Large Load Customer Service combines seasonal electricity supply, bundled generation and transmission demand, and recovery riders. The forecast represents constant, firm imports equal to contract capacity.
Service overview
| Item | Coverage |
|---|---|
| Service | Missouri · MISO · Schedule 11(M), Standard transmission service. |
| Rate basis | ET-2025-0184 compliance rates effective January 4, 2026; sheets 61.5–61.9. Ameren Missouri filed general rate case ER-2026-0291 on June 26, 2026; new rates can take effect from June 1, 2027. The forecast does not reflect that case. |
| Supply | Bundled utility service, forecast using seasonal energy prices and a class-cost demand forecast. |
Charge breakdown
| Line item / what it pays for | Tariff Charge Type | How the Charge Is Assessed | Calculation basis |
|---|---|---|---|
| Electricity supply | Supply | Energy | Imported MWh multiplied by seasonal energy rate. |
| Generation and transmission demand | Supply | Capacity (demand-based) | Monthly peak imported MW multiplied by seasonal demand rate. |
| Fuel adjustment | Rider | Energy | Imported MWh multiplied by fuel-adjustment rate. |
| Securitized cost recovery | Rider | Energy | Imported MWh multiplied by annual recovery rate. |
| Customer service | Distribution | Fixed | Monthly customer amount. |
| Low-income support | Rider | Fixed | Monthly support amount. |
How charges are calculated
Energy
The energy rate is 90% of the annual seasonal average day-ahead price, before the renewable rider. Summer covers June–September; the remaining months form the other season. A full season’s prices determine the rate, even for a shorter forecast period.
Energy cost is calculated by multiplying imported MWh by 90% of the seasonal average price in $/MWh and applying the 1.033 multiplier.
Demand and recovery riders
Monthly peak imports are multiplied by a seasonal demand rate that includes generation and transmission costs. Fuel adjustment and securitization are separate per-MWh charges. Customer service and low-income support are fixed monthly charges.
Renewable rider assumption
A 3.3% renewable rider is applied once to each of the six included charges. This is a forecast assumption; the filed 2026 rider uses a per-kWh rate.
Forecast methodology
| Charge | How its rate changes |
|---|---|
| Energy | 90% of each year’s seasonal average day-ahead price. One forecast rate applies within each season. |
| Demand | Seasonal filed rates are increased for allocated MISO transmission additions and for generation additions from the 2023 Integrated Resource Plan as revised by the February 2025 preferred-plan change, net of amounts already in base rates or recovered through fuel adjustment. Class demand and revenue grow with the LRZ5 peak-load index and planning price index. The 2026 Integrated Resource Plan filed in September 2026 is not yet reflected in the published cost inputs. |
| Fuel adjustment | A base fuel rate plus the allocated share of eligible transmission costs, with customer sharing and load growth. |
| Securitization | Uses the supplied annual recovery schedule in real 2025 dollars. |
| Customer and low-income support | Assumed 4.3% annual nominal growth from 2026, followed by inflation conversion. |
| Renewable rider | 3.3% applied to all six charges throughout the forecast. |
Assumptions and limitations
| Assumption | Effect on results |
|---|---|
| Demand rule | Monthly maximum imports approximate the Standard tariff only for constant imports at contract capacity. Variable loads require the on/off-peak rule, 80% contract floor, and alternate-rate eligibility. |
| Revenue allocation | New transmission and generation cost is recovered across the rate class by an equal-percentage increase. The demand share of class revenue is held at 44.89%, from the ER-2024-0319 stipulation, assuming proportional growth in other base revenue. The ET-2025-0184 stipulation requires Ameren Missouri to propose cost-causation allocation for large load customers at the first general rate case with a customer of 75 MW or more in the test year; the equal-percentage rule applies until that case. |
| Energy efficiency | Assumes the large-customer opt-out. |
| Taxes | Taxes are excluded. Missouri state sales tax is 4.225%, with local sales tax added where applicable. A qualifying new data storage center approved under RSMo 144.810 can receive state and local sales-tax exemptions on electricity for up to fifteen years, subject to the program’s limits. Municipal gross receipts taxes are separate and may still apply under the tariff’s Tax Adjustment clause. |
| Excluded charges | Reactive-power charges below 90% lagging power factor and the Cost Stabilization Rider are excluded. The rider is zero unless a discount has been negotiated. |
| Partial months | Monthly demand and fixed charges are not prorated by day. Use complete billing months when comparing with invoices. |
Public tariffs and regulatory filings
| Source | Coverage |
|---|---|
| LLCS tariff filing | Schedule 11(M), sheets 61.5–61.9. |
| ER-2024-0319 Staff rate design testimony | Class allocators: transmission 8.28%, production 7.35%, energy 11.64%. |
| ER-2024-0319 Stipulation and Agreement | Exhibit A: class revenue by rate element; source of the 44.89% demand share. |
| ER-2026-0291 case record | Pending general rate case filed June 26, 2026. Search File No. ER-2026-0291. |
| Missouri data storage center tax exemption | Eligibility, covered utilities, exemption limits, and duration. |
Methodology version: October 2026. Results use real 2025 dollars.