baseload thermal generation declines because of reduced exports to Markets+ balancing areas, the report says. Those savings would be partially offset by decreases in congestion and wheeling revenues. Export revenues would fall as TEP’s trading footprint shrinks. Under EDAM, TEP would trade more with PNM and less with APS and SRP.

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Nonprofits Tell 9th Circuit BPA’s DAM Decision Poses ‘Imminent’ Harm

The consequences of the Bonneville Power Administration’s decision to join SPP’s Markets+ could hit the Northwest sooner rather than later even though the agency has yet to formally join the market, a group of nonprofits suing it over the choice told the 9th U.S. Circuit Court of Appeals.

The group wrote in a reply brief that the potential injuries arising from BPA’s day-ahead market choice are “imminent,” urging the court to reject agency’s argument that the suit is too hypothetical for standing. The brief is dated Feb. 20 but appeared on the docket Feb. 23.

As the NW Energy Coalition “has emphasized, Bonneville is now implementing numerous steps to ‘go live’ in Markets+ in October 2028,” the group wrote. “Every additional step towards that date without vacate and a remand order will make a fair and candid look at alternatives less likely. The court has everything it needs to vacate the DAM policy and [Record of Decision] and remand for preparation of an” environmental impact statement.

Represented by Earthjustice, the organizations suing BPA include NWEC, Idaho Conservation League, Montana Environmental Information Center, Oregon Citizens’ Utility Board and the Sierra Club.

On May 9, BPA issued its decision to join Markets+ over CAISO’s Extended Day-Ahead Market (EDAM). The announcement came after a lengthy debate over which day-ahead market would provide the most benefits to BPA and its customers. (See BPA Chooses Markets+ over EDAM.)

The plaintiffs filed their claims July 10, alleging the agency failed to factor in environmental impacts and financial considerations in violation of the National Environmental Policy Act, the Pacific Northwest Electric Power Planning and Conservation Act, and the Administrative Procedure Act. (See BPA Sued in 9th Circuit over Day-ahead Market Decision.)

BPA has yet to officially join Markets+, but it plans to do so in October 2028.

In a Dec. 19 answering brief, the agency argued the plaintiffs lack standing because the alleged injuries rest on its participation in Markets+, which has yet to happen.

Even if the court finds the group has standing, the claims under the Northwest Power Act and NEPA fail under precedent established in the 9th Circuit, BPA argued.

BPA’s decision “is a quintessential example of the agency evaluating what is in its sound business interest,” according to the agency. It said the suit is an attempt at getting the court to “second-guess that determination.”

“Although they disagree with BPA’s conclusions, BPA considered the relevant factors and articulated a rational connection between the facts found and the choice made,” it contended.

In the Feb. 20 brief, the plaintiffs called BPA’s injury assessment “incorrect.” They noted that when BPA announced its day-ahead market choice, it also announced it intends to exit CAISO’s Western Energy Imbalance Market (WEIM).

“Leaving the WEIM will result in immediate cost and reliability harms to NWEC,” the Feb. 20 brief states.

BPA’s failure to consider the environmental impacts of its choice further demonstrates the immediate risk of harm, the plaintiffs claimed. It focused only on the economic impacts of extreme weather and the necessity of building out transmission lines and generation resources, which all “have environmental consequences that Bonneville never disclosed or considered,” they argued.

Though BPA claims the DAM policy and ROD are just preliminary steps and do not trigger the need for an environmental analysis, it has committed $40 million to Markets+, demonstrating there “is nothing tentative about this choice,” the plaintiffs argued.

“While a formal contract to join has not yet been signed, the policy and ROD set in motion multiple concrete steps that are designed to culminate in a contract to join Markets+ two years from now,” according to the brief. “These steps include negotiating specific contracts, initiating necessary rate cases and amending standards.”

BPA has argued that its day-ahead market process was conducted with significant stakeholder input, noting in its final market decision that other electric utilities weighing which market to join have done so “without public process or transparency.”

Production cost studies found that participation in EDAM under certain scenarios could deliver the agency up to $106 million in greater benefits than Markets+. However, the agency has contended those failed to factor in other key issues, like governance.

“BPA rationally opted for Markets+,” the agency argued in the Dec. 19 answer. “It presented less risk in meeting BPA’s core statutory function of economical service to its customers. Moreover, Markets+ proved superior in several important evaluation criteria, which, from early in the process, BPA emphasized would be important considerations.”

Trade organizations have filed motions to intervene in the suit in support of BPA, including the Public Power Council, Alliance of Western Energy Consumers, Pacific Northwest Generating Cooperative and Northwest Requirements Utilities. (See BPA Supported by Trade Orgs in Suit over Day-ahead Market Decision.)

They, along with SPP itself, highlighted Markets+’s governance approach and “overall design.”

The trade organizations filed a brief Jan. 23 saying, “BPA’s decision to pursue Markets+ was not arbitrary or capricious, as BPA considered relevant quantitative and qualitative factors and rationally applied those factors in reaching its decision.”

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DOE Loans $26.5B to Southern Co. for Infrastructure Upgrades

The U.S. Department of Energy announced Feb. 25 it will provide a loan package totaling $26.5 billion to Southern Co. that it said will deliver savings for ratepayers while enhancing grid reliability in Georgia and Alabama.

According to a statement, DOE will provide the loans under the Office of Energy Dominance Financing, the new name for the Loan Programs Office, to Southern utilities Georgia Power and Alabama Power. The 30-year package is the largest loan in the department’s history, it said.

The loans will support the building or upgrading of projects representing over 16 GW, including 5.3 GW of new gas generation and nearly 500 MW of capacity upgrades at existing gas plants; upgrades and license renewals for nuclear facilities totaling 6.3 GW; and modernization and enhancement projects at hydropower facilities representing 1 GW.

Battery energy storage system projects are also part of the funding package, along with about 1,300 miles of transmission and grid enhancement projects. DOE said in a fact sheet that the loans will “provide $7.3 billion in estimated customer savings” and reduce Southern’s interest expenses by $300 million/year, while Southern CEO Chris Womack said in a separate statement that the financing “will help lower the cost of investments in our grid that will enhance reliability and resilience for the benefit of our customers.”

“The Energy Department is lowering energy costs and ensuring the American people have access to affordable, reliable and secure energy for decades to come,” Energy Secretary Chris Wright said. “These loans will not only lower energy costs but also create thousands of jobs and increase grid reliability for the people of Georgia and Alabama.”

The financing announcement came the week after Southern released its fourth-quarter earnings, reporting net income of $4.3 billion for the year 2025, down from $4.4 billion the previous year. (See Southern Forecasts Continued Large Loads Growth.) The company announced plans to invest $81 billion across its subsidiaries through 2030, an expansion of the previously planned $63 billion; the main driver is new generation facilities, including five combined cycle plants, three combustion turbines, two combined solar and battery plants and 17 BESS facilities.

Both Georgia Power and Alabama Power have received permission from their state regulators to freeze base rates for several years. Georgia’s Public Service Commission in July 2025 approved Georgia Power’s plan to freeze rates through the end of 2028, and the Alabama Public Service Commission in December accepted a two-year halt on increases to Alabama Power’s rates. The PSCs’ decisions did not apply to storm recovery costs.

The loans to Southern follow $4.1 billion in financing provided to Constellation Energy to restart the Three Mile Island nuclear plant; an American Electric Power subsidiary to strengthen its transmission system; and Wabash Valley Resources to use a coal plant to produce fertilizer. The Office of Energy Dominance Financing has more than $289 billion in available loan authority and plans to prioritize projects in 2026 that it says contribute to energy security, grid reliability and affordability.

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Stakeholders Urge Changes to ISO-NE Surplus Interconnection Rules

Clean energy groups are calling for changes to ISO-NE’s surplus interconnection service (SIS) rules to use capacity headroom and help some resources avoid lengthy cluster study processes.

The RTO’s existing SIS rules stem from FERC Order 845, which required transmission providers to allow new resources to access unused capability behind existing interconnection points.

ISO-NE’s surplus process enables interconnection customers “to use any unused capability of interconnection service established in an interconnection agreement for a generating facility” while requiring the consent of the original customer and maintaining the original customer’s priority use of its interconnection rights.

The attractiveness of the surplus process lies in the ability for developers to avoid the interconnection cluster process, potentially enabling them to bring resources online more quickly.

But concerns about capacity revenue sharing, the extent of surplus studies and the lack of permanence of surplus interconnections appear to have limited the use of ISO-NE’s SIS pathway. To date, there is only one surplus interconnection agreement in the region.

ISO-NE has noted that surplus requests can still need extended studies when the resource has different performance characteristics from the original customer, including thermal analysis when adding charging capabilities to a site.

Surplus interconnection also does not equal permanent interconnection rights. If the original interconnection customer retired, the surplus customer would not retain its interconnection rights beyond a one-year grace period. It would need to proceed though the RTO’s general interconnection process to continue operations.

At the NEPOOL Transmission Committee meeting Feb. 24, several stakeholders emphasized the need for more clarity around the surplus application and study processes to help induce greater participation in the pathway.

ISO-NE “should focus on setting and meeting accelerated timelines in order to give developers confidence to proceed with projects,” said Bill Fowler, speaking on behalf of JERA Americas. JERA owns a fleet of large fossil generators in the region and has expressed interest in using SIS at its existing sites.

Fowler advocated for a nonbinding “target timeline” for ISO-NE approval of surplus requests set at “no more than six to nine months from filing an application.”

He said ISO-NE should consider changes to surplus accreditation in coordination with its ongoing capacity accreditation overhaul, and he recommended that the RTO “give SIS market participants flexibility in how the resources participate in the market, similar to how co-located facilities can choose to function as separate resources or as a single resource.”

Claire Lang-Ree, of the Natural Resources Defense Council, said ISO-NE “should recognize that surplus resources may improve the overall capacity value of the arrangement.”

She said ISO-NE’s proposed accreditation methodology for co-located storage and generation resources “could be a good fit for surplus arrangements.”

Speaking on behalf of RENEW Northeast, Carter Scott said changes would likely be needed to ISO-NE’s definition of unused capacity to account for the RTO’s proposed new accreditation framework, which would make resource accreditation values subject to change on a yearly and seasonal basis.

To reflect the new accreditation process, Scott said ISO-NE should allow both original and surplus resources to share capacity rights on a “more flexible, periodic basis.”

Multiple speakers noted that the proposed accreditation changes in the RTO’s Capacity Auction Reforms (CAR) project also likely will reduce the amount to accredited capacity in the region, potentially opening up headroom on the system.

Alex Lawton, director at Advanced Energy United, stressed that lowering barriers to surplus interconnection could help bring resources online more quickly and efficiently, helping prevent future resource adequacy issues.

“The current barriers that have prevented participants from using SIS to date stem primarily from difficulty participating in the capacity market, and the lack of permanent capacity interconnection rights,” Advanced Energy United wrote in a memo published prior to the TC meeting.

Lawton advocated for the creation of a process for capacity surplus customers to obtain permanent rights upon the retirement of the original customer without having to proceed through the interconnection cluster study process.

“If a [surplus interconnection customer] is required to go through a cluster study and potentially be responsible for network upgrade costs after it has already become operational, and if those upgrade costs are not supportable, this could lead to an unwanted market exit,” he said.

Responding to the stakeholder feedback, Alex Rost, director of transmission services at ISO-NE, detailed the RTO’s plans for a “gap analysis” intended to evaluate potential improvements to the surplus process and the potential “development of a comparable surplus interconnection service-like process” for co-location or resource repowering.

He committed to fully evaluating stakeholder proposals in the gap analysis, but he emphasized the subordinate nature of surplus interconnection customers. He noted that surplus customers can submit an interconnection request for permanent interconnection rights at any time.

He added that ISO-NE plans to evaluate surplus process timelines, surplus study scope and resource requirements in the gap analysis. He said the implementation of the CAR project would require an update to the definition of unused capability but added that this will depend on the outcome of the project.

ISO-NE plans to complete the analysis by early in the third quarter of the year, Rost said.

Stakeholders generally responded favorably to ISO-NE’s proposal for the gas analysis but expressed interest in expediting the timeline of the analysis and related discussions.

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FERC Declines to Suggest Interregional Transmission Requirements

FERC declined to suggest any minimum transfer capability requirements to Congress in a legally required report released Feb. 25.

The report was a required follow-up from the commission on NERC’s Interregional Transfer Capability Study, which found shipping power between some regions produces significant benefits. (See NERC Releases Final ITCS Draft Installments.)

“Increasing interregional transfer capability can be a potent tool in addressing reliability issues and warrants further examination,” FERC Chair Laura Swett said in a statement. “However, it is crucial to recognize that this measure is not a cure-all solution and should be considered in conjunction with potential economic impacts and other reliability strategies.”

FERC staff declined to make any suggestions for changes to the law in response to the study. The report notes that while transfer capacity has benefits, they come about only if the region on the other end of the line has excess generation.

“If neighboring regions lack resources, additional transfer capability will provide limited help because there is not enough surplus energy to share,” the paper says. “These results suggest that using a heuristic approach to establish interregional transfer capability requirements — such as setting a target to achieve interregional transfer capability to match a fixed percent of peak load or historical outages — can inaccurately value interregional transfer capability compared to an approach that accounts for the complexity of the transmission system. As is true with setting a planning reserve margin, an intuitive or informal approach is unlikely to set the right target compared to a more systematic approach that includes thorough analysis to support decision-making.”

The study analyzed how electricity moves across regions and identified opportunities to improve links between regions. It found ERCOT would benefit from plugging into the rest of the bulk power system, with up to 14,100 MW of interconnection suggested, and it also found increasing links between many regions in the Eastern Interconnection could produce significant benefits.

But the report also notes that forecasted deficiencies could be fixed with local generation development, demand response or simply by accepting more reliability risk during extreme weather events.

Many commenters on the study were not opposed to the idea of increasing interregional transfer capability, but another common theme was that the study is not a transmission planning document.

“According to the Niskanen Center, although the ITC Study combines historical and synthetic load to capture hourly variability, the United States is no longer experiencing a steady load growth as it did in the past decade, but rather accelerating load growth, and as a result the ITC Study results are already outdated,” FERC’s report says.

NERC’s initial study said that 35,000 MW of additional interregional transfer capacity would cut projected energy deficiencies and improve reliability, said Christina Hayes, executive director of Americans for a Clean Energy Grid.

“FERC’s staff report to Congress today stops short of translating those findings into meaningful statutory recommendations — despite mounting reliability pressures and accelerating electricity demand since the study was completed,” she added.

Failing to act decisively on transmission will undermine grid reliability, Hayes said, and Congress must include transmission in any permitting reform legislation.

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La. Energy Leads Say Determined Approach Lands Data Center Contracts

Louisiana utility players described their pull-out-all-the-stops, gas-propelled campaign to attract data centers as another hyperscaler announced plans for a new artificial intelligence-training facility in the state.

Amazon and Google’s fresh announcements for major data centers in Louisiana and Minnesota, respectively, grabbed attention at the Gulf Coast Power Association’s annual MISO–SPP Regional Conference.

“We’re in a power first world,” Entergy Louisiana CEO Phillip May said in a Feb. 24 keynote speech.

May said the data center revolution needs more than traditional regulatory frameworks and historical infrastructure buildout can offer.

“Regions that can deliver … are becoming new hotspots for growth,” he said. “Today, we’re being asked to deliver agility and adaptability.”

Northern Louisiana is set to host another multibillion-dollar data campus, this time a $12 billion Amazon facility near Shreveport.

American Electric Power’s Southwestern Electric Power Co. said it would supply power in a Feb. 23 announcement. Amazon said it has worked with SWEPCO to ensure it would pay all costs associated with the new data center.

Amazon’s venture is in addition to Meta building its largest, $10 billion-plus AI data center to date in Richland Parish.

One audience member in an earlier panel had pointed out that SWEPCO is valued at $9 billion, just 75% of the $12 billion deal. They asked at what point hyperscalers would outright buy a utility. Panelists demurred on the question.

May said investment is “mobile” and can switch prospective points on the grid easily. He said utilities must be able to compete for the new load. He lauded the Louisiana Public Service Commission’s new expedited review process, which can cut certain projects’ regulatory approval to an eight-month turnaround.

May said natural gas right now is the technology that can meet the scale of demand.

“It’s not an ideological argument. It’s an engineering reality,” May said. He added that nuclear must also play a role in the long term.

May framed data centers’ 24/7 load as a good thing, taking the guesswork out of planning generation and transmission investments.

‘Tired of Being on the Bottom of the List’

May asserted that Entergy Louisiana’s supplier philosophy is paying dividends and that the utility has been integral in Louisiana being able to attract $90 billion in capital investment since 2024.

“This is the moment we’ve been waiting for. We get to design the next 100 years of Louisiana,” he said.

Audience members asked if the massive investments are upping Entergy’s financial risk and if the utility is pursuing non-traditional means to secure capital.

“There’s a massive capital challenge to meet that,” May acknowledged. He said Entergy does not place generation projects for hyperscalers in its capital plan until data center developers strike electric service agreements and commit to funding all infrastructure costs associated with their facilities. He also said Entergy expects help with cash flow from the start to begin planning and construction.

May said Entergy played an instrumental role in creating the state’s 2024 20-year sales tax exemption on equipment and software for qualifying data centers. Entergy lobbied Gov. Jeff Landry (R) for the law, which was tailored to attract Meta.

“This state is hungry. We’re tired of being on the bottom of the list,” May said.

Data center centers are a good fit for lower-income regions of the state that until now have been “overlooked by economic development,” he argued. He assured residential customers in Richland Parish that they would pay less for power because of Meta’s planned, $10 billion data center.

‘Guarantee is a Guarantee’

In a later panel with a trio of state regulators, who are elected officials, Louisiana PSC Commissioner Jean-Paul Coussan said his inbox is flooded with constituents angrily asking why they are helping to defray data center costs. But he said that’s not the case in the state.

“The national conversation is controlling the narrative,” Coussan said. He said the commission required Meta to “immediately pay on bills” that its data center campus is triggering.

Coussan said constituents sometimes don’t believe that a “guarantee is a guarantee.”

From left: Sarah Freeman of the Regulatory Assistance Project, Missouri Public Service Commissioner John Mitchell, Louisiana Public Service Commissioner Jean-Paul Coussan and Minnesota Public Utilities Commissioner Joe Sullivan | © RTO Insider 

Some environmental and consumer advocates worry that Meta has since fundamentally changed the financing structure of the project and could wriggle out of its promised consumer protections. (See Earthjustice Says Change to Louisiana Meta Data Center Funding Fishy, Asks PSC to Investigate.)

In January, Earthjustice, on behalf of the Alliance for Affordable Energy and the Union of Concerned Scientists, filed a motion to request the PSC probe the new arrangement and its potential effect on ratepayer protections. The PSC on Feb. 25 declined to investigate the new financial setup.

Coussan said he has not reviewed the Google data center deal yet, and he is interested in seeing which consumer protections Google and SWEPCO intend to establish.

Google Stakes Claim in Southeastern Minn.

During the same panel, Missouri Public Service Commissioner John Mitchell said the “lightning pace” of demand and infrastructure additions causes him anxiety.

Minnesota Public Utilities Commissioner Joe Sullivan said that among other things, the impact of higher rates on those who can least afford them weighs on him.

Xcel Energy followed Louisiana’s Amazon announcement a day later on Feb. 24 with notice that it plans to power a new Google data center in southeastern Minnesota. Google similarly said it would pay all the costs accompanying the new campus and fund 1,400 MW of wind, 200 MW of solar and 300 MW of Form Energy’s long-duration, iron-air battery storage.

“We’re going to see. The rubber is going to hit the road very soon here,” Sullivan said of Xcel’s impending docket before the commission. He said Xcel will propose a large load rate in the coming months.

“We’re going to take one step in front of the next and work through it,” Sullivan promised.

Regulatory Assistance Project principal Sarah Freeman, herself a former Indiana commissioner, asked how regulators deal with the “trilemma” of achieving affordability and consumer protections, reliability and meeting demand.

Mitchell said although it is almost impossible to achieve all three, state commissioners must try.

Freeman said commissions can help create a “pathway” for data centers to be better neighbors to the communities they’re situated in.

In a conference where nearly every speaker stressed speed, Sullivan insisted his commission has time to make decisions. He said Minnesota’s integrated resource planning process affords it time to weigh projects.

“If you’re landing the 747, you can’t land it on a runway built for a Cessna. Fortunately, we have a runway for a 747,” Sullivan said of the commission, adding he has “tremendous faith in our process.”

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LaCerte: FERC Focused on Winning AI Race

FERC Commissioner David LaCerte was back before the Senate Energy and Natural Resources Committee on Feb. 25, just four months after being sworn in, for a hearing on his nomination for a full five-year term.

LaCerte was confirmed by the Senate in October to complete former Chair Willie Phillips’ term, which ends June 30. (See Senate Confirms Swett, LaCerte to Open Seats on FERC.)

The commissioner once again told the committee he supports expanding LNG and related onshore infrastructure to make natural gas exports possible. Speaking of his experience on FERC, he said the commission is focused on ensuring the U.S. wins the artificial intelligence race.

“This may be the defining competitive challenge of our generation,” LaCerte said. “If we are not the world’s leader in AI, our adversaries surely will be. We need to meet this moment, and we will do so without sacrificing affordability.”

So far, the biggest action FERC has taken on the issue has been to approve new transmission service options for data centers that want to co-locate with generators on PJM’s system. (See FERC Approves Transmission Deals Between ComEd and Data Centers.)

“I recognize this represents a first step in a very long road, but I’m proud of the decisive action the commission took at a time when energy demand is rising and reliability challenges are mounting,” LaCerte said.

He also said his personal focus is on ratepayers, reiterating what he said at his first open meeting of the commission in November.

“There are always people looking to curry favor for one project or one industry,” LaCerte said. “And I meant what I said: None of those people represent the ratepayers; I do. My commitment to the ratepayer has not wavered.” He emphasized that FERC has a duty to ensure that ordinary consumers do not face undue costs as the country deals with the demand growth from data centers and reindustrialization.

Sen. Alex Padilla (D-Calif.) asked LaCerte whether FERC needed to ensure that regions were doing adequate long-term transmission planning.

“In the past, I think we probably could have tightened some screws with some of the some of the plannings that have been done, both regionally, interregionally and at the state level themselves,” LaCerte said. “I think that it’s important that we squeeze every possible lot out of the existing grid that we have, and that means more diligent, more proper planning and taking a harder look at all the decisions before us.”

Sen. Angus King (I-Maine) said the power grid is designed to meet peak demand, which leads to inefficiencies. He asked whether LaCerte supports grid-enhancing technologies to make it more efficient.

“I think we need to squeeze every megawatt of the existing grid that we can — whether that’s dynamic line ratings, whether that’s grid-enhancing technologies of any type — but I can’t endorse one over another,” LaCerte said. “I think we need to do a much better job of being efficient with the grid that we have, in addition to building new transmission.”

The hearing was just on LaCerte’s nomination; the committee also heard from Kyle Haustveit, nominated to be undersecretary of energy, and former Rep. Steve Pearce (R-N.M.), who is up for director of the Bureau of Land Management. Haustveit is currently assistant secretary for fossil energy and carbon management at the Department of Energy.

The committee is well stocked with Westerners, several of whom noted how much land BLM controls in their states, but Pearce was also asked about the power sector. King noted that the bureau’s parent agency, the Department of the Interior, has not been processing renewable projects on federal lands under normal orders, requiring the secretary to sign off on individual projects.

“We’re facing a 2%-a-year increase in demand, which is unprecedented; compounded in 10 years, that’s a 30% increase in demand,” King said. “How are we going to get there by eliminating a significant source of energy from consideration?”

King, an independent who caucuses with the Democrats, asked what Pearce and Republicans will think if a future Democratic administration uses the same tactics to stymie fossil fuel development on federal lands.

Pearce did not answer the questions directly, saying he did not have the information to comment on the policy.

“It’s a conversation I’m more than willing to have with you and with the administration, but I don’t know the rationale,” he said.

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CAISO Unveils Principles for Western Seams Coordination

CAISO has released a set of guiding principles for upcoming discussions about seams between the ISO, SPP and other entities as the Extended Day-Ahead Market nears its opening in May.

In November, FERC staff urged Western electricity industry stakeholders to get ahead of seams issues before EDAM and Markets+ begin. (See FERC Report Urges West to Address Looming Market Seams Issues.)

CAISO’s eight principles focus on how to ensure the continued strength of the Western Energy Imbalance Market, which has provided significant reliability and financial benefits to its participants and their customers, CEO Elliot Mainzer said in a blog post Feb. 23.

“We hope all WEIM participants will carefully consider the unprecedented and fortuitous combination of physics, economics and fully independent governance of WEIM and EDAM before leaving the seamless real-time market we have worked so hard to build together,” Mainzer said.

WEIM currently includes 22 balancing authorities from 11 states that account for 80% of electricity demand in the Western Interconnection. The market has proven that balancing areas can function seamlessly in a real-time market, providing reliability benefits and economic value to participants and customers across the West, CAISO’s document says.

“Breaking up the WEIM footprint risks unwinding these benefits,” CAISO says. “Market-to-market seams arrangements are a poor substitute for seamless real-time operation of the grid and can only limit the loss of efficiency and reliability that results from fragmented footprints.”

One principle is that the seams issue is not a venue for market design advocacy.

“Market-to-market seams discussions are not a forum to relitigate transmission service [and] transmission rights, or a vehicle to redesign market rules,” CAISO says. “Seams discussions are predicated on sufficiently defined market protocol[s], transmission tariffs and market boundaries.”

Another principle is ensuring seams protocols minimize the risk of gaming or manipulation. Instead, protocols should support market power monitoring at interfaces to maintain competition.

CAISO’s EDAM will open in May, and SPP’s Markets+ is scheduled to begin in 2027. These markets could cause issues at their borders because of their different policies and dispatch processes. (See CAISO, SPP Explore Using Existing Tools to Manage DAM Seams.) The grid operators had made “significant progress” on adapting existing tools to tackle seams between their respective day-ahead markets, a CAISO representative said in December.

Seams negotiations are not solely between CAISO and SPP, Mainzer said. Instead, these discussions include balancing authorities, transmission providers, transmission operators, reliability coordinators, market operators and others when scoping procedures, agreements, discussions and solutions.

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DOE Extends Eddystone Emergency Order Through May

The U.S. Department of Energy has ordered PJM and Constellation Energy to keep the 760-MW Eddystone Generating Station online through May 24, extending an emergency order that has been in place since the plant’s final two gas-fired units were to deactivate May 31, 2025.

In an announcement of the Federal Power Act Section 202(c) order, Energy Secretary Chris Wright said the units helped PJM keep the grid reliable during the late January 2026 winter storm — dubbed Fern by The Weather Channel — during which Eddystone ran for 124 hours. The order states the generator, which is outside Philadelphia, must remain online because of “a shortage of facilities for the generation of electric energy and other causes.”

“The energy sources that perform when you need them most are inherently the most valuable — that’s why natural gas and oil were valuable during recent winter storms,” Wright said. “Hundreds of American lives have likely been saved because of President Trump’s actions keeping critical generation online, including this Pennsylvania generating station which ran during Winter Storm Fern. This emergency order will mitigate the risk of blackouts and maintain affordable, reliable and secure electricity access across the region.”

The order is the third 90-day mandate for PJM and Constellation, which owns Eddystone, to keep Units 3 and 4 online. DOE has also ordered Consumers Energy to keep its 1.45-GW J.H. Campbell coal generator in western Michigan to stay online until May 18 under a similar order. (See DOE Reups Campbell Coal Plant Emergency Ops; Losses Top $135M.)

The department wrote that the need for additional generation has continued to grow in PJM, pointing to the RTO’s Reliability Resource Initiative, which is expediting the interconnection studies for 51 projects. (See PJM Selects 51 Projects for Expedited Interconnection Studies.)

The order states Eddystone is needed for both near- and long-term emergency conditions, the latter of which would be hard to address if the units were allowed to deactivate.

“Practical issues, such as employment, contracts and permits, may greatly increase the timeline for resumption of operations during the period they are needed,” DOE wrote. “If Constellation Energy were to begin disassembling the units or other related facilities, the associated challenges would be greatly exacerbated. Thus, continued operation is required in such cases so long as the secretary determines that an emergency exists.”