Ameren’s new resource plan connects extraordinary data-center demand to an accelerated natural-gas expansion
Änna Farrar 11.2.2026
Missouri’s data-center expansion has entered a new phase. What began as prospective industrial demand has become billions of dollars in proposed generating infrastructure, and Ameren Missouri’s latest resource plan makes the connection increasingly difficult to separate.
On September 28, Ameren filed its 2026 Integrated Resource Plan, outlining how the utility intends to meet electricity demand over the next twenty years. Among its planned investments are approximately 6,800 megawatts of new natural-gas generation by 2035.
At the center of that expansion is the proposed West Alton Energy Center, a 2,100-megawatt combined-cycle natural-gas facility planned for the existing Sioux Energy Center site in St. Charles County.
The Missouri Public Service Commission is now considering whether to authorize its construction.
But the significance of West Alton extends beyond another generating facility. Ameren’s own testimony establishes that extraordinary industrial load growth helped accelerate the company’s generation schedule, while its September resource plan reveals just how substantially those demand expectations have changed.
The question is no longer whether data centers are influencing Missouri’s energy future. The question is whether the costs and risks of building that future will follow the customers creating the additional demand.
An entirely different kind of growth
Ameren’s latest resource plan identifies data-center development as the primary driver of its anticipated increase in electricity demand.
The distinction between its traditional customers and its new industrial customers is considerable.
According to Chapter 3, page 1, of the IRP, Ameren forecasts electricity consumption among customers outside its large-load tariff class to increase approximately 1.2% annually over the next twenty years. For the large-load class, the company’s base forecast anticipates approximately 20% annual growth.
Those percentages begin from vastly different levels of consumption and should not be confused with a comparison of total demand. But they establish the disparity driving the company’s planning decisions.
Electricity consumption among Ameren’s traditional customers is not growing at anything approaching the rate anticipated from new industrial development.
And the generating portfolio is changing accordingly.
In February 2025, Ameren revised its preferred resource plan after receiving construction agreements representing more than two gigawatts of prospective large-load demand. The company also cited changes in expected energy-efficiency savings as part of the decision.
At that point, those construction agreements were not the same as executed electric service agreements. But the anticipated demand was already substantial enough to influence the timing of future generation.
Then, between February and May 2026, Ameren executed Electric Service Agreements, or ESAs, representing approximately 2.8 gigawatts of expected new demand.
For perspective, its previous preferred resource plan anticipated approximately 1.5 gigawatts of large-load demand by 2032.
By the time Ameren filed its September 2026 plan, it had signed agreements for substantially more demand than previously forecast, with that demand expected to arrive sooner.
The comparison appears on page 1 of Ameren’s September IRP executive summary.
An executed ESA is a more developed commitment than a transmission-study request or an expression of interest. It does not necessarily guarantee that every projected megawatt will be consumed on schedule, but it provides a stronger basis for utility planning.
The distinction matters because the decisions prompted by those forecasts are increasingly expensive and difficult to reverse.
A projected customer can delay construction. An electric service agreement may contain financial protections. But a power plant, once authorized and under construction, introduces long-lived financial obligations.
And Ameren is planning considerably more generation than it was just a few years ago.
The gas expansion is already taking shape
Under its September 2026 preferred resource plan, Ameren anticipates adding 1,900 megawatts of simple-cycle natural-gas generation by 2029, followed by 2,100 megawatts of combined-cycle generation at West Alton in 2031.
Another 2,800 megawatts of combined-cycle generation is planned by 2035, with further additions contemplated beyond that date. These additions are laid out in Chapter 10, page 19, of the 2026 IRP.
The resources serve different functions. Simple-cycle turbines can help address peak demand and resource adequacy, while combined-cycle facilities are generally designed for more efficient, sustained generation.
They are also not all attributable exclusively to data centers. Ameren must account for the retirement of aging generating facilities, existing customer needs, and applicable reliability requirements. Still, the utility’s July 2026 testimony establishes that growing industrial demand is accelerating investments that had previously been scheduled for later years.
West Alton demonstrates that change particularly well.
Ameren’s earlier planning anticipated approximately 1,200 megawatts of combined-cycle generation associated with replacing retiring capacity.
The West Alton proposal is now 2,100 megawatts, with three approximately 700-megawatt generating units expected to enter service during 2031.
That represents 900 megawatts of additional near-term combined-cycle capacity compared with the earlier plan.
The increase cannot simply be assigned in its entirety to data centers without a more detailed comparison of resource requirements. Ameren identifies other changes affecting its forecasts. But the company has documented that extraordinary load growth influenced the acceleration.
And that distinction raises the question the Commission should be examining:
What would Ameren need to build, and when would it need to build it, if the new industrial demand were removed from the forecast?
Not whether Sioux needs replacement. Not whether Missouri needs reliable electricity.
How much of the expanded portfolio is necessary to serve customers who were already here, and how much is necessary because the utility has committed to supplying extraordinary new demand?
Those are different questions with potentially different financial consequences.
The part of the plan that doesn’t tell us what residential customers will pay
Ameren has already modeled scenarios without additional large-load growth, as well as scenarios where anticipated demand develops more slowly or declines.
In Chapter 9 of its 2026 IRP, the company concludes that higher large-load demand increases total revenue requirements but can reduce average modeled electricity rates.
In principle, that makes sense. Additional electricity sales may allow certain fixed utility costs to be spread across more kilowatt-hours.
But the company includes an important qualification. On page 29 of Chapter 9, Ameren acknowledges that its analysis does not account for how costs are allocated between large-load customers and other customer classes, or for the safeguards contained in its approved large-load tariff.
That limitation is crucial.
A lower average modeled electricity rate is not the same as a lower residential electricity bill.
To establish the effect on residential customers, the Commission must examine the actual costs of serving the new load alongside the revenues collected from those customers and the rules determining how shared expenses are assigned.
That includes the construction and financing of generating facilities, fuel and purchased-power expenses, capacity requirements, and the possibility that anticipated customers will consume less electricity than originally projected.
The Law Changed. The Question of Who Pays Remains.
In 1976, Missouri voters adopted Proposition 1, establishing a restriction on electric utilities charging customers for generating facilities before those facilities were operational.
For nearly fifty years, that principle remained embedded in Section 393.135 of Missouri law.
Then came Senate Bill 4.
Signed into law in April 2025, SB 4 changed more than Missouri’s approach to large industrial electricity customers. It also established new mechanisms affecting how utilities finance generating facilities, recover investment costs, and plan future infrastructure.
Among those changes was an exception to the voter-established prohibition on recovering construction costs before a power plant begins operating.
Under the amended Section 393.135, qualifying new natural-gas generating units can have Construction Work in Progress, or CWIP, included in utility rate base before the facilities produce electricity.
The Commission must approve the eligible amount, and the law establishes limits and refund provisions for certain imprudent expenditures or projects that fail to enter service within a reasonable period.
But the fundamental change remains: Missouri law now permits certain construction investments to affect customer rates before the generating facilities are operational.
And Ameren is already seeking to use that authority.
In its July 24 application for the 2,100-megawatt West Alton Energy Center, Ameren specifically requests a determination of the amount of construction spending eligible for inclusion in rate base.
The utility argues that earlier recovery can reduce long-term financing expenses. That is one part of the financial calculation.
The other is who ultimately pays.
The changes extend beyond construction financing
SB 4 also modified Missouri’s Plant-in-Service Accounting framework under Section 393.1400, commonly called PISA.
Unlike CWIP, which concerns qualifying expenditures before a generating facility is operational, PISA addresses the deferral of certain depreciation and return expenses associated with qualifying investments after they enter service, for recovery through future rates.
The legislation expanded eligibility to include certain new natural-gas generating units, subject to statutory restrictions. These are separate financial mechanisms, and their treatment must be evaluated under their respective requirements. But both affect when costs are recognized and recovered.
Their significance increases when considered alongside Ameren’s rapidly expanding generation portfolio. The utility is planning thousands of megawatts of new natural-gas generation while incorporating extraordinary industrial electricity demand into its forecasts. Some of that infrastructure replaces aging facilities. Some is being accelerated to accommodate expected growth.
Those facts are relevant because the law has also changed how eligible investments can be recovered.
Missouri is not simply authorizing additional generating capacity. It has changed the financial framework under which that capacity may be constructed and paid for.
PSC Staff had already identified the accounting problem
During Ameren’s large-load tariff proceeding, ET-2025-0184, Missouri Public Service Commission Staff raised concerns that go directly to the question of whether existing customers will actually receive the financial benefits promised by industrial expansion.
In its September 5, 2025 rebuttal report, pages 14–20, Staff examined how revenues from new large-load customers interact with costs already being recovered through existing electric rates.
The concern was straightforward.
Existing residential and commercial customers are already paying rates established to recover Ameren’s authorized generation costs. When major new industrial customers begin paying for electricity, those additional revenues do not necessarily produce an immediate reduction in existing customers’ rates. Until the new revenues are reflected in a subsequent rate case or another authorized accounting mechanism, the utility may retain additional earnings through what regulators call positive regulatory lag.
Meanwhile, certain additional costs associated with serving those customers may flow through mechanisms such as the Fuel Adjustment Clause. That means the timing of cost recovery and revenue recognition can matter just as much as the rates specified in an industrial customer’s electric service agreement.
Staff did more than identify the possibility. Its rebuttal included an illustrative thirty-five-year scenario examining the financial consequences of adding a large-load customer and constructing new generating capacity. Under that hypothetical, approximately $2.6 billion in large-load revenue produced only $97 million in offsets to the existing cost of service because of the regulatory-lag assumptions used.
Those figures were an illustration of a potential accounting problem, not a finding that Ameren has actually retained those amounts or that West Alton will produce the same result. Nevertheless, they demonstrate why the mere existence of new industrial revenue cannot be treated as proof that other customers will benefit.
The Commission subsequently approved a negotiated large-load rate plan in November 2025, establishing a conditional revenue-sharing mechanism intended to return a portion of qualifying excess earnings to customers. While the agreement addressed part of Staff’s concerns, it did not establish whether those provisions would adequately offset the long-term costs of new generation investments such as West Alton.
West Alton brings those questions directly before regulators
Ameren’s pending West Alton application, EA-2026-0226, identifies the company’s executed large-load agreements among the reasons additional generating capacity is needed. The company is requesting permission to construct the facility and a determination of the amount of construction investment potentially eligible for CWIP treatment.
At the same time, Ameren states that the allocation of West Alton project costs for ratemaking purposes will be determined in future proceedings.
That sequence deserves scrutiny.
The Commission is being asked to evaluate the necessity, scale, economic feasibility, and construction-financing treatment of a substantial generating investment before its final customer-class cost allocation has been established.
This does not mean the Commission has already approved improper cost recovery. Nor does it mean every megawatt of West Alton is attributable solely to data-center demand. It means the relationship between replacement generation and industrial-load-driven expansion must be examined carefully. The utility’s obligation to provide reliable electricity is not in question.
What deserves examination is how much of the proposed investment would have been necessary without the extraordinary industrial demand, how much has been accelerated because of that demand, and what happens financially if the forecasts supporting the investment fail to materialize.
Those questions have become more consequential because Missouri has simultaneously altered the rules governing construction financing and the recovery of generating investments. The Commission has an opportunity to evaluate the evidence before authorizing another long-lived asset.
Future rate cases may determine how eligible costs are divided among customer classes, but the decision to build—and the financial commitments that follow—begins much earlier.
The public deserves to understand the cost of that decision before it becomes an obligation reflected in electric rates.
Reliability is the obligation. Cost responsibility is the question.
Ameren has an obligation to provide reliable electric service. There is no serious dispute about that responsibility. What matters is how the utility defines the resources necessary to fulfill it as new industrial customers enter the system.
The addition of several gigawatts of demand can increase capacity requirements, alter the need for purchased power, and accelerate construction that might otherwise have occurred years later. Those investments may be necessary to maintain reliability after the new demand is added. But that does not automatically make every resulting expense an independent benefit to existing customers.
It also introduces a timing problem.
Ameren anticipates substantial large-load growth before West Alton begins operating in 2031. In Matt Michels’ direct testimony, pages 10–11, Ameren explains that it intends to use interim capacity arrangements, existing resources, and planned additions to serve growing demand before its larger generating projects enter service.
The utility must therefore demonstrate how it intends to meet its service obligations during the intervening years, including through available generating resources, purchased capacity, and other reliability measures.
That assessment should account for the possibility of industrial demand arriving earlier or later than expected.
The Commission must distinguish what is needed to maintain existing service from what is required to accommodate additional industrial customers, while examining how the financial consequences of those decisions are assigned.
That is not opposition to electricity generation.
It is a basic requirement of responsible resource planning and utility regulation.
November 18: The public has an opportunity to question West Alton
Ameren’s request to construct the West Alton Energy Center is pending before the Missouri Public Service Commission under Case No. EA-2026-0226.
The Commission is considering construction authorization, a determination concerning eligible construction-work-in-progress costs, a reliable-replacement finding, and an operational-planning variance.
A final construction decision has not yet been issued.
The public hearings scheduled for November provide an opportunity for residents to question the assumptions supporting the project and place their concerns before regulators.
Although proposed data-center developments in Warren and Montgomery counties illustrate the extraordinary industrial demand reshaping Ameren’s resource plans, the implications of West Alton extend across the utility’s entire Missouri service territory.
West Alton is not being proposed to serve a single development or county. If authorized, it would become part of Ameren Missouri’s generating system, with construction and operating costs subject to regulatory decisions affecting customers throughout that system.
While new electricity demand may be concentrated in a relatively small number of industrial developments, the financial obligations associated with expanding the generation fleet are not necessarily confined to those customers or their communities.
For every Ameren Missouri customer, regardless of proximity to a proposed data center, the West Alton proceeding raises the same fundamental question: whether the investments being undertaken to accommodate extraordinary industrial growth will be necessary, appropriately justified, and fairly allocated.
In-person public hearing — Wednesday, November 18, 2026
6:00 p.m. CST
St. Charles Community College
4601 Mid Rivers Mall Drive
Cottleville, Missouri
Virtual public hearing — Thursday, November 19, 2026
6:00 p.m. CST
Webex access code: 2861 099 9154
Password: 0226
Telephone: 1-855-718-6621
The hearings include a public information and question-and-answer session followed by public testimony.
Advance registration is encouraged but not mandatory. To register, contact the PSC at pscinfo@psc.mo.gov or 1-800-392-4211 by 5:00 p.m. Central the day before the selected hearing.
Official PSC announcement and full participation instructions
Attending versus intervening
The original deadline to apply for formal intervention was August 17, 2026.
That deadline has passed, but Missouri PSC Rule 20 CSR 4240-2.075(10) allows late intervention upon a showing of good cause and subject to Commission approval.
Formal intervention provides procedural rights and obligations that public testimony does not. Residents do not need to intervene to attend either hearing, offer testimony, or submit written comments.
For those following the full regulatory process, rebuttal testimony is currently scheduled for January 22, 2027, followed by surrebuttal on March 5 and evidentiary hearings April 19–23.
The complete schedule is available through the PSC’s official procedural calendar.
Submit written public comments to the Commission — reference EA-2026-0226.
Before the contracts become permanent costs
Ameren has already signed electric service agreements representing approximately 2.8 gigawatts of expected large-load demand. Its September 2026 IRP identifies industrial growth as a major force reshaping the utility’s generation portfolio. And West Alton is now moving through the process that could turn part of that expanded portfolio into an authorized construction project.
The utility has a responsibility to replace aging generation and reliably serve its customers. It also has a responsibility to justify additional investments and demonstrate that their costs can be recovered fairly. Those responsibilities should not be separated simply because they are examined in different regulatory proceedings.
The public deserves to understand which investments would have been necessary without the new industrial demand, which have been accelerated to accommodate it, and how Missouri intends to protect customers from financial obligations that should properly be borne elsewhere.
The contracts are already signed. The generation plans have changed. The next question is what the Commission will require before those plans become long-term financial commitments.
On November 18, Missourians have an opportunity to ask.
Regulatory note: Ameren’s forecasts and financial models are utility evidence, not independent Commission findings. The September IRP does not authorize construction, and West Alton’s customer-class cost allocation remains unresolved.
