In a case that sits at the intersection of regulatory policy, customer cost, and energy reliability, parties and their expert witnesses are challenging Entergy Arkansas’ (EAL) bid to approve the Jefferson Power Station (JPS). The core contention: does JPS meet the standards set by the Generating Arkansas Jobs Act of 2025 (Act 373), and has EAL adequately explored alternative resources through a competitive procurement process?

The materials shared across multiple testimonies submitted on Sept. 5 - including those from the Arkansas Attorney General’s Office, Arkansas Electric Energy Consumers, SREA, and the Arkansas Public Service Commission (APSC) General Staff - each lay out detailed, critiques and recommendations aimed at ensuring that any new generation project truly serves the public interest.

EAL estimates JPS will increase the Company’s existing non-fuel charges to a residential customer that uses 1,000 kWh by approximately $2.85/month (2.13%) for the first year the project costs are included in the proposed SIR Rider.

EAL is also requesting that 100 percent of JPS costs be allocated to their retail customers.

Three Tiered Test under Act 373

SREA Executive Director Simon Mahan argues that JPS fails the Act 373 standard of being reasonable, necessary, and in the public interest. The burden is on EAL to prove all three elements; according to Mahan’s testimony, the evidence does not meet that threshold, suggesting that the application should be pursued through normal regulatory channels rather than the expedited approval process under Act 373.

“EAL has failed to prove that this application necessitates the use of Act 373, which was developed and passed, in part, with the justification that current regulatory processes are too slow to capture new economic development opportunities or new strategic investments to attract new economic development - however, EAL has known about the retirement of White Bluff for almost a decade, and has effectively waited until the last minute to announce public plans,” Mahan writes.

Further, Mahan writes, JPS does not meet the definition of a strategic investment under Act 373, nor is it being proposed to serve a new large load customer’s economic investment like a data center. Entergy has not provided a good reason to avoid the competitive procurement process required by the APSC’s Resource Planning Guidelines (RPGs), and should not be treated with special privilege afforded under Act 373.

And if we’ve learned a thing or two from extreme winter weather events like Winter Storm Elliott, it’s that the reliability of natural gas power plants during said events can get… questionable. During Winter Storm Elliott in 2022, 44 percent of MISO South’s natural gas generation resources failed to operate as expected.

It’s Not Reasonable

Scott Norwood, testifying on behalf of the Arkansas Attorney General’s office, notes that EAL’s case for JPS relies on an incomplete IRP to justify the construction of JPS. “Due to this major error, there is no basis for concluding that JPS is the lowest reasonable cost alternative or in the public interest,” Norwood writes. “In fact, EAL’s 2024 IRP modeling demonstrates that the JPS was not the lowest reasonable cost alternative because it did not select the much lower cost generic gas-fired CCCT resource as an optimal resource in any year of the IRP study period.”

For background, White Bluff Coal Plant has been scheduled to stop operation as a coal plant by 2028 since a 2018 settlement was approved by a federal court in 2021. Since 2015, Entergy IRPs discussing this closure have often selected combustion turbine (CT) technology as opposed to combined-cycle combustion turbine (CCCT) resources to replace the coal operation at White Bluff. In recent years, assessments have relied heavily on renewable energy and battery resources that have yet to be adopted by the company, Mahan notes.

Norwood’s testimony notes that EAL’s 2021 IRP did not evaluate JPS, but instead selected a generic CCCT project as the optimal resource in 2034. In their 2024 IRP analysis, Entergy included a CCCT project as a fixed resource addition in 2030 in all scenarios. Other economic analyses of JPS are based on unreasonable assumptions regarding costs of alternatives to JPS. Additionally, EAL did not present an analysis of the alternative of converting White Bluff units to burn natural gas, which would have a far lower cost than JPS or other new plant alternatives. The cost of JPS is not reasonable nor is the project the best available resource for meeting the system’s capacity needs in 2030.

Jeffrey Bower, testifying on behalf of the APSC General Staff, shared Norwood’s concerns about the heavy-handed 2024 IRP and its use in this analysis. He writes that in general, CCCT units are more expensive to build and cheaper to operate, while CT units have lower upfront capital costs and higher operating costs. While EAL’s analysis shows JPS yields $377 million in net benefits, Bower writes that the workpapers provided by Entergy are not sufficiently detailed to fully evaluate the methodology used to achieve this number. He also notes that in all EAL’s IRPs since 2012, the cost of a CT has been lower than the cost of a generic 1x1 CCCT.

It’s Not Necessary

Mahan believes that Entergy did not demonstrate that JPS is necessary. In his testimony on behalf of SREA, he noted that EAL witness testimony highlighted a capacity need as early as Winter 2027 of more than 850MW - yet, JPS would not, under the best circumstances, be operational until the end of 2029. This means that JPS would not be able to serve the short-term needs to fill this gap.

However, when stakeholders requested information from EAL regarding plans to cover the near-term projected gap, EAL responded, “EAL is evaluating its options.” SREA’s testimony notes that “without firm capacity plans between now and the operational date of JPS, EALs load projects suggest risks of load shedding and blackouts. EAL has not demonstrated adequate planning for the 2027-2029 capacity shortfall. IRP stakeholders, including the Arkansas Attorney General’s Office, insisted on receiving more information from EAL in the IRP process. EAL eventually did provide some information, stating, "If additional capacity credits are needed in that time frame, EAL may consider meeting that need either through a request for proposals for short-term capacity products or through the MISO capacity market.”

Elizabeth Stanton, Ph.D, a witness submitting testimony on behalf of the Arkansas Electric Energy Consumers also made note of the lack of a competitive procurement process in her recommendations to the Commission. Mahan noted in his testimony that the RFP released by Entergy in April 2024 - then cancelled in August of that same year - included such narrow parameters that even the JPS facility would not have achieved the milestones set forth.

In fact, one of Mahan’s recommendations is that the Commission should require competitive procurement as a test for new generation to achieve Act 373’s goals of supporting projects that are reasonable, necessary and in the public interest. “Having a procurement plan is required by the Commission’s RPGs, and issuing an all-source RFP before acquiring new generation resources is consistent with best resource planning practices,” he writes.

Norwood also points to an RFP that was “designed to limit proposals,” and that required proposing parties to assume risk for things like unexpected cost increases that EAL is not offering to assume for the JPS project. “The lack of proposals does not demonstrate there were no viable alternatives to JPS. The lack of proposals likely reflects the reluctance of bidders to assume the risks of fixed prices, guaranteed delivery dates, and regulatory disallowances. EAL is not offering to assume such risks for the JPS project.”

It’s Not in the Public Interest

Transparency around project costs - and costs passed to the consumer - were the focus of Elizabeth Stanton, Ph.D’s testimony. Stanton testified on behalf of Arkansas Electric Energy Consumers, and noted, “with concern” EAL’s choice to file the total cost of the project as highly sensitive protected information. She writes:

“The Company’s choice to make basic information about the project, like its total cost, inaccessible to ratepayers is non-standard, unnecessarily secretive, and - quite frankly - inappropriate. I have never before seen a CECPN-type case, in any state, for which the total cost of the project was posed as confidential much less highly sensitive. Designation of confidential material should be reserved for real concerns that information, if made public, could give an edge to competitors or otherwise demonstrably damage the Company’s business. Confidentiality should never be used to shield a basic description of a project from public scrutiny. Ratepayers must be allowed to know what it is that the Company wants to add to rates and how much it will cost.”

It was hard to get a true picture of costs from these filing since most mentions of costs were redacted. But in Norwood’s testimony, he noted that EAL’s estimated cost for JPS is far higher than the cost estimates for other CT projects by other utilities serving Arkansas.

While acknowledging that interconnection benefits may exist at the White Bluff site, the testimony argues that such advantages are not unique to the JPS configuration. In other words, alternative resource setups at White Bluff or other locations could potentially yield similar interconnection cost savings, reducing the argument for a single, large combustion-turbine project at a greenfield site.

APSC Staff witness Bower noted that while reusing the interconnection rights at White Bluff would provide significant savings over entering the MISO queue, he is concerned about the transfer of White Bluff’s transmission right. He outlines three specific concerns - EAL is not the sole owner, as White Bluff is co-owned by EAL, AECC and multiple joint owners. All parties have filed for ownership shares to transfer to Entergy as sole owner by January 1, 2029; however, the fact that it’s not yet approved adds risk to the project.

Bower also raises concerns around a potential fuel conversion in the future, and the simple fact that White Bluff’s equipment may reach its end of service date before JPS does, which would also devalue reusing the interconnection at the site.

Next steps in the procedural schedule include the following filing deadlines and hearing date:

• EAL Rebuttal: September 19, 2025
• Staff/Intervenor Surrebuttal: October 3, 2025
• EAL Sur-Surrebuttal: October 10, 2025
• Settlement of Issues List: October 20, 2025
• Opposition to Settlement: October 23, 2025
• Hearing: October 30, 2025 at 9:30 a.m.