Ameren supplies electricity and natural gas in Missouri and Illinois and earns regulated fees for moving electricity across the regional grid. In the first nine months of 2026, profit attributable to common shareholders rose to $1.35 billion, but construction spending exceeded cash from operations by $1.90 billion. Its third-quarter filing shows why: earlier investments are lifting customer rates and earnings, while a larger building program requires financing before new large customers begin taking power.
Analysis covers the quarter and nine months ended September 30, 2026. Research cutoff: November 8, 2026, New York time; the latest dated company document used is the November 6 filing.
Source: Ameren’s third-quarter 2026 Form 10-Q, consolidated statements, pp. 4–7, and management’s discussion, pp. 46–47 and 65–69.
1. Higher customer rates are doing more than broad growth in electricity use
Ameren’s utility earnings improved mainly as earlier infrastructure investment entered customer rates. Missouri customers pay for electricity production and delivery. Illinois customers principally pay Ameren for delivery, with purchased electricity and gas costs largely passed through to them. Regulators determine what costs the businesses can recover and the profit they can earn on approved investment.
That structure makes sales revenue an imperfect measure of progress. Ameren can collect more money simply because purchased energy costs more, without keeping a larger profit. Conversely, lower energy costs can reduce both revenue and expense while leaving the business little changed.
| Consolidated results, USD millions except EPS and margins | Third quarter 2025 | Third quarter 2026 | First nine months 2025 | First nine months 2026 |
|---|---|---|---|---|
| Revenue | 2,699 | 2,882 | 7,017 | 7,150 |
| Operating profit | 825 | 900 | 1,666 | 1,891 |
| Operating margin, calculated | 30.6% | 31.2% | 23.7% | 26.4% |
| Profit attributable to common shareholders | 640 | 676 | 1,204 | 1,347 |
| Common-shareholder profit margin, calculated | 23.7% | 23.5% | 17.2% | 18.8% |
| Diluted earnings per share, USD | 2.35 | 2.42 | 4.43 | 4.83 |
Source: 2026 Form 10-Q, consolidated income statement, p. 4. Each margin is the corresponding profit divided by revenue; quarter and cumulative results are separate comparisons.
Nine-month revenue rose 1.9%, while operating profit rose 13.5%. Higher electric base rates contributed an estimated $248 million to revenue across the segments, and higher natural gas base rates contributed another $74 million. Missouri’s electric rate increase began in June 2025, so the 2026 comparison includes five additional months at those rates. New Missouri and Illinois gas rates also contributed.
The largest revenue movement had a very different meaning. Missouri’s revenue category covering sales outside its retail system, capacity and fuel adjustments fell $515 million over the nine months. The corresponding energy-cost category fell $514 million. Lower regional capacity prices—payments for having power available when needed—largely drove both changes. The near-offset explains why Missouri could report lower electric revenue while earning more profit. It also means the wider consolidated operating margin should not be read entirely as better operating efficiency.
Source: 2026 Form 10-Q, revenue changes and explanations, pp. 54–55, and fuel and purchased power, pp. 56–57.
Actual electricity use presents a more modest picture. Missouri retail electricity sales increased 3.9% in the quarter but only 0.9% over the first nine months. Warmer summer weather helped the quarter. Management also estimated that growth in commercial and residential sales, after allowing for weather and energy-efficiency programs, added $29 million to nine-month revenue.
Illinois electricity deliveries fell 2.2% over the nine months. Its distribution earnings still rose because a regulatory adjustment separates authorized delivery revenue from the amount of electricity customers use. Ameren’s current earnings improvement therefore rests more on approved infrastructure investment and rates than on a broad surge in customer consumption.
Sources: Ameren’s November 5, 2026 earnings release, electric sales statistics; 2026 Form 10-Q, pp. 55 and 74. Volume calculations use Missouri retail sales of 9,328 versus 8,982 million kilowatt-hours for the quarter and 24,618 versus 24,400 million for nine months; Illinois deliveries were 25,059 versus 25,632 million for nine months.
2. The profit increase is real, but some earnings arrive before cash
The utility businesses improved, while construction accounting and investment gains also helped reported profit. Missouri supplied most of the nine-month increase. Illinois distribution and natural gas added earnings, and the loss outside the operating segments narrowed.
| Profit attributable to Ameren common shareholders, USD millions | First nine months 2025 | First nine months 2026 | Change |
|---|---|---|---|
| Ameren Missouri | 710 | 815 | 105 |
| Illinois electric distribution | 184 | 208 | 24 |
| Illinois natural gas | 105 | 124 | 19 |
| Ameren Transmission | 326 | 304 | -22 |
| Other activities and intersegment eliminations | -121 | -104 | 17 |
| Consolidated total | 1,204 | 1,347 | 143 |
Source: 2026 Form 10-Q, segment reconciliation, p. 51. These are the filing’s contributions to consolidated common-shareholder profit, including its ownership adjustments and eliminations. Transfers between group companies are removed to avoid counting the same activity twice. Ameren Transmission includes Illinois transmission and Ameren Transmission Company of Illinois, or ATXI.
Transmission’s reported decline mainly reflects a favorable tax item in the comparison period. In the third quarter of 2025, a change in the treatment of deferred taxes reduced Ameren’s tax expense by $48 million. Removing that benefit from the 2025 comparison raises calculated nine-month common-profit growth from 11.9% to 16.5%. Transmission profit then compares with $278 million rather than $326 million. The missing tax benefit also helps explain why quarterly common-profit growth of 5.6% lagged operating-profit growth of 9.1%. The complete reported-to-adjusted bridge appears in the calculation notes.
This adjustment makes the utility improvement clearer, but it does not turn every remaining dollar into recurring customer earnings. Ameren earned $48 million before tax from investments accounted for through its share of their results, compared with a $19 million loss a year earlier. That $67 million swing included the absence of a prior-year impairment as well as stronger results from investments associated with energy technology. Such gains can vary independently of household utility bills.
Ameren also recognized $104 million of income for the use of shareholder funds during construction, up from $60 million. This accounting allowance adds a financing return to the cost of qualifying projects while they are being built. It raises current profit, although customers have not yet paid that amount in cash. The cash-flow statement therefore removes it when calculating operating cash flow.
Together, those two categories improved pretax results by $111 million. They are separate from the $225 million increase in operating profit. Other offsets included lower pension-related income and higher interest expense. Utility operations are earning more, but part of the added profit still depends on future customer collections or cash returns from investments.
Source: 2026 Form 10-Q, Note 5, p. 24; Note 12, p. 35; cash-flow statement, p. 6; and discussion of other income and interest, pp. 63–64. November 5 earnings release, adjusted-earnings reconciliation. The $48 million 2025 tax benefit is already an after-tax amount.
3. More construction and slower cash receipts widened the funding gap
Operating cash covered just over half of cash capital spending in the first nine months. This is a larger funding requirement than in either of the previous two comparable periods.
| Consolidated cash allocation, USD millions | First nine months 2024 | First nine months 2025 | First nine months 2026 |
|---|---|---|---|
| Cash from operations | 1,946 | 2,397 | 2,193 |
| Capital expenditures, shown as a positive use of cash | 3,029 | 3,118 | 4,089 |
| Cash after capital expenditures, calculated | -1,083 | -721 | -1,896 |
| Common dividends paid, shown as a positive use of cash | 535 | 576 | 622 |
| Cash after capital expenditures and common dividends, calculated | -1,618 | -1,297 | -2,518 |
Sources: 2024 third-quarter Form 10-Q, consolidated cash-flow statement, p. 6; 2026 Form 10-Q, p. 6. The operating-cash and capital-spending figures for 2024 also match the SEC’s Ameren company facts. This table uses the cash-flow statement’s capital-expenditure line; separate nuclear fuel spending and other investing flows are addressed below.
Cash capital spending rose 31.1%. The principal reasons were Missouri’s acquisition of the Split Rail solar project and spending on other generation projects, alongside Illinois electric distribution upgrades. Lower major-storm spending in Missouri and changes in the timing of Illinois gas work partly offset the increase. Management identifies these uses; the difference between spending and depreciation does not identify how much was maintenance or expansion.
Operating cash moved the other way, falling $204 million, or 8.5%. One large explanation was $223 million less cash received from selling production and investment tax credits to unrelated parties. Another was a $91 million unfavorable timing change in Illinois payments and reimbursements for customer-owned generation programs. Ameren had to make those payments before recovering the same amounts.
Management still expects approximately $2.9 billion of tax-credit transfers during 2026–2031. These receipts can help fund the business, but the benefits ultimately flow back to customers through rate mechanisms. They support cash timing rather than a permanent increase in profit margins.
Higher customer collections provided a $203 million offset, principally from rate increases, after allowing for lower collections under other cost-recovery mechanisms. Higher interest payments, plant maintenance and pension contributions also used cash. These movements explain how profit could rise while cash from operations fell: customer collections improved, but other receipts and payments moved against the company.
Source: 2026 Form 10-Q, operating cash explanations, pp. 66–68, investing activities, p. 68, and tax-credit funding outlook, p. 77. The listed explanations are major contributors, not a complete additive bridge; the statement-based reconciliation is in the calculation notes.
Using operating cash less the reported capital-expenditure line, calculated free cash flow was negative $1.896 billion. Including the separately reported $26 million of nuclear fuel purchases makes the shortfall $1.922 billion before dividends. After common dividends, the same broader shortfall was $2.544 billion. Nuclear trust transactions and other investing uses required additional funding.
The company met these needs mainly through borrowing. It received $3.234 billion from long-term debt issuance, paid $378 million for maturities and debt extinguishments, and reduced short-term debt by $147 million. Share issuance brought in only $31 million of cash during the nine months. Ameren’s expansion was therefore financed predominantly with debt during this period, even though its longer-term plan also includes substantial new equity.
Source: 2026 Form 10-Q, consolidated cash-flow statement, p. 6, and financing discussion, pp. 69–71.
4. The growing asset base carries future collection obligations
Most of Ameren’s asset growth is physical infrastructure, but more money is also awaiting collection or regulatory recovery. Net property, plant and equipment increased $2.926 billion from year-end. “Net” means after accumulated depreciation, the expense that spreads equipment costs over its useful life. That is consistent with the accelerated building program and the addition of Split Rail. The balance reflects depreciation and other accounting changes as well as spending.
| Consolidated financial position, USD millions | December 31, 2025 | September 30, 2026 |
|---|---|---|
| Net property, plant and equipment | 39,313 | 42,239 |
| Customer, unbilled and miscellaneous receivables combined | 1,187 | 1,602 |
| Inventories | 774 | 873 |
| Regulatory assets, current and noncurrent combined | 2,911 | 3,239 |
| Cash and cash equivalents available on the balance sheet | 13 | 40 |
| Total assets | 48,476 | 52,767 |
| Financing debt, including current maturities and short-term debt | 19,830 | 22,513 |
| Total equity, including noncontrolling interests | 13,530 | 14,336 |
Source: 2026 Form 10-Q, consolidated balance sheet, p. 5. Combined receivables, regulatory assets and financing debt are calculated from the stated balance-sheet lines. Debt uses reported carrying amounts, not face values.
Receivables rose $415 million from December. These include bills awaiting payment, energy already supplied but not yet billed, and miscellaneous amounts owed to Ameren. The cash-flow statement records a $411 million use of cash from receivables, after its accounting adjustments. The comparison is seasonal: a September balance follows summer electricity demand, while December is a different point in the billing cycle. It does not by itself establish deteriorating collection quality.
There is, however, a measurable increase in credit costs. Nine-month bad-debt expense rose from $37 million to $42 million, and net write-offs rose from $34 million to $40 million. The allowance for unpaid accounts increased from $39 million at year-end to $47 million. Illinois has mechanisms to recover qualifying write-offs from customers, limiting the lasting earnings effect while leaving collection timing relevant.
Inventory increased $99 million. Disclosed cash uses included more materials and supplies for Illinois networks and fuel oil to fill new storage tanks at Missouri’s Audrain plant as it adds the ability to run on either gas or fuel oil. These are operating supplies and fuel for the system; the filing does not allocate the entire inventory increase to those two uses.
Source: 2026 Form 10-Q, Note 13, p. 36, and operating cash discussion, pp. 66–68.
Regulatory assets are amounts Ameren expects to recover through future customer rates. Their $328 million increase means more recovery is carried into later periods. The company’s mechanisms cover such items as qualifying infrastructure costs, energy-efficiency programs and customer-generation rebates. Each mechanism has its own approval and collection rules; an accounting asset is not cash in the bank.
The other side includes obligations to pass benefits back to customers. Noncurrent regulatory liabilities rose from $6.255 billion to $6.606 billion, and deferred income taxes and tax credits rose from $5.181 billion to $5.646 billion. These differ from bank and bond debt: they largely reflect future rate adjustments and tax timing. Similarly, the $1.638 billion nuclear decommissioning trust is reserved for closing the Callaway plant. Changes in its investment value are offset through a regulatory liability, rather than treated as freely available corporate profit.
Goodwill, which records part of the price paid for earlier business acquisitions, remained $411 million. The expansion is therefore visible chiefly in utility assets and related recovery balances, rather than in a larger goodwill balance from buying businesses. The financial challenge is converting the new assets into approved collections soon enough to support their financing.
Sources: 2026 Form 10-Q, balance sheet, p. 5; Notes 10 and 13, pp. 33 and 36; 2025 Form 10-K, Note 1, regulatory accounting and recovery mechanisms.
5. The expansion needs both borrowing and new shares
Ameren had borrowing capacity at September 30, while its construction program still depended on continued access to lenders and new shareholders. Its $40 million cash balance is small beside the building program. Current liabilities exceeded current assets by a calculated $1.074 billion. The larger source of immediate flexibility was $2.670 billion of unused capacity under committed credit agreements, after commercial paper and letters of credit. Together they provided $2.710 billion of reported available liquidity.
Those credit agreements run to December 2030, although utility-subsidiary drawings have a 364-day repayment term. Ameren reported compliance with the financial conditions in its lending agreements. Its debt-to-capital measure under the agreements was 61%, against a 67.5% limit; the Missouri and Illinois subsidiaries were at 49% and 46%, against separate 65% limits. These are the agreements’ defined measures, not ratios reconstructed from the simplified balance-sheet table.
Source: 2026 Form 10-Q, Note 3, pp. 20–21, and liquidity table, p. 70; 2025 Form 10-K, Note 4, covenant terms, p. 116.
Current maturities of long-term debt increased from $973 million to $1.574 billion. Including short-term debt of $643 million and $496 million, respectively, total debt due within a year increased from $1.616 billion to $2.070 billion. The maturity schedule includes $600 million of parent-company notes due in 2026, followed in 2027 by $500 million of parent notes and $400 million of Missouri notes, along with smaller obligations. These amounts compete with construction for financing capacity. The 2027 parent notes carry an annual interest rate of 1.95%, well below the 5.00% rate on new parent notes issued in March 2026, illustrating the potential cost of replacing older borrowing.
Interest expense already rose from $570 million to $629 million over the nine months. Short-term borrowing became cheaper on average, but more long-term debt and higher rates on that debt outweighed the benefit. The September issuance of $900 million of junior subordinated notes is another long-term funding source. It initially costs 6.45% annually, or a calculated $58.05 million a year before issuance-cost adjustments. After March 2032, its rate resets every five years and cannot fall below 6.45%. It remains debt in the consolidated accounts.
Sources: 2025 Form 10-K, Note 5, debt terms and maturity schedule, pp. 117–120; 2026 Form 10-Q, Note 4, pp. 21–23, and interest discussion, p. 64. The older maturity schedule is used with the 2026 issuance and repayment disclosures; it is not presented as an unchanged September schedule.
Equity is the other major funding source planned. At September 30, Ameren had forward sale agreements covering 19.4 million shares. Physical settlement at that date would have provided approximately $2 billion. This was potential settlement cash, not money Ameren had already received. The other parties’ sales of borrowed shares do not provide proceeds to Ameren until Ameren settles the agreements.
October agreements added 2.1 million shares. Ameren expected to settle 6.4 million shares in 2026 and the remaining 15.1 million later. Its approximately $5 billion equity-financing plan for 2027–2031 includes forward agreements, dividend reinvestment and employee plans. Forward settlements scheduled after 2026 form part of that plan; they are not additional funding to count again.
The trade-off is already visible in per-share results. Nine-month diluted average shares increased from 271.7 million to 278.7 million. Common profit rose 11.9%, while diluted EPS rose 9.0%. Much of the year-over-year share increase follows issuance in late 2025; only 0.5 million net new outstanding shares were added during the first nine months of 2026. Cash dividends of $622 million also absorbed funds that could otherwise have supported construction. New shares help finance a larger utility system, but that system’s earnings must be shared across more shares.
Sources: 2026 Form 10-Q, pp. 4–7, Note 4, pp. 21–22, and funding plan, pp. 65–66 and 77; 2025 Form 10-K, liquidity discussion, p. 58. The 2025 filing reports 5.8 million shares issued through the market-sale program during that year. Equity movements and the absence of a separate treasury-stock balance are reconciled in the notes below.
6. Signed power contracts support expansion, with a gap before full service
Ameren has firmer evidence of future demand, but the associated revenue and power supply arrive on different schedules. Missouri’s signed electric service agreements represent 2.8 gigawatts of demand, up from 2.2 gigawatts disclosed in February. Management expects demand under those contracts to begin arriving in the second half of 2027 and reach full capacity in 2030. It does not expect a material financial contribution from them in 2026.
Developers have also signed construction agreements representing another 1.2 gigawatts. That demand is not yet secured by electric service agreements. Keeping those categories separate matters: construction arrangements demonstrate development activity, but do not establish the same commitment to buy utility service.
Sources: 2026 Form 10-Q, pp. 47 and 75; 2025 Form 10-K, filed February 18, 2026, large-load customer discussion, pp. 31–32 and Note 2.
The approved large-customer tariff provides a minimum 12-year service term, with up to five additional years to reach contracted demand. Minimum demand charges are based on 80% of contracted capacity, and the framework includes credit support and exit fees. Missouri’s regulator describes collateral equal to two years of minimum monthly bills. These terms help protect the utility and other customers if a major customer uses less power than planned or leaves early.
The framework also shares unusually high earnings with customers. Under the approved arrangement, Missouri would defer 65% of the return above a 9.74% earned return on equity for later customer benefit; the regulator can change the threshold in future rate orders. Thus, stronger demand can support more infrastructure and spread system costs, while the tariff limits how much excess return Ameren retains.
Sources: 2025 Form 10-K, large-load tariff and earnings-sharing provisions, management’s discussion and Note 2; Missouri Public Service Commission’s explanation of large-load tariffs, minimum terms, financial security and termination protections. The regulator page is undated; the tariff’s November 2025 approval is independently established by the annual filing.
Management’s purpose for the larger building program is to serve this demand while maintaining reliability. The filing estimates $5.945 billion of investment for 2026 and $36.200 billion to $40.040 billion for 2027–2031. These estimates include construction financing allowances, so they are broader than the historical cash-capex measure used earlier. Missouri accounts for most of the planned spending, including generation, batteries and grid upgrades.
| Selected Missouri projects | Capacity, megawatts | Service timing stated in the filing | Approval or completion status |
|---|---|---|---|
| Bowling Green solar | 50 | March 2026 | In service |
| Split Rail solar | 300 | June 2026 | In service |
| Castle Bluff natural gas | 800 | Fourth quarter 2027 | State construction approval received |
| Big Hollow battery storage | 400 | Second quarter 2028 | State construction approval received |
| Big Hollow natural gas | 800 | Third quarter 2028 | State construction approval received |
| West Alton natural gas | 2,100 | Fourth quarter 2031 | Application filed; decision expected in first half of 2027 |
Source: 2026 Form 10-Q, Note 2, p. 18, and investment plan, p. 69. Future service dates are management estimates dependent on approvals and construction. Battery capacity indicates maximum power output, not the number of hours it can supply power.
Actual completions and approvals provide evidence that the plan is advancing. Split Rail entered service after an approximately $600 million acquisition. In October, regulators also approved three additional battery projects and two solar projects. Yet the largest listed gas project, West Alton, is scheduled after the signed customers are expected to reach full demand. Ameren explicitly anticipates higher purchased-power costs until new generation is available. Missouri normally recovers 95% of changes in net energy costs through its fuel adjustment mechanism, but purchases still affect customer bills and the timing of cash recovery.
For two transmission projects awarded earlier in 2026, federal regulators approved including construction spending in the calculation of customer rates before completion. This can bring cash recovery forward and reduce the time Ameren must finance work without customer payments. The company will therefore receive a return through rates instead of adding a construction financing allowance to those projects’ costs.
Transmission offers a second route to growth. In October, Ameren’s ATXI subsidiary and partners won an Iowa project through a competitive selection. ATXI’s 42.5% interest in the $1.23 billion estimated project implies approximately $523 million of investment at that estimate. Its partners include NextEra’s GridLiance and Dairyland. The project’s portions are expected in service in 2032 and 2034, making it a longer-term opportunity rather than a near-term earnings contribution. It is included within the broader set of 2026 awards, not an additional amount to stack on top of them.
Sources: 2026 Form 10-Q, Notes 2 and 4 and outlook, pp. 18–20 and 75–76; Ameren and partners’ October 22, 2026 project announcement, ownership, competitive selection, estimated cost and service dates.
7. Cost recovery and plant reliability determine how much growth becomes cash
Ameren’s next operating test is to bring projects into service while keeping their costs recoverable in customer rates. Missouri has requested a $343 million annual electric revenue increase, with a decision expected by May 2027 and new rates by June. The request supports grid investment and generation additions, partly offset by bringing tax-credit benefits to customers sooner. It is a revenue request, not an approved profit increase.
Missouri’s plant-in-service accounting mechanism helps bridge the wait between investment and a rate review. For qualifying assets, Ameren can record 85% of depreciation as an amount to recover from customers later, instead of charging it immediately against profit. It can also earn a financing return on 85% of the investment covered by the rule. This supports earnings before the next rate change, but does not produce immediate customer cash. An annualized 2.25% limit applies to increases in the revenue used to set rates that arise from these deferred amounts. Amounts above that limit can be excluded from recovery.
Illinois shows that regulators can restrict recovery even while approving growth. Its 2025 gas order raised annual revenue by $79 million but removed $75 million of planned capital investment from the requested calculation. Ameren appealed; the outcome remains pending. For electric distribution, Illinois compares approved revenue with actual qualifying costs each year. Recovery of differences is subject to a cap and performance adjustments. A proposed order supports recovery of a separate $28 million 2025 reconciliation in 2027, but the final commission decision was still due in December 2026.
Sources: 2026 Form 10-Q, Note 2, pp. 18–19, and regulatory outlook, pp. 73–74; 2025 Form 10-K, risk factors on the Missouri deferral limit and Illinois reconciliation cap.
Keeping the existing system reliable is also becoming more costly. Nine-month operations and maintenance expense increased $100 million across Ameren, including $72 million in Missouri. Management identified reliability work at the Labadie and Sioux plants, tree trimming, injury and damage claims, and higher charges for past Callaway outage work. Depreciation and amortization also increased $86 million, primarily as additional equipment entered the asset base. These expenses explain part of the gap between growing infrastructure revenue and the profit Ameren retains.
Callaway’s scheduled refueling and maintenance outage began in late September, with return to service expected in November as of the filing. Its maintenance costs are initially recorded for later recovery and then charged against profit over the operating cycle. That accounting smooths the expense, while the company still has to fund the outage work and manage power supply during the shutdown. Ameren’s ability to keep older plants dependable remains important while replacement resources are built.
Source: 2026 Form 10-Q, pp. 4, 51, 59–61 and 75. The expected November return is a filing-date plan, not a verified completion.
Environmental obligations remain another claim on resources. Illinois estimates $45 million to $90 million of remaining cleanup work at former manufactured-gas sites and has recorded the $45 million lower end because no other amount is a better estimate. Ameren can recover these costs through designated customer-bill charges, subject to annual regulatory reviews of whether the costs were reasonable. The provision therefore does not cap possible spending, and recovery can occur later than payment.
Missouri separately estimates $50 million to $80 million of environmental capital spending during 2026–2031. Coal-ash retirement obligations include $57 million already recorded, with estimates subject to further site information. These disclosures have different purposes and should not be added as if they were independent bills. The larger concern is whether changing requirements alter project timing or costs before customer rates can adjust.
Source: 2026 Form 10-Q, Note 9, pp. 30–32. Environmental spending estimates are not a maximum estimate of all legal or regulatory exposure.
8. Ameren has a stronger expansion case, with financing execution at its center
Ameren’s operating outlook has improved, but its larger opportunity requires sustained funding before the full customer revenue arrives. Existing utility investment is already producing higher earnings. Signed service contracts, completed solar projects and new regulatory approvals provide evidence of future business beyond the present rate increases.
Management raised 2026 diluted EPS guidance to $5.35–$5.55 and introduced a 2027 range of $5.70–$5.90. Those are company forecasts, assuming normal temperatures for the remaining 2026 quarter and for 2027, alongside successful operating and regulatory execution.
Source: Ameren’s November 5, 2026 earnings release, earnings guidance and assumptions.
The decisive business measure is how quickly approved projects and customer commitments become collected revenue. Timely rate recovery, customer connections and construction would allow a larger utility system to support its added debt and shares. Delayed customer demand or disallowed project costs would leave the same financing commitments supported by less cash. Ameren has near-term liquidity and a defined financing plan; its task is to keep spending, customer arrivals and regulatory collections moving together.
Reporting basis and calculation notes
Reporting basis: Ameren Corporation, CIK 0001002910, Form 10-Q, accession 0001002910-26-000032, filed November 6, 2026, for the period ended September 30, 2026. Filing identity and dates were checked against SEC submission data. The analysis uses unaudited US GAAP consolidated Ameren accounts, including subsidiaries and the entity that issued bonds backed by dedicated customer charges for the retired Rush Island plant. The separately presented Missouri and Illinois accounts are used only where their scope is identified.
The quarter means July 1–September 30; the first nine months mean January 1–September 30. Earnings and cash comparisons use the same periods in 2025. Financial-position comparisons use December 31, 2025. Historical cash comparisons use January–September 2024. The research cutoff is November 8, 2026, New York time. Dated evidence used extends through the November 6 filing, including its October and early-November developments; the analysis does not establish that no later change occurred before the cutoff.
The SEC company-facts extract available during research contained filings through August 3, 2026. It was used to cross-check the historical 2024 consolidated cash amounts in USD, not as independent confirmation of the latest quarter. Current-period figures were checked against the supplied complete filing and, where applicable, the original company release. Historical facts were matched to the 2024 third-quarter accession and nine-month dates, excluding subsidiary or quarterly contexts.
Calculation notes: Reported and adjusted earnings. The only adjustment below removes the tax benefit recorded in the third quarter of 2025. It reduces adjusted net profit dollar for dollar and has no pretax operating-profit adjustment. No second tax deduction is applied. All dollar amounts are USD millions except EPS.
| Reconciliation | Third quarter 2025 | Third quarter 2026 | First nine months 2025 | First nine months 2026 |
|---|---|---|---|---|
| Reported common-shareholder profit | 640 | 676 | 1,204 | 1,347 |
| Remove prior-year tax benefit | -48 | 0 | -48 | 0 |
| Adjusted common-shareholder profit | 592 | 676 | 1,156 | 1,347 |
| Reported diluted EPS, USD | 2.35 | 2.42 | 4.43 | 4.83 |
| Remove tax benefit per diluted share, USD | -0.18 | 0.00 | -0.18 | 0.00 |
| Adjusted diluted EPS, USD | 2.17 | 2.42 | 4.25 | 4.83 |
The adjustment leaves construction financing income, investment results, weather effects and other reported items in earnings. Nine-month reported common-profit growth is (1,347 / 1,204 − 1) × 100 = 11.9%; the adjusted comparison is (1,347 / 1,156 − 1) × 100 = 16.5%. Transmission’s adjusted 2025 comparison is 326 − 48 = 278.
Sources: 2026 Form 10-Q, Note 12, p. 35, and segment table, p. 51; November 5 earnings release, non-GAAP reconciliation.
Calculation notes: How profit became operating cash. This reconciliation starts with consolidated net income, before subtracting profit belonging to outside owners of interests in subsidiaries. All amounts are USD millions for the first nine months.
| Profit-to-cash reconciliation | 2025 | 2026 |
|---|---|---|
| Consolidated net income | 1,208 | 1,351 |
| Net noncash and other income-statement adjustments | 1,497 | 1,549 |
| Changes in operating assets and liabilities | -308 | -707 |
| Cash from operations | 2,397 | 2,193 |
The adjustments below remove amounts included in profit that do not represent the same period’s operating cash. For example, depreciation spreads earlier equipment spending across years, while stock compensation pays employees with shares rather than cash. All amounts are USD millions for the first nine months.
| Noncash and other adjustments | 2025 | 2026 |
|---|---|---|
| Depreciation and amortization | 1,199 | 1,277 |
| Nuclear fuel costs allocated to the period | 39 | 63 |
| Debt issuance costs and discounts allocated to the period | 14 | 15 |
| Deferred taxes and tax credits | 255 | 281 |
| Remove construction financing income on shareholder funds | -60 | -104 |
| Stock compensation | 21 | 24 |
| Other adjustments | 29 | -7 |
| Total adjustments | 1,497 | 1,549 |
The $707 million operating-balance cash use in 2026 comprises receivables of $411 million, inventory of $97 million, supplier and wage payables of $138 million, regulatory balances of $220 million, other assets of $48 million and retirement-benefit balances of $79 million, partly offset by $156 million from accrued taxes and $130 million from other liabilities. These are cash-flow adjustments, which can differ from simple balance-sheet changes. The $399 million deterioration from 2025 outweighed the combined $195 million improvement in net income and noncash adjustments, producing the $204 million decline in operating cash.
Tax-credit sale receipts discussed in the body are management’s explanation of cash movements already included here. They must not be added again to the deferred-tax adjustment.
Source: 2026 Form 10-Q, consolidated cash-flow statement, p. 6, and cash discussion, pp. 66–68.
Calculation notes: Unpaid-bill allowance. The allowance is the amount set aside in the accounts for bills Ameren may not collect. In USD millions, the 2026 nine-month balance reconciles as 39 opening allowance + 42 bad-debt expense + 6 additions related to purchased supplier receivables − 40 net write-offs = 47 closing allowance. The comparable 2025 reconciliation is 30 + 37 + 5 − 34 = 38, using the same categories.
Source: 2026 Form 10-Q, Note 13, p. 36.
Calculation notes: Cash scope and funding. In USD millions, opening cash including restrictions of 420 + operating cash 2,193 − investing cash 4,154 + financing cash 2,066 = closing cash 525. Closing cash consists of $40 million unrestricted cash, $56 million restricted cash in current assets, $426 million restricted cash in other assets and $3 million within the nuclear trust. Opening cash comprised $13 million unrestricted, $63 million restricted in current assets, $336 million restricted in other assets and $8 million in the nuclear trust. Most closing cash therefore was unavailable for general construction or debt repayment.
Investing cash use reconciles as 4,089 capital expenditures + 26 nuclear fuel + 513 trust-security purchases − 488 trust-security proceeds + 14 other uses = 4,154. Financing cash reconciles as 3,234 debt issuance + 31 share issuance − 378 debt repayment/extinguishment − 147 short-term debt reduction − 622 common dividends − 4 noncontrolling dividends − 14 employee share-tax payments − 34 debt issuance costs = 2,066.
Sources: 2026 Form 10-Q, p. 6 and Note 13, p. 36. Free cash flow in this analysis is an explicitly calculated measure, not a separate GAAP statement line.
Calculation notes: The balance sheet and shareholders’ funding. At September 30, assets of $52,767 million equal liabilities of $38,431 million plus total equity of $14,336 million. At December 31, 2025, assets of $48,476 million equal liabilities of $34,946 million plus equity of $13,530 million. Thus, the $4,291 million asset increase was financed by $3,485 million of additional liabilities and $806 million of additional equity.
Financing debt increased $2,683 million, calculated from long-term debt, current maturities and short-term debt. Operating balances moved differently: accounts and wages payable fell from $1,254 million to $976 million, while accrued taxes rose from $66 million to $235 million. Paying down amounts owed to suppliers uses cash; accruing taxes before payment temporarily retains it. These balances are not treated as borrowing in the debt total.
Common-shareholder equity rose from $13,401 million to $14,207 million. Ameren retained $725 million of profit after dividends: $1,347 million of common profit less $622 million of dividends. That increased the account called retained earnings. Paid-in capital increased $43 million, comprising $30 million from dividend-reinvestment and employee-plan shares plus $13 million of net stock-compensation activity. Gains on contracts used to limit financial risks added $38 million after tax outside net income, in the account called other comprehensive income. Common-stock par value remained $3 million, noncontrolling equity remained $129 million, and there was no separate treasury-stock balance. The filing reports no equity-security purchases during the third quarter.
Outstanding shares reconcile from 276.4 million at year-end to 276.9 million: 0.3 million from reinvestment and employee savings plans and 0.2 million from stock compensation. Nine-month stock-compensation expense was $24 million; shares issued for compensation had a $25 million value and supplied no cash. The equity statement’s $30 million plan contribution differs from $31 million of cash proceeds because cash and equity recognition occur at different times; the filing separately identifies a $6 million receivable at September 30.
Sources: 2026 Form 10-Q, pp. 5–7, Note 13, pp. 36–37, financing-table footnotes, p. 71, and Part II, Item 2, p. 78.
Calculation notes: Debt and other commitments. The December 2025 contractual maturity schedule showed $974 million due in 2027, $966 million in 2028, $1,207 million in 2029 and $917 million in 2030. New debt actually issued through September 2026 matures in 2036 or later. The September balance sheet’s $1,574 million in current maturities of long-term debt plus $496 million in short-term debt totals $2.070 billion due within a year; the older annual schedule supplies the longer-term concentration context.
The latest full operating-lease schedule, at December 31, 2025, showed $158 million of undiscounted payments and a $76 million recorded liability. Payments were $6 million annually for 2026–2029, $5 million for 2030 and $129 million thereafter. Leases are much smaller than financing debt, but remain contractual uses of cash. That same annual filing disclosed $2.1 billion of minimum fuel, purchased-power and natural-gas purchase commitments, including $0.8 billion scheduled for 2026. These are dated commitments, not an updated September remaining balance, and are distinct from the new construction forecast.
Sources: 2025 Form 10-K, liquidity discussion, pp. 57–58; Note 5, p. 120; Note 15, operating leases. 2026 Form 10-Q, Note 4, pp. 21–23, and balance sheet, p. 5.
This analysis is for general information and is not investment advice.