Alliant Energy Corp (NASDAQ: LNT) — Faster Growth Meets a Heavier Funding Burden

Published: 2026-10-31 · Verdict: Hold · Entry price: $66 · Price target: $74 · Research confidence: High (80%)

Executive conclusion

Analyst Take

Hold at the October 30, 2026 close of $71.65. Preferred entry is approximately $66; twelve-month target is $74. Investment conviction is medium. The target applies approximately 20 times the $3.68 midpoint of management’s new 2027 ongoing-EPS guidance, rounded. The entry corresponds to approximately 17.9 times that estimate. The prospective $2.25 annual dividend yields 3.14% at the current quotation; target appreciation plus that dividend implies approximately 6.4% prospective return. These are analyst judgments conditional on execution, financing, and valuation, rather than company forecasts of shareholder returns. [S3][S11]

October materially improved the investment proposition. Alliant introduced 2027 EPS guidance of $3.63–$3.73, increased its 2027–2030 annual ongoing-EPS growth expectation to at least 8%, and disclosed a $15.935 billion investment schedule for those four years. Management reports identifiable customer progress: Google is taking transmission service, QTS expects to commission its first two Cedar Rapids buildings during the fourth quarter, and Meta is taking distribution service ahead of expected transmission service in early 2027. These developments make the opportunity more credible than a collection of preliminary electricity inquiries. They still provide less evidence than disclosed customer payments, complete contractual loss allocation, or demonstrated lifetime project returns. [S2][S3][S4]

The financing improvement deserves substantial credit. Executed agreements provide IPL and WPL access to approximately $5.126 billion of Federal Financing Bank borrowing, guaranteed by DOE, at the applicable Treasury rate plus 37.5 basis points. Financial close is verified. Funding remains subject to eligible expenditures, regulatory and environmental approvals, ratings, fees, and other conditions. The respective utilities remain fully responsible for repayment. The government guarantee protects the lender; it does not guarantee customer demand or shareholder returns. DOE’s projected customer savings cannot be added directly to equity value. [S7][S8][S39]

My variant perception concerns the conversion rate between infrastructure growth and the existing common share. Management now explicitly identifies approximately 3.75 percentage points of equity dilution and 0.50 percentage point of parent and non-utility refinancing drag as principal differences between 13% investment growth and the at-least-8% EPS expectation. That confirms the earlier financing concern while making it more measurable. Those drags are already incorporated in guided EPS: deducting them again would double count the burden. The useful challenge is whether actual funding stays within that bridge. [S4]

The strongest opposing evidence is financial composition. Nine-month common net income increased $124 million, but operating income declined $5 million and operating cash flow increased only $9 million. Higher equity-method income, AFUDC, and tax benefits explain the consolidated acceleration after higher interest expense. Moreover, the filing’s 2025 interest-expense line is $512 million, versus the draft’s standardized $486 million. Using filed interest produces approximately $570 million of trailing expense and only 3.3 times coverage by operating income plus depreciation and amortization. The franchise has maintained market access, but the financing burden is greater than the draft’s presentation suggested. [S1][S2][S12][S16]

Cash analysis also requires balance. Conventional operating cash less construction was negative $897 million for nine months. Including $318 million of investing-classified receipts on sold receivables reduces that deficit to $579 million before dividends. Both measures show external funding needs; the second prevents the cash-flow classification from exaggerating the economic shortfall. Similarly, higher O&M deserves scrutiny without treating every dollar as permanent maintenance inflation: incentive compensation explains $37 million of the $88 million increase. [S2]

Business-quality conviction is higher than valuation conviction. Evidence is strong for filed accounts, signed financing, and disclosed regulatory actions; moderate for management-reported customer milestones; and weakest for confidential contract economics and long-term earned returns. The immediate decision sequence is fourth-quarter tax normalization, year-end equity settlement, early-2027 customer and resource decisions, and then actual cash and earnings delivery. I would strengthen the judgment if customer payments follow disclosed ramps, guidance survives actual issuance, credit remains stable, and regulatory outcomes preserve viable recovery. A major customer delay after irreversible spending, additional equity for substantially unchanged earning assets, or repeated recovery setbacks would weaken it. The improved opportunity is real; at the recovered quotation, a meaningful portion of successful conversion is already priced. [S2][S4][S7][S9]

Changes since 2026-09-10

The prior report’s central question—whether contracted load becomes adequately financed per-share earnings—survives. Several numerical assumptions have changed, and two accounting comparisons require correction.

The new 2027 midpoint is 7.1% above the narrowed 2026 midpoint of $3.435. Management’s advertised 8% uses the original $3.41 midpoint. Both calculations are valid when their bases are stated. The higher growth framework supersedes the earlier outlook; it does not establish that the old forecast was false when issued. [S1][S2][S3][S4]

The consistently retrieved price series reports a September 10 close of $67.25, versus the prior report’s stored $67.46 reference. Appreciation to $71.65 is therefore 6.5% on the matched series, or 6.2% against the old reference. The discrepancy is retained as a data inconsistency without inventing its cause. The prior $64 entry threshold subsequently traded through: October 1’s intraday low was $62.54 and its close was $63.71. This establishes availability of that historical price, not a transaction or ownership. [S10][S11]

The prior recovery test has been met directionally, while the full-year recurring-earnings test remains open. The earlier interpretation that higher costs might largely reverse is weaker after management’s October explanation that significant O&M pull-forward was absent. Conversely, the filing’s incentive-compensation bridge prevents an equally unsupported conclusion that the entire increase is permanently fixed. These distinctions matter more than changing the description of the same quarterly result from optimistic to pessimistic. [S2][S4]

Stock Price Action — Five-Year Event Map

The retrieved October 29, 2021–October 30, 2026 series contains 1,256 split-adjusted daily observations. LNT began at $56.57, reached a five-year intraday low of approximately $45.15 on October 3, 2023, and reached an intraday high of $78.81 on July 7, 2026. The current $71.65 close is 9.1% below that high. The trailing-52-week intraday range is $62.54–$78.81; the current price sits approximately 56% through that range and 14.6% above its low. These are price observations excluding dividend reinvestment. [S10][S11]

The historical prices are facts. The driver descriptions are interpretations, supported by contemporary financial and operating disclosures rather than event-level causal estimates. Annual filings document the importance of investment, financing, weather, and regulation. The latest disclosures identify specific October improvements, but they do not explain every intervening trading session. [S1][S2][S3][S7][S19][S20][S21][S22]

A matched peer comparison materially limits claims of company-specific validation. From September 10 through October 30, LNT appreciated 6.54%, WEC 10.18%, CMS 3.58%, AEP 5.46%, and XEL 5.85%. The simple average peer appreciation was 6.26%. A regression of LNT’s 36 daily price returns against the equal-weighted daily returns of those four peers produces a coefficient of approximately 1.00 and R-squared of approximately 0.92. The sample is short, excludes dividends, and contains closely related companies. It is a contemporaneous diagnostic rather than a durable hedge ratio. [S10][S30][S31][S32][S33]

That result supports a narrower conclusion than either bullish or bearish price narratives usually imply. LNT’s rebound occurred alongside a substantial common utility move. It cannot independently prove that its customer contracts became more profitable than peers’ contracts, that investors accepted its financing assumptions, or that regulatory risk disappeared. Conversely, common movement does not invalidate company-specific improvements established by filings. Price attribution and fundamental verification answer different questions.

Verdict: The quotation recovered substantially from October’s trough while remaining below July’s peak. Most of the inter-report movement was shared with the selected peer group. Future company-specific evidence should come from customer payments, normalized earnings, financing settlement, and regulatory outcomes rather than the rebound alone.

Business Overview

Alliant Energy is a Wisconsin-incorporated public-utility holding company. Its two reportable utility segments are Interstate Power and Light, or IPL, principally serving Iowa, and Wisconsin Power and Light, or WPL, serving Wisconsin. Alliant Energy Finance holds non-utility activities and investments. The parent’s common shares trade on Nasdaq. The established business supplies essential electricity and natural-gas service; the current growth debate concerns a substantial expansion in electricity requirements within that existing footprint. [S1][S2]

The business and its economic drivers are readily understandable: raise capital, invest prudently in generation and networks, recover approved costs, and earn regulated returns while controlling operating expense, financing, and dilution. A household pays for continuing access and consumption. A large industrial customer also purchases capacity, connection certainty, power quality, and coordination of resources. Shareholder economics depend on the approved revenue requirement and customer terms, rather than unrestricted pricing of a scarce commodity.

Customer value and revenue durability

Revenue is predominantly recurring essential-service revenue, but fuel pass-through, weather, industrial usage, and regulatory timing make reported sales less stable than the franchise itself. A colder winter can increase gas revenue and commodity expense together. Lower fuel prices can reduce revenue while leaving underlying utility earnings largely intact. Consequently, revenue growth is an incomplete measure of franchise improvement; earned returns, retained cash, and per-share earnings are more discriminating. [S1][S2]

For residential customers, the most important outcomes are reliable service, safe delivery, rapid restoration, and manageable bills. For commercial customers, continuity and power quality affect operating costs. For a data center, access to a large dependable power block by a credible date can determine whether a site is usable. Alliant combines network access, generation planning, procurement, engineering, interconnection coordination, and regulatory applications to deliver that outcome. The customer value can be considerable even when regulation limits the portion retained by shareholders.

This distinction explains why an attractive customer proposition does not automatically create extraordinary utility profitability. A utility may solve a difficult connection problem yet earn only its authorized return on approved capital. It can also create customer savings through cheaper borrowing or fixed-cost sharing while retaining little incremental margin. The relevant question is which costs are reimbursed, which capital earns a return, and how obligations behave if the customer’s ramp changes.

The revenue mix is overwhelmingly electric. For the first nine months of 2026, consolidated electric utility revenue was $2.951 billion, gas utility revenue $408 million, other utility revenue $6 million, and non-utility revenue $75 million. Electricity represented approximately 86% of consolidated revenue. IPL exited the steam business after 2025, explaining much of the decline in other utility revenue. That reduction should not be misread as deterioration in the continuing electric franchise. [S2]

Operating entities and the parent bridge

Subsidiary net income includes tax and construction-accounting effects. IPL’s net income can therefore exceed operating income without implying a merchant operating margin above 100%. The subsidiaries’ revenue and net income also cannot simply be added and capitalized while ignoring corporate costs, investments, and eliminations. [S2]

Management’s separate earnings grouping reports nine-month Utilities and Corporate Services income of $775 million, ATC Holdings income of $36 million, and a Non-utility and Parent loss of $19 million. These reconcile to consolidated common income. They are useful management-defined presentations, while IPL and WPL remain the filing’s reportable utility segments. Confusing the two segment systems can lead to incorrect statements about where earnings improved. [S2]

ATC-related investments provide exposure to regulated transmission through equity-method accounting. Their carrying value increased from $463 million at year-end to $522 million in September. The related nine-month equity income was $51 million before the financing and tax effects included in management’s alternative earnings grouping. This is a meaningful infrastructure interest, but its accounting carrying value is neither a current market quotation nor proof of an available disposal premium. [S1][S2]

The smaller non-utility portfolio includes logistics, an Oklahoma wind interest, and corporate venture investments. Their economic characteristics differ. Logistics depends on commercial activity and competitive service. Wind income depends on operating and contractual performance. Venture income can move with valuations of underlying holdings and is recognized with a lag. These businesses should not receive an identical assessment of recurrence merely because they appear within the same consolidated statement.

Corporate venture income was $48 million for nine months, versus a $10 million loss in the comparable period. The filing attributes the improvement principally to valuation changes, including an onsite-power company’s IPO, recognized with a one-quarter lag. These are reported accounting earnings, but the available disclosure does not establish a matching recurring cash distribution. Valuation analysis should preserve that distinction rather than removing all investment income or capitalizing all of it at a utility multiple. [S2]

Economically valuable assets and obligations

The principal economically valuable assets not separately marked to market are franchise rights, existing network access, development sites, interconnection positioning, and regulatory operating capability; no defensible aggregate uplift to book value is established. An assembled service network can connect customers faster than a new entrant could reproduce the same permissions and infrastructure. That capability earns its value through approved investment, reliable service, and timely recovery. Repeated delays or disallowances would reduce its economic worth. [S1][S2]

Regulatory assets require a different interpretation. September current and non-current regulatory assets totaled approximately $2.343 billion, while regulatory liabilities totaled approximately $1.043 billion. Assets generally represent costs expected to be recovered through future rates; liabilities generally represent customer obligations or benefits. These balances are neither hidden cash nor a freely tradable investment portfolio. Their value depends on timing, permitted return, and final regulatory treatment. [S2]

The security is ordinary U.S. corporate common stock, rather than an ADR, MLP, or partnership interest requiring partnership K-1 reporting. The corporate structure does not impose partnership distribution mechanics. Individual dividend taxation depends on the holder, but there is no basis for applying partnership valuation or tax assumptions to the listed common claim. [S1][S7]

Verdict: The established business is understandable and durable. Its complexity lies in the timing and allocation of utility returns, parent financing, tax benefits, and investment income. The large-load opportunity strengthens the need for those distinctions because customer value, consolidated earnings, and cash available to each common share can develop at different speeds.

Industry Dynamics

Alliant operates within regulated electric and gas systems where network economics, service obligations, franchises, and public oversight create substantial barriers to entry. A rival generally cannot duplicate the incumbent’s local distribution grid and compete for the same ordinary retail meters simply because the incumbent reports an attractive return. Regulation provides the principal constraint on prices and investment recovery. The resulting profit opportunity is durable but deliberately bounded. [S1]

Industry profitability is governed by recoverable capital and allowed returns, while franchises, network scale, permitting, and financing create high barriers to entry. The relevant number of network competitors at an existing meter is usually very small. The number of utilities and regions competing for a mobile industrial project before it selects a site is much larger. Both statements can be true without contradiction.

Profit pools and authorized economics

The core profit pool is the equity return on approved rate base. Operating-cost recovery, depreciation, and fuel reimbursement support service and capital replacement; they are not all economic profit. As an illustration, $1 billion of approved investment with a 51% equity layer and a 9.65% allowed equity return supports approximately $49 million of annual equity return before parent effects. With a 54.5% equity layer and a 9.8% return, the comparable amount is approximately $53 million. These are calculations illustrating regulatory mechanics, not forecasts for a particular project. [S1]

Alliant’s actual authorized returns vary by asset cohort. The annual filing lists different returns for legacy IPL generation investments, a blended rate for certain other electric assets, a 9.65% gas return, and 9.8% for WPL retail electric and gas with a 54.5% equity layer. Some credit carryforwards and other assets receive different treatment. A single headline ROE therefore cannot be applied uniformly to every dollar of capital or construction work in progress. [S1]

Authorized returns also differ from earned subsidiary ROE, consolidated ROE, project cash returns, and investor total return. Regulatory lag can reduce the earned result. Holding-company leverage can alter consolidated ROE. Market valuation can change shareholder returns without changing utility earnings. The appropriate comparison depends on the question: project recovery requires asset-level terms, financial resilience requires debt and cash measures, and common-share compounding requires earnings and distributions after issuance.

Forward test years and advance ratemaking can reduce uncertainty by addressing forecast costs or project parameters before final expenditure. Subsequent review can still compare actual costs and revenues with those forecasts. Iowa’s 2026 proceeding demonstrates this balance: electric results remained within the accepted return range, while residential gas rates were reduced and management practices received further scrutiny. A useful investment mechanism is not unconditional immunity from review. [S9]

Demand geography and the supply-side cycle

The relevant market is domestic and geographically bounded by Iowa and Wisconsin service territories, with growth coming from electricity intensity and customer location rather than international expansion. Management’s approximately 60% peak-demand growth expectation through 2031 is a company forecast tied to contracted data-center demand. It is not equivalent to 60% energy-sales growth, a national electricity-market forecast, or a guarantee of immediate billed utilization. [S3]

Peak MW, annual MWh, and customer revenue have different meanings. Peak demand determines capacity requirements; energy consumption influences generation and purchased-power needs; minimum bills and tariffs determine payment obligations. Storage MW also differs from storage duration and accredited seasonal capacity. Comparing headline capacity across utilities without preserving those units can exaggerate either market share or economic value.

The industry is becoming more competitive for project location, equipment, labor, and financing, while ordinary retail distribution remains protected by territorial regulation. Customers choose among regions before committing buildings and interconnections. Utilities simultaneously seek turbines, transformers, contractors, engineering resources, and transmission access. Scarcity can therefore benefit equipment and construction suppliers while increasing the incumbent utility’s cost of serving new demand. [S1][S2][S28]

This is the important supply-side capital-cycle tension. Strong demand encourages many utilities to invest together, but the industry cannot instantly expand manufacturing capacity, skilled labor, or permitting resources. A signed customer can improve demand visibility while the cost of fulfilling the commitment rises. If costs exceed approved caps or schedules, the economic advantage may accrue to suppliers or customers rather than utility shareholders.

The cycle also creates temporal risk. Generation and network assets are long lived, while customers can revise the pace of computing deployment. A minimum-payment obligation may protect part of the utility’s fixed costs, but its duration can be shorter than the physical asset life. Long-term value therefore depends on both the initial contract and the usefulness of the residual asset after that contract. Public disclosures do not support assuming that all new infrastructure remains equally redeployable.

Foreign low-cost production cannot directly replace the licensed local distribution network, although imported equipment, tariffs, and supply restrictions can alter construction costs and schedules. More direct substitutes include customer relocation, self-generation, behind-the-meter supply, efficiency, and alternative service configurations. These threats matter most before a large customer has made substantial site-specific commitments. [S1][S2]

Peer context and policy

WEC is the closest jurisdictional comparison because it shares Wisconsin regulation and serves large-customer development. CMS offers a compact Midwest regulated-growth comparison, although its Michigan framework and non-utility restructuring differ. AEP contributes a much larger transmission and large-load comparison. Xcel adds a Midwest-relevant capital program but has broader jurisdictions and material liability issues. These are analytical peers; they are not interchangeable suppliers to an existing Alliant household. [S26][S27][S28][S29]

Peer disclosures also show why demand categories require discipline. AEP’s presentation combines electric-service agreements and letters of agreement within its headline portfolio. WEC separately reports ordinary deliveries after excluding specified very large customers. CMS’s adjusted earnings remove major restructuring effects. Xcel’s ongoing earnings and capital needs coexist with distinct legal exposures. A synchronized price does not make the underlying earnings or contract definitions identical.

Federal policy now affects both funding and project affordability. Tax-credit qualification determines available benefits, while transferability affects cash realization. Government-backed borrowing lowers a funding spread subject to its terms. Neither mechanism guarantees a project’s operating performance. The proper economic bridge runs from approved expenditure through credits, customer allocation, financing cost, and retained return. [S1][S7][S8]

Verdict: The industry offers protected service franchises and an unusually strong demand opportunity, but the return remains constrained by regulation and capital availability. LNT’s prospective load is large relative to its system, increasing growth potential alongside construction, customer, and funding concentration.

Competitive Position

Alliant’s moat is legal and infrastructural. Existing networks, operating assets, customer connections, sites, and regulatory capabilities are difficult to reproduce. The protected outcome is an opportunity to recover prudent costs and earn approved returns. Without the franchise, ordinary service revenue would face more direct competition; without competent execution and regulatory credibility, approved investment could fail to produce timely shareholder earnings. [S1][S2]

Brand has limited direct pricing power; reliability, affordability, regulatory credibility, and connection timing matter more than customer preference for the Alliant name. A residential customer generally cannot select another physical distributor while remaining at the same address. A prospective industrial customer can value the company’s reputation, but principally because it predicts delivery and operating outcomes rather than permitting unrestricted premium pricing.

The nature of competition is pre-location rivalry for large customers followed by post-location execution under regulated tariffs and contracts. Before commitment, customers can compare territories, resource strategies, costs, and schedules. After buildings and interconnections exist, relocation becomes much more expensive. This change in bargaining position is economically meaningful, but regulated terms continue to limit the utility’s ability to monetize it. [S1][S4]

Customers face high physical and contractual switching costs after interconnection, but prospective large customers retain meaningful location choice before buildings and customer-specific infrastructure are committed. The relevant moat test is consequently different at each stage. Before location, Alliant must offer a credible combination of power availability and cost. After location, it must operate reliably and recover costs under the agreed framework.

Time to power as an operating advantage

Management emphasizes selecting sites where large loads can interconnect without major incremental transmission investment. If demonstrated consistently, that can shorten schedules, reduce gross infrastructure exposure, and improve customer affordability. Google’s reported transmission service and Meta’s reported distribution service provide preliminary support for execution capability. They do not establish that every future prospect has an equivalent network position. [S4]

Time to power creates value only when several dependencies align. Generation must be available in the required season, transmission must be authorized and energized, local permits must allow the customer facility, and contractual payments must compensate the utility. A fast distribution connection with insufficient firm capacity is a different product from fully supported large-load service. The analysis should therefore track the specific service milestone rather than treating all energization as completion.

Alliant also depends on external transmission providers. Owning generation and distribution does not mean the company controls every required network upgrade. September cancellation-related guarantees to transmission providers totaled approximately $199 million at IPL and $125 million at WPL. Those gross obligations show that some pre-service exposure exists at the utilities. Public disclosure does not provide a complete reconciliation of customer collateral and termination recovery against each guarantee. [S2]

That distinction cuts both ways. The guarantees do not establish a $324 million expected shareholder loss; customer remedies may offset them. Equally, the existence of a large customer and a signed agreement does not establish full collateralization under every stress scenario. A competitive advantage in coordinating transmission should ultimately appear as better schedules, lower net exposure, or more secure cash recovery.

Regulation as an advantage with conditions

Iowa’s advance-ratemaking framework can improve visibility before major construction is completed. The approved framework for up to 1,000 MW of new wind includes a $3,020-per-kW fixed cost cap incorporating AFUDC, transmission, and other specified costs. Such terms clarify the recovery boundary. Their value depends on constructing inside that boundary and preserving adequate economics after financing. A cost cap protects customers while exposing shareholders to some execution risk above the approved amount. [S2]

Wisconsin demonstrates why customer approval and shareholder retention must be separated. The June-approved customer rate includes conditions governing demand revenue received before WPL’s next base-rate review through its fuel-cost recovery mechanism. Early customer revenue therefore cannot simply be assumed to become unrestricted incremental shareholder profit. The September broader tariff application proposes a fifteen-year initial term, minimum demand, termination charges, reimbursement obligations, and credit support; approval remains ahead. [S2]

The May Wisconsin announcement is useful evidence of regulatory priorities: transparency, termination protection, financial safeguards, and ongoing reporting. The current filing establishes subsequent customer-specific approval and the pending broader process. The earlier preliminary announcement should not substitute for the status of later written actions. Regulatory scrutiny can strengthen a repeatable business model by clarifying who pays, while also limiting economics initially proposed by the utility. [S2][S37]

Relative to WEC, Alliant has greater Iowa exposure and a smaller system against which several customer projects can produce exceptional percentage growth. Relative to AEP, it has less geographic and transmission diversification. Relative to CMS, named large-customer service milestones are more developed, but the project and regulatory frameworks differ. Relative to Xcel, its risk discussion should preserve its own concentration and operational exposures rather than import wildfire-specific liabilities. [S26][S27][S28][S29]

Limits to the moat

There is no verified proprietary generation technology or consumer-brand advantage supporting unregulated excess returns. The practical advantage is coordination of infrastructure, customers, sites, and regulation. Each claim should be tied to a measurable outcome: quicker service, approved costs, adequate security, reliable operations, earned returns, or better per-share growth. An expanding investment plan alone does not establish superiority.

Regulatory trust is a particularly important limitation. Iowa rejected charter-flight recovery as inconsistent with the settlement and opened a management-efficiency inquiry involving severance and outsourcing concerns. Those findings do not weaken the physical network barrier, but they contradict an unconditional claim of frictionless regulation or superior management conduct. The relevant institutional asset is trust maintained through cost discipline and service, rather than a permanent jurisdictional label. [S9]

Concentration also limits diversification. Management clarified that current contracted demand is concentrated at three sites, despite five agreements. Agreement count therefore overstates the number of independent operating locations. Different agreements can share local permitting, transmission, construction, or counterparty dependencies. The appropriate stress test groups correlated sites and obligations rather than assigning every document an independent probability of success. [S4]

Verdict: The franchise moat is durable, and current service milestones support practical execution capability. The incremental large-load advantage remains conditional on final tariffs, transmission coordination, customer security, and regulatory trust. It deserves a premium only to the extent those capabilities improve actual retained economics.

Growth History and Forward Opportunities

Alliant’s recent history establishes moderate regulated compounding. Diluted GAAP EPS increased from $2.63 in 2021 to $3.14 in 2025, approximately 4.5% annually. Management’s ongoing series increased from $2.63 to $3.22, approximately 5.2% annually. The at-least-8% 2027–2030 expectation is a meaningful acceleration from that recent record, although management’s longer ten-year history shows stronger growth than the narrower five-year comparison. [S12][S25]

The outlook for regulated electricity service is favorable because signed large loads can expand capacity needs and customer payments, while the gas business remains an established service franchise with weather and industrial sensitivity. The important qualification is economic: incremental demand must support resources, operating expense, depreciation, financing, and customer protection before it produces sustainable earnings for existing shares. [S2][S3]

Commercial commitments and customer ramps

The present framework comprises five data-center agreements and approximately 3.4 GW of contracted demand. Management expects roughly 60% peak-demand growth by 2031. The approximately 370 MW Iowa agreement was entered into in April 2026 and identified on the October call as supporting Google’s Cedar Rapids expansion. References to approximately 400 MW are rounding of that opportunity and must not be added as another contract. [S2][S3][S4]

Google is reported to be taking transmission service in line with its accelerated schedule. QTS expects commissioning of its first two Cedar Rapids buildings later in the fourth quarter. Meta is reported to be taking distribution service, with transmission service expected in the first quarter of 2027. These are management-reported milestones. Public evidence does not disclose each customer’s billed MW, minimum payments, utilization, or contribution after incremental costs. [S4]

The correct progression is contract, local permission, construction, connection, available firm service, billed demand, collected cash, and earned return. Projects can advance on some steps while remaining incomplete on others. For example, temporary or non-firm service can support customer construction without establishing the ultimate firm-capacity requirement. Tracking that sequence helps avoid assigning mature earnings to an early operating milestone.

One timing change deserves explicit attention. On the July call, management expected the QTS Clinton individual customer-rate filing later in 2026. On the October call, it expected that filing in the first half of 2027. This is a changed regulatory-filing timetable. It does not establish a customer cancellation or an equivalent delay in every construction activity, but it argues against describing all project timing as unchanged. [S4][S5]

The investment schedule and its concentration

The 2027–2030 total is $15.935 billion. Estimates exclude AFUDC and applicable capitalized interest. Spending peaks in 2027–2029, ahead of the mature load profile management describes for 2031. That schedule creates a substantial interval during which construction and financing must be supported before all customer cash reaches its eventual level. [S3]

The overlapping-year comparison is more informative than the headline rolling-window increase. The old schedule allocated $10.270 billion to 2027–2029; the new schedule allocates $13.325 billion, approximately 29.7% more. The approximately 19% headline compares different four-year windows, dropping 2026 and adding 2030. Meanwhile, the 2026 forecast itself declined from $3.130 billion to $2.860 billion. The evidence supports both expansion and rephasing rather than a uniform increase in every year. [S1][S3]

The six-year resource framework includes approximately 2.8 GW of new gas resources, 1.3 GW of storage, 1.3 GW of renewable generation, existing gas upgrades, and wind refurbishment. Approval status varies. The approximately 720 MW Linn County project and 1.2 GW Riverhawk project remain subject to decisions expected in 2027. Bent Tree North wind and specified storage expansions have progressed further. Aggregating these resources as though they were already operating would overstate present capacity. [S2]

Optionality beyond the base plan

Management expects approximately 1 GW of additional contracted large load within six months. It estimates approximately $2–$3 billion of additional capacity-related capital per incremental GW, with prospective load beginning around 2029–2030 and some resource investment extending beyond 2030. This is a management expectation outside the present capital plan, not an immediate contribution to 2027 EPS. [S4]

The higher inclusion threshold now explicitly incorporates local permitting alongside land, transmission, generation, and commercial visibility. That is a useful improvement in disclosure discipline. It also means older pipeline totals cannot automatically be combined with current cohorts. Changes in qualification criteria can alter reported pipeline size without equivalent economic additions or losses.

Mesabi Metallics provides separate industrial optionality. Management says initial non-curtailable capacity requirements are included in the refreshed plan, while a significant portion of prospective load is expected to be curtailable. That differs from continuously firm data-center demand. Applying the data-center capital-per-GW rule mechanically to an undisclosed industrial total would create false precision about resource requirements. [S4]

Verdict: Growth visibility improved through named customers, service milestones, and a more developed resource schedule. The enlarged construction peak and changed Clinton filing timetable show why commercial progress must still be tested against paid demand, final approvals, and funding. Additional pipeline conversion is upside only after its corresponding obligations are included.

Financial Quality

Alliant’s accounts describe a capital-intensive regulated franchise with improving earnings and a growing financing burden. The appropriate analysis reconciles filed GAAP statements, management’s ongoing EPS, subsidiary results, construction accounting, and cash classifications. Standardized financial data are useful for discovery and multi-year comparison, but their field labels cannot replace the filing when definitions differ. [S1][S2][S12][S14]

Five-year financial reconciliation

The figures reconcile to annual filings and the company’s ongoing-EPS reconciliation. The 2021 difference between total and common income reflects $15 million of preferred-dividend requirements. Operating income plus D&A is an explicitly defined analytical measure; it does not include every non-operating item sometimes included in EBITDA. [S1][S19][S20][S21][S22][S25]

Revenue grew approximately 4.4% annually from 2021 to 2025, and operating income approximately 6.6%. Filed interest expense grew approximately 16.6%, from $277 million to $512 million. That is materially different from the draft’s $284 million-to-$486 million series. The larger financing charge is an important counterweight to asset growth, especially when parent debt must be serviced from subsidiary distributions.

Company Financials’ standardized interest values do not consistently match the filed line item. For 2023–2025, the differences of $26 million, $21 million, and $26 million equal the debt components of AFUDC disclosed in the 2025 filing. The earlier-year discrepancy is not assigned an unsupported universal explanation. The report uses filed interest expense consistently for its coverage calculations and retains standardized ratios only as separately defined diagnostics. [S1][S12][S16][S20][S22]

Current earnings and the implied fourth quarter

The quarter improved at the operating level: operating income increased $40 million. However, year-to-date operating income remained slightly lower despite 4.3% revenue growth and 18.6% common-income growth. The complete income bridge is negative $5 million from operations, positive $69 million from equity income, positive $34 million from AFUDC, positive $12 million from other items, negative $58 million from interest, and positive $72 million from the larger tax benefit. [S2][S3]

This bridge does not establish that all non-operating earnings are poor quality. ATC income can be recurring, and construction returns can be recoverable. It does establish that consolidated profit growth currently overstates the acceleration in customer-funded operating profit. The next normalization test must distinguish recurring regulated investment contributions from valuation gains and temporary tax allocation.

Annual ongoing guidance of $3.41–$3.46 less nine-month ongoing EPS of $2.99 implies approximately $0.42–$0.47 for the fourth quarter. The comparable 2025 quarter was $0.60. The implied decline is approximately 22–30%. This is an analyst calculation from annual guidance, not separately issued quarterly guidance. Management explicitly expects favorable tax timing to reverse by year-end, so a weaker fourth-quarter comparison is compatible with the improved full-year outlook. [S3][S4][S38]

Earnings are neither at a conventional commodity-cycle peak nor a clean trough; construction, load ramps, weather, tax allocation, valuation income, and financing currently separate reported profit from mature asset economics. Annualizing the latest quarter would ignore the expected reversal. Equally, extrapolating the first-half weakness would ignore the verified third-quarter operating recovery. The appropriate observation period spans the full year and actual project commissioning.

Costs, taxes, and accounting quality

Nine-month O&M increased $88 million to $618 million. The filing identifies $37 million of higher incentive compensation, $23 million of generation and energy-delivery expense, $9 million of energy-efficiency expense mostly offset by revenue, and $19 million of other changes. Management says significant pull-forward is absent, but that does not mean every component grows permanently at the same rate. Incentive expense is performance-sensitive; fleet maintenance and delivery costs have different recurrence. [S2][S4]

The tax line is structurally important. Guidance assumes a negative 28% consolidated effective tax rate for both 2026 and 2027. Credits can support earnings and affordability while transfer proceeds support funding. Gross credits cannot simply be divided by shares to estimate retained shareholder EPS: regulatory deferrals, customer sharing, eligibility, timing, and tax allocation all affect the outcome. A negative tax rate is therefore neither automatically low quality nor economically equivalent to an unrestricted subsidy. [S1][S3]

Accounting is definition-sensitive rather than demonstrably aggressive: regulatory deferrals, tax credits, construction returns, and differing adjusted-EPS exclusions require explicit reconciliation. The auditor identifies regulatory accounting as a critical audit matter because recovery assessments require judgment. The latest filing reports effective disclosure controls and no material quarterly change in internal control. Those disclosures support the reporting framework without eliminating uncertainty about future recovery. [S1][S2]

A concrete definition difference concerns 2025 EPS. Investor ongoing EPS was $3.22, while the compensation calculation was $3.24. The proxy additionally excluded $0.02 of development-site expense retained in investor ongoing EPS. The discrepancy is small but real. Incentive achievement, historical growth, and investor guidance should each use their own reconciled denominator. [S6][S25]

Returns on equity and capital

The business earns utility-like returns: 2025 consolidated ROE was approximately 11.3%, while a defined 21%-tax operating ROIC sensitivity was approximately 4.5%. ROE uses $810 million of common income divided by average 2024–2025 common equity of approximately $7.169 billion. The older 19–20% characterization remains unsupported. Authorized subsidiary returns and consolidated accounting ROE are distinct measures. [S1][S13][S15]

The operating ROIC sensitivity applies an assumed 21% tax rate to $1.025 billion of operating income, producing $809.75 million of NOPAT. Average funded debt plus common equity less cash is approximately $18.112 billion. The resulting return is 4.47%. The calculation retains construction capital and corporate debt while excluding equity-method income from operating profit. It is a reproducible accounting sensitivity, not a project IRR or a standardized company metric.

Its limitation is material: a 21% tax assumption removes the benefit of LNT’s unusual tax position. Assigning the entire reported tax benefit to operating income would produce a higher return, approximately 6.5%, but would not constitute a clean operating-tax allocation. Company Financials reports approximately 6.2% and 6.0% standardized ROIC for 2022 and 2023, with later values missing. The evidence supports definition-dependent mid-single-digit capital returns rather than extraordinary economics. [S1][S13][S15]

Value creation requires actual project cash flows to exceed their risk-adjusted financing cost. Regulated leverage and tax treatment can support attractive equity compounding despite modest conventional ROIC. Conversely, construction balances can increase capital before cash recovery. Earned versus authorized subsidiary ROE, per-share growth after issuance, and credit quality must therefore accompany a consolidated return calculation.

Balance sheet, leverage, and liquidity

Funded debt includes short-term borrowing, current maturities, and long-term debt, including junior subordinated notes. September net debt was approximately $12.537 billion. Against approximately $1.900 billion of trailing operating income plus D&A, leverage was approximately 6.6 times. Trailing filed interest expense was approximately $570 million, giving approximately 3.3 times coverage. For 2025 alone, the same coverage convention produces approximately 3.65 times. These are analytical measures rather than covenants or rating-agency calculations. [S1][S2][S13]

Liquidity depends on continued market access. September cash was $26 million, commercial paper $704 million, other short-term borrowing $400 million, and current long-term maturities $374 million. Available revolving capacity was $596 million, including only $139 million at the parent. Undrawn utility federal facilities cannot be treated as unrestricted parent cash. The filing separately reports company-sourced ratings; these should not be represented as independently obtained agency opinions. [S2][S7]

Cash conversion and contingent obligations

Capital intensity is substantial: nine-month construction spending of $1.806 billion exceeded operating cash flow by $897 million before $413 million of dividends. For 2025, operating cash of $1.169 billion compared with $2.483 billion of construction. Both periods require external funding, but the cash statement’s receivables classification changes the size of the apparent deficit. [S1][S2]

The receipt-inclusive measure is a cash-classification reconciliation, not a claim that all receivables activity is normalized operating cash or that financing needs disappear. It also differs from management’s operating-cash measure excluding receivables sold because sales and collections occur at different times. Both presentations remain negative after construction and dividends. [S1][S2][S14]

Net income rose faster than operating cash because equity-method earnings, deferred taxes and credits, working capital, and regulatory balances affect cash conversion differently. Nine-month operating cash increased $9 million while common income increased $124 million. October tax-credit transfers generated a further $174 million after September, and $61 million of tariff-cost recoveries arrived in October. The latter reduced previously capitalized storage costs; it is a capital-cost and liquidity benefit rather than an equivalent operating-EPS windfall. [S2]

Material economic obligations include $318 million of capital purchase commitments, $1.693 billion of other minimum purchase commitments, $324 million of transmission cancellation guarantees, tax-credit indemnities, and an uncapped legacy guarantee. Known Whiting-related abandonment exposure is estimated at $92 million, but that estimate is not a contractual cap. Management does not presently expect material guarantee payments. Gross commitments should not be added mechanically to net debt, yet their timing and loss allocation belong in liquidity stress tests. [S2]

Verdict: The regulated franchise supports earnings and funding access, but current net-income growth exceeds operating and cash improvement. Correcting interest expense makes the coverage trend less comfortable. Returns remain utility-like, and cash classifications require care in both bullish and bearish interpretations.

Capital Allocation

Alliant’s capital allocation is dominated by regulated organic investment, followed by dividends and financing. The central decision is how rapidly to build resources for customer demand while preserving credit, affordability, and per-share returns. Capital expenditure creates value when recoverable cash returns compensate for construction and funding risk. Its size alone provides little evidence of capital efficiency. [S1][S2]

Free cash flow after construction is negative; management prioritizes approved reinvestment, capital-market access, and a dividend within its 60–70% earnings payout policy. The 2025 conventional cash deficit after construction and dividends was $1.835 billion, or $1.207 billion after including investing-classified receivable receipts. The investment-plus-dividend package is consequently externally financed even though accounting earnings cover the dividend. [S1][S2]

Reinvestment and transaction outcomes

The reviewed statements show predominantly organic construction rather than a major corporate acquisition program. Company Financials maps substantial construction spending into acquisition-related fields and sometimes leaves physical capex missing. Treating those fields literally would mischaracterize the allocation record and materially overstate standardized free cash flow. The primary statement’s construction captions establish the economic use of cash. [S1][S14]

Portfolio transactions should still be evaluated separately. WPL received $120 million and $123 million from partial West Riverside ownership sales in 2023 and 2024. Those proceeds are capital recycling, not recurring customer cash. In the third quarter of 2026, WPL transferred $57 million of gas-generation assets to IPL at carrying value. That transaction eliminated on consolidation and created no group-level gain or external cash receipt. [S1][S2][S20]

The non-utility allocation record includes valuation charges and an abandoned development site alongside current venture gains. Excluding a charge from ongoing EPS can improve annual comparison without reversing the capital loss. The same discipline applies to gains: reported valuation improvement does not establish cash realization or repeatability. A symmetric assessment counts both development failures and investment successes when evaluating management’s long-run decisions.

Equity issuance and ownership dilution

September outstanding forward agreements represented approximately 25.58 million potential shares and $1.736 billion of proceeds. The 2025 program accounted for approximately 18.668 million shares at a $66.01 then-current forward price; the 2026 program accounted for approximately 6.913 million at $72.89. Physical settlement is expected, but alternatives are permitted and prices adjust. Some treasury-stock-method dilution is already reflected in diluted EPS. [S2]

The forwards therefore do not imply an additional immediate 9.9% EPS reduction. Their economic significance is that a substantial future share count will accompany cash used to fund earning assets or refinance bridge funding. Analysis must model numerator and denominator together. Issuance can create value when project returns exceed the cost of equity; it still reduces each old share’s ownership percentage.

The current calendar includes up to $650 million of physical settlement during the remainder of 2026 and up to $2.7 billion of common-equity issuance during 2027–2030. Management’s rounded call discussion used approximately $600–$700 million for the imminent settlement and approximately $3.4 billion from the broader starting point. These are horizon differences, not evidence that equity funding suddenly became negligible relative to the expanded capital program. [S2][S4]

The principal dilution issue is external funding rather than compensation. Nine-month equity-plan issuance was 228,260 shares, compared with 929,759 ATM shares, 231,561 direct-plan shares, and 834,811 shares from convertible settlement. Period-end shares increased from 257.137 million to 259.362 million before most outstanding forwards were physically delivered. Compensation issuance is economically relevant but small beside the funding program. [S2]

The company’s share purchases are compensation-trust purchases rather than a shareholder retirement program: Q3 purchases totaled 8,712 shares at $74.49, while shares outstanding continued to rise. Those shares were held in a rabbi trust under deferred compensation arrangements. They should not be presented as an accretive public buyback or as evidence that management is reducing the common share count. [S2]

Federal funding and dividend policy

The federal facilities improve the cost and duration of a portion of utility borrowing. They reimburse up to 80% of eligible project costs, with final maturity in May 2056. Advances can be requested quarterly, subject to conditions, and the availability period can extend to September 2033. A first advance must occur within eighteen months to avoid a DOE termination right. The facilities improve funding capacity without eliminating the need for equity or interim liquidity. [S7]

The dividend policy targets 60–70% of earnings, with management expecting the lower end as investment accelerates. The $2.25 2027 target equals approximately 61% of midpoint guidance and represents approximately 5% growth from $2.14. Slower dividend growth retains incremental capital, but the overall program still requires outside funding. Each quarterly dividend remains subject to board declaration. [S3][S4]

Governance, compensation, and insider evidence

Management’s annual incentive is heavily tied to adjusted EPS, while long-term awards combine relative TSR, absolute net-income growth, project execution, and time-based retention. In 2025, EPS represented 70% of the annual pool. Long-term target value was 35% relative TSR, 35% net-income growth, 5% renewable and storage execution, and 25% service-based units. The annual company performance pool paid 130% of target. [S6]

The absolute net-income component can reward expansion faster than per-share value, while exclusions can soften the incentive effect of development losses. Relative TSR and stock ownership provide offsets. Management’s incentives favor adjusted earnings, absolute growth, and relative share performance, creating a reason to test whether larger investment improves EPS and credit together. The observed financing effort and dividend moderation are constructive, but they do not establish superior allocation outcomes in advance.

Director compensation combines retainers and deferred investment choices. The proxy reports a $300,000 2026 board-service retainer and additional role fees, with stock-exposure encouragement and ownership requirements. Such arrangements create exposure to share performance while differing from discretionary open-market purchases. They should be assessed as compensation policy rather than an independent valuation signal. [S6]

The verified February 2026 Antonio Smyth Form 4 reports code-A awards and a code-F withholding disposition, not a code-P open-market purchase. The latest quarterly filing reports no adoption or termination of specified trading arrangements during the quarter. That does not establish an exhaustive absence of insider purchases or sales across the year. The unverified October director transaction from the draft is not used. [S2][S35]

Verdict: Allocation is coherent for a regulated growth program, with organic investment, cheaper long-duration utility funding, and moderated payout growth. The decisive test remains per-share delivery through issuance, rather than the number of projects announced or compensation shares purchased for a trust.

Changes and Headwinds — Last Two Years

The business environment changed materially during the last two years as large-load development converted a conventional utility investment cycle into a concentrated generation, storage, and financing program. The change is visible in named customers, signed agreements, resource applications, investment schedules, and the new earnings framework. It should be evaluated as a change in operating commitments rather than simply a change in market narrative. [S1][S2][S40]

Results reflect an external demand opportunity implemented through internal contracting, resource planning, financing, and cost decisions; weather, tax law, interest rates, and regulatory approvals remain important external constraints. Management controls site selection, negotiation, procurement, and execution choices. It cannot independently determine customer construction schedules, regional accreditation, public policy, or capital-market prices. Performance evaluation should preserve those responsibilities without excusing controllable cost failures.

Strategy, leadership, and facilities

Important changes in markets, facilities, and management include named data-center service milestones, larger gas and storage plans, continued coal operation, the Barton-led growth strategy, and increased financing complexity. Lisa Barton and CFO Robert Durian explain the current plan; Antonio Smyth joined in April 2025. The inspected evidence does not establish an additional recent leadership transition, and transcript references should not be used to invent one. [S2][S4][S6]

The resource mix now places substantial emphasis on dispatchable capacity alongside renewables and storage. The latest filing describes planned gas additions, existing-unit upgrades, storage, wind development, and refurbishment at different stages. WPL also plans to continue coal operations at Edgewater Unit 5 and Columbia Units 1 and 2 at least through 2030. The economic issue is reliability and cost during the transition, including maintenance and compliance requirements, rather than adherence to a superseded retirement date. [S2]

Specific execution progress includes completed Neenah and Sheboygan gas-path upgrades, approved Bent Tree North wind, additional Whispering Willow storage authorization, and approval of a Wisconsin LNG facility. Pending applications remain distinct from completed assets. Comparing proposed capacity with operating capacity without a status bridge would exaggerate near-term available supply. [S2]

Regulation and customer affordability

Iowa’s electric base-rate stability commitment now extends through the end of 2030. Additional customer payments can spread fixed costs, while permitted tax-credit use can support the earnings bridge. A longer stay-out also increases exposure if costs and financing exceed assumptions. Base-rate stability applies to a defined portion of the customer bill; it should not be described as an unconditional freeze of every bill component. [S1][S3][S4]

The August Iowa review provides concrete adverse evidence. Electric results were within the accepted return range, but residential gas rates were reduced and charter-flight recovery was rejected as inconsistent with the settlement. The separate management-efficiency review addresses severance, outsourcing, and related concerns. One commissioner dissented from portions of the action. The current filing still describes the inquiry, and no verified closing decision was established. [S2][S9]

The gas reduction became effective October 6. The filing rounds the annual amount to $3 million, while the regulator’s release describes more than $2.5 million. These are different levels of precision for the same action. The immediate earnings impact is small relative to the group, but management conduct and regulatory trust can affect future recovery well beyond that annual amount.

Wisconsin progressed from a customer-specific process to a proposed general large-load tariff. The latest filing records June customer-rate approval with conditions and a September tariff application, with a decision expected during the first half of 2027. Proposed financial safeguards are not final universal terms. WPL also expects its next base-rate filing in 2027 for the 2028–2029 test years. [S2][S37]

Policy, costs, and reporting changes

Tax-policy changes made project timing and qualification more consequential. The 2025 filing and subsequent quarterly disclosures discuss accelerated phaseouts and restrictions associated with certain foreign-linked support. Management expects qualifying projects to preserve benefits, but this remains a project-specific execution requirement. No complete public sensitivity establishes how every credit shortfall would be divided among customers, cash funding, and shareholder earnings. [S1][S40]

Wisconsin legislation now requires capacity costs and revenues in fuel plans filed from January 2027. This matters because a utility’s capacity purchases and sales can otherwise produce timing and allocation differences. The latest filing also describes changes in federal generating-unit rules and continued uncertainty from litigation. Those developments affect construction and operating economics; no quantified earnings benefit is assumed without a disclosed company bridge. [S2]

The cost interpretation has changed. October commentary weakens the idea that most higher O&M merely reverses after being pulled forward. However, the primary expense bridge shows that performance-related compensation, maintenance, efficiency programs, and other costs are mixed together. Future analysis should test each category’s recurrence instead of applying either a blanket temporary-cost adjustment or the full observed growth rate indefinitely. [S2][S4]

No material newly adopted accounting policy explains the earnings change; the significant issues are existing regulatory accounting, tax estimates, valuation effects, and intercompany eliminations. The new environmental-credit standard is expected to be adopted in 2028, with management not currently anticipating a material increase in relevant assets or obligations. A subsidiary lease remeasurement eliminated at consolidation and should not be treated as equivalent new group cash investment. [S2]

Verdict: Demand and financing visibility improved, while the operating and regulatory dependencies became more explicit. The most consequential changes are the larger construction peak, longer affordability commitment, conditional funding, and continuing regulatory scrutiny. None can be summarized adequately by calling the environment uniformly constructive or adverse.

Risk Analysis

The most plausible adverse outcome is a mismatch among customer payments, construction, financing, and recovery. These risks interact. Assets can arrive on schedule while customer utilization is delayed; interest and new shares then precede expected cash contribution. A smaller earnings result can coincide with a lower valuation multiple, producing an equity loss much larger than the operating shortfall alone. [S1][S2]

The factors most likely to cause a material stock decline are delayed customer payments, sub-plan recurring EPS, higher financing requirements, adverse regulatory recovery, tax-credit shortfalls, or a lower utility valuation multiple. The physical franchise can remain intact while common holders experience poor returns. Essential service protects demand for the assets more reliably than it protects the price or recovery timing of the common claim. [S1][S2][S3]

A simple scenario demonstrates the interaction. If 2027 EPS were $3.45 and the multiple declined to 17.5 times, the implied value would be approximately $60.4, around 16% below the current quotation before dividends. That combines a roughly 6% earnings shortfall with multiple compression. It is an analytical scenario, not a forecast or a numerical probability of failure.

Funding and regulatory feedback

The federal facilities add a specific contractual link between recovery and liquidity. Certain failures of eligibility, project status, law, or final regulatory recovery can require prepayment of affected borrowing. The 95% cost-recovery test is subject to the agreement’s timing provisions; it should not be described as an immediate quarterly trigger. Mandatory prepayments are scheduled over one year below $1 billion and four years at or above $1 billion. [S7]

Those provisions temper both extremes. The facilities are not unconditional cheap money, but neither does a small adverse order automatically make the full $5.126 billion immediately payable. The amount drawn, affected projects, final orders, and contractual calculation determine exposure. Each utility has its own obligations, and the parent and sister utility are not direct parties to the other borrower’s loan documents. Economic effects can still reach common shareholders through reduced subsidiary distributions or additional capital support.

Public customer disclosure leaves an important uncertainty about net loss allocation. Minimum bills, collateral, termination remedies, and counterparties can protect the utilities, but the complete project-by-project stress bridge is unavailable. Gross transmission guarantees cannot be equated with net shareholder loss. Management descriptions of high-quality customers likewise cannot substitute for collateral enforceability, timing, and survival under stress.

Catastrophic and total-loss pathways

A catastrophic investment loss could arise from a major uninsured operating liability or concentrated stranded investment combined with disallowance and impaired financing access. Gas explosions, plant failures, extended cyber disruption, severe storms, and environmental liabilities can generate immediate cash costs and damage regulatory trust. Insurance and extraordinary-cost recovery provide mitigants, but coverage, deductibles, exclusions, prudence, and timing remain relevant. [S1][S2]

Total loss appears remote under current evidence, but a plausible path would combine extraordinary liabilities, large unrecovered investment, customer failure, and prolonged loss of capital-market access until debt overwhelms the common claim. The essential assets could continue operating through a financial restructuring that materially impairs equity. There is no defensible numerical probability of total loss in the reviewed evidence. [S1][S2][S7]

The strongest practical warning would be simultaneous deterioration in customer cash timing, filed interest coverage, and funding needs. An isolated weather quarter or one small rate adjustment would not establish that sequence. Conversely, repeated reliance on new equity to repair unchanged earning investment would be more concerning than issuance funding newly approved, adequately secured growth.

Verdict: Ordinary drawdown and opportunity-cost risks are substantially greater than extinction risk. The useful stress framework combines project timing, loss allocation, coverage, and capital access. The federal package lowers one funding constraint while preserving borrower obligations and recovery conditions.

Valuation Discussion

Valuation uses the October 30 completed-session price and September filing denominators. Company Financials’ latest retrieved enterprise-value and multiple resources still refer to March 2026 financials and an older price. Their historical information remains useful, but the headline snapshots cannot be presented as synchronized current valuation. Current multiples are reconstructed below. [S17][S18]

Present valuation and denominator discipline

Trailing EPS is approximated as 2025 EPS plus nine-month 2026 EPS less nine-month 2025 EPS. Changing share counts and rounding limit precision. Enterprise value uses existing reported debt and cash. It excludes undrawn federal facilities and unsettled equity proceeds from present cash. Those funding sources will affect future assets, debt, interest, and shares when used; they do not retroactively reduce September leverage. [S1][S2][S3][S11]

The enterprise multiple has a scope limitation. Some equity-method income sits outside the operating-profit-plus-D&A denominator, while the corresponding investments remain within the consolidated common claim. A refined sum-of-parts analysis could separately value ATC and other holdings and align debt with each business. No sufficiently defensible current transaction value supports a precise adjustment here. The limitation warrants a range rather than an invented exact multiple.

Price/book also requires interpretation. A multiple above twice book is not independently evidence of overvaluation when earnings can grow through productive reinvestment. However, a roughly 11% consolidated ROE does not support treating the company as an extraordinary-return franchise. The premium depends heavily on the duration and funding efficiency of growth. A larger construction base can raise book value and reported earnings before demonstrating adequate cash returns to newly issued shares.

Synchronized peer comparison

Prices are synchronized; company earnings definitions are not identical. AEP’s current-year convention is an upper-bound multiple because management expects to meet or exceed the high end. WEC’s current-year multiple should not be compared directly with LNT’s next-year multiple. CMS’s restructuring and Xcel’s liability exposures affect risk; AEP’s transmission scale and diversification differ. [S3][S26][S27][S28][S29][S30][S31][S32][S33]

The evidence supports a moderate LNT earnings premium to several peers, rather than the extreme premium alleged in older analysis. LNT trades approximately 0.6 turn above AEP and two turns above Xcel on verified 2027 midpoints. Its concentrated growth opportunity and Iowa mechanisms can support some premium. Customer concentration, leverage, and tax dependence constrain how much should be assigned.

Peer growth ambitions also matter. AEP’s new framework exceeds its previous growth expectations, and Xcel introduced a 2027 midpoint materially above its current-year midpoint. LNT’s upgrade is therefore part of a broader increase in regulated investment opportunities. A premium cannot rest solely on being a utility with a data-center story; it requires superior timing, protection, funding, or earned economics.

Own-history context and valuation sensitivity

The July 10 price of $76.40 represented approximately 22.4 times the then-current $3.41 guidance midpoint. The September matched close represented approximately 19.7 times that estimate. Today’s price represents 20.9 times the narrowed current-year midpoint and 19.5 times next year’s midpoint. These observations establish compression and recovery using stated estimates. A reliable historical percentile requires a consistent forward-estimate series that was not available. [S3][S10]

A cash-flow valuation could appear more rigorous while depending on less observable inputs. During a construction peak, conventional free cash flow is negative and terminal value dominates. Treating planned investment as indefinitely recurring would understate mature distributable cash; assuming construction drops immediately after 2030 would overstate it. A useful discounted model would need customer ramps, allowed returns, project lives, credit allocation, residual capital needs, and financing scope. The disclosed evidence supports scenario analysis more strongly than a finely calibrated single DCF.

All scenario inputs are analyst assumptions. Revenue and operating margin are secondary checks because pass-through costs, tax credits, AFUDC, investment income, and parent financing can change EPS without proportional changes in operating margins. The EPS figures are controlling scenario outputs, not the product of a fully disclosed customer cost-of-service model. [S2][S3][S4]

The base case incorporates expected issuance and refinancing. It does not subtract management’s dilution bridge a second time. It also does not assume the prospective additional gigawatt immediately increases 2027 earnings. The bull case requires stronger execution or improved later funding efficiency; merely signing more demand with proportionately greater capital needs is insufficient.

At $71.65, a 20-times multiple requires approximately $3.58 of EPS, below the 2027 midpoint. At 19 times, required EPS rises to approximately $3.77, above that midpoint. The quotation therefore embeds meaningful confidence in guidance and a durable upper-teens-to-20-times multiple. It does not require every pipeline opportunity to convert, but it leaves limited room for simultaneous earnings and valuation disappointment.

Compounding $3.68 at 8% for three additional years produces approximately $4.64 in 2030. At 19.5 times, that would imply approximately $90; at 17 times, approximately $79, before dividends. These are long-term sensitivities. They demonstrate how sustained EPS growth can coexist with modest share appreciation if the valuation multiple contracts sufficiently.

Verdict: Current valuation recognizes a credible growth upgrade and requires considerable execution success. The most important valuation variable is sustainable earnings and cash delivered to each fully financed share. Aggregate gigawatts and capital-plan size cannot substitute for that denominator.

Variant Perception

The prevailing narrative appears to be a durable Midwest utility with unusually visible data-center demand and faster earnings growth. Management’s named customers, resource plan, financing agreements, and new outlook support that narrative. No independently verified consensus model or positioning survey was available, so this should be understood as an inferred market narrative rather than a measured consensus EPS forecast or crowding statistic. [S3][S4]

Strongest opposing cases

The strongest bull case is that Alliant has crossed enough commercial and operating milestones to distinguish its opportunity from generic pipeline claims. Customers are taking specified service, buildings are under construction, and management has a concrete funding framework. Cheaper utility borrowing and qualifying credits can preserve affordability while new demand spreads fixed costs. Under those conditions, an established franchise can sustain faster per-share growth without relying on unrestricted pricing power.

The strongest bear case is that investors capitalize the headline growth rate while underweighting composition and funding. Year-to-date operating income has not accelerated, venture valuations and tax benefits support reported income, filed interest coverage has weakened, and construction spending rises sharply before all load matures. A few sites dominate incremental demand. A delay can leave the utility funding resources before receiving the expected customer contribution. [S1][S2][S4]

Thoughtful investor questions on the latest call concerned the EPS base year, equity-horizon reconciliation, capital required per incremental gigawatt, local permitting, tax-credit support for the stay-out, and the difference between firm and curtailable demand. Campanella tested the growth base, Weisel challenged the apparent equity-to-capex relationship, and Crowdell examined the affordability and tax-credit cushion. These questions focus on retained economics rather than the largest possible pipeline number. [S4]

Four assumptions carry most of the valuation:

1. Contracted demand becomes paid service. The constructive case requires billed demand or enforceable minimum payments to follow the resource schedule. Repeated commissioning delays after material irreversible spending would weaken it. Several periods of disclosed payments tracking contractual ramps would undermine the skeptical case.
2. Funding remains inside the EPS bridge. Actual settlements and refinancing should broadly match the disclosed framework. Additional equity for substantially unchanged earning investment would be adverse. Strong per-share growth with stable coverage through the construction peak would be favorable disconfirmation of the bear case.
3. Tax benefits support viable recovery. Project qualification, transfer proceeds, and regulatory allocation must work together. A material recurring shortfall would weaken the favorable thesis. Stable earned returns and collected credit cash without increasing customer burdens would strengthen it.
4. Regulatory trust survives expansion. Final tariffs must preserve enforceable cost allocation, and Iowa findings must remain manageable. Repeated disallowances or adverse management findings would weaken the thesis. Timely prudent recovery with demonstrated existing-customer protection would weaken the adverse case. [S2][S4][S7][S9]

Factor and peer context

The October 30 factor model reports Utilities exposure of 0.880, Market 0.550, LowVolatility 0.425, Growth −0.633, InterestRate −0.301, and Quality −0.291. R-squared is 0.711 and adjusted R-squared 0.702. Residual momentum is 0.00227, residual Sharpe 0.287, and residual volatility 0.0968. These are supplied internal diagnostics; estimation window, scaling, standard errors, and annualization conventions were not provided. [S34]

The factor model’s sector coefficients are statistical exposures, not legal industry classifications. Negative Quality exposure does not establish weak management, and positive GoldPrice exposure does not create a gold-related business thesis. Correlated factors can absorb common movements. The useful conclusion is that utility, market, defensive, and rate relationships explain a substantial share of historical variation under the supplied specification.

The separate short-window peer regression reinforces common movement without establishing a durable hedge ratio. Neither analysis measures investor ownership concentration, crowding, short positioning, or the causal effect of a rate change. Fundamental interest-rate exposure is independently visible in financing needs and expense, but the factor coefficient should not be presented as a precise earnings sensitivity.

Revalidating earlier analytical lessons

The prior proposition that rate-base growth must be assessed after financing is strongly confirmed by management’s explicit equity and refinancing bridge. It should now be applied to the updated plan rather than repeated as an unquantified objection. The first-half utility recovery test received favorable directional evidence, but the stronger claim of recurring cash conversion remains unproven. [S2][S4]

The old remaining-equity boundary is stale because the horizon changed and imminent settlement matters. An unconditional view of Iowa regulation remains contradicted by the open inquiry. The older extraordinary-ROE characterization remains unsupported. The new audit additionally finds that standardized interest fields require reconciliation before calculating coverage; a field name alone does not establish the filed denominator. [S1][S2][S9][S12][S16]

Research-capital adjustments developed for software, semiconductor, or biotechnology companies do not transfer directly to this plant-heavy utility. No material omitted research asset has been established. The bank-specific lesson about securities marks bypassing income likewise does not establish an unrecognized LNT capital problem. The transferable discipline is matching profit, capital, and cash definitions—not importing another industry’s adjustment mechanically.

Contract terms from other utilities also remain company-specific. Another issuer’s construction cash return, collateral package, or minimum-payment disclosure can identify useful questions without establishing Alliant’s rights. Likewise, common price performance tests attribution rather than proving competitive share shifts. The retained lessons are narrower, falsifiable, and anchored to LNT’s own disclosures.

Verdict: The differentiated question concerns the timing, cost allocation, security, and financing of demand that is increasingly real. October improves the favorable case, while earnings composition, coverage, and the recovered peer-correlated quotation preserve meaningful downside if conversion disappoints.

Fact vs. Interpretation

The evidence base includes the 2021–2025 annual filings, current 2026 quarterly filings, selected historical quarterly material, current financing disclosures, the latest proxy, and selected ownership evidence. A complete census of every quarterly filing, material 8-K, proxy, and Form 3/4/5 across the trailing sixty months could not be established from the accessible archive. Accordingly, no claim of exhaustive historical governance or insider coverage is made. Current customer contracts, collateral, and billing schedules remain the most consequential non-public information gaps. [S1][S2][S6][S19][S20][S21][S22][S23][S24][S35][S40][S41]

Open Questions

1. What are billed demand, minimum payments, and collected cash for each major customer relative to contractual ramps? Service milestones do not resolve this revenue bridge. [S4]
2. How much enforceable collateral and termination recovery offsets the $324 million of gross transmission guarantees, and how quickly would it be available after cancellation? [S2]
3. What does the recurring utility earnings bridge look like after fourth-quarter tax reversal, venture normalization, and actual equity settlement? [S2][S3]
4. Which expenditures qualify for the first federal advances, what fees apply, and how much interim liquidity is required before reimbursement? [S7]
5. How much of the projected federal financing benefit is retained temporarily or permanently, versus allocated to customer rates? [S7][S39]
6. Which storage projects qualify for higher credit percentages, and what is the earnings and funding sensitivity if qualification is delayed? [S1][S4]
7. What findings and remediation emerge from Iowa’s management-efficiency inquiry? Does the process affect future cost recovery beyond the small gas-rate reduction? [S9]
8. What final Wisconsin tariff governs minimum demand, termination, security, and residual costs after the initial term? How will early demand revenue flow through fuel recovery? [S2]
9. Does the revised QTS Clinton filing timetable affect customer service, resource commitments, or only the approval sequence? [S4][S5]
10. Can cash conversion and filed interest coverage improve during the 2027–2029 spending peak while ongoing EPS meets the accelerated framework? [S1][S2][S4]
11. How much additional capital and financing accompanies the prospective next gigawatt, including spending beyond 2030? [S4]
12. Will compensation-adjusted and investor ongoing EPS continue to differ, and which development costs will remain excluded from incentive measurement? [S6][S25]

The priority is customer cash and loss allocation, followed by normalized earnings and funding. Another aggregate pipeline headline would be less decision-useful than answers to those questions.

What Must Be True

Bull tests

The favorable thesis requires customer-backed investment to generate the promised per-share growth while preserving recovery and financial resilience. The following numerical warning levels outside company guidance are analyst monitoring rules, not covenants or management forecasts. Additional financing should always be assessed against changes in earning asset scope. [S2][S3][S4][S7]

The company’s 2027 guidance explicitly assumes expected data-center revenue, authorized returns, project execution, cost control, and financing execution. These premises make the monitoring tests evidence-based. They do not justify treating every temporary quarterly deviation as a broken thesis. A delay compensated by enforceable minimum payments has different economics from an uncompensated delay after committed spending. [S2][S3][S4]

Federal funding adds a separate passing condition. Eligible projects must retain qualification and sufficient approved recovery, and the utilities must maintain access to necessary liquidity. A recovery-linked prepayment affecting drawn borrowing would require an updated funding analysis. It would not automatically establish total loss or immediate repayment of every facility dollar. The agreement’s project scope, test date, and installment schedule must remain in the assessment. [S7]

Bear tests

The adverse thesis requires persistent leakage between expanding investment and the common shareholder. It weakens if Alliant delivers annual guidance after tax normalization, converts named service milestones into disclosed customer payments, and preserves credit through settlement. A capital plan that grows while customer cash reduces incremental common-equity intensity would be stronger favorable evidence than a larger plan financed proportionately with new securities. [S2][S4]

The strongest bear falsifier is simultaneous improvement in per-share earnings, collected cash, and financial resilience. Successful construction alone is insufficient because costs can be recovered late. EPS delivery alone is also insufficient if leverage or contingent exposure deteriorates sharply. Conversely, negative construction free cash flow alone does not prove value destruction when approved assets earn adequate returns and funding is incorporated in per-share guidance. [S1][S2][S4]

The favorable thesis would be substantially weakened by a major customer cancellation, repeated material delays after capital commitment, recurring growth below the monitoring threshold, or a recovery and funding failure requiring balance-sheet repair. The adverse thesis would be substantially weakened by two years of verified payment conversion, accelerated recurring EPS, stable credit, and final regulatory outcomes preserving returns. These are observable competing tests rather than assumptions that average each other away. [S2][S3][S4][S7][S9]

Verdict: The franchise supports a credible opportunity to compound faster, but the evidence must progress from contracts and construction into collected returns for each fully financed share. The decisive documents are the current quarterly filing, earnings and guidance release, federal financing disclosure, and Iowa regulator’s findings.

Public source appendix

• S1: Alliant Energy 2025 Form 10-K — primary_SEC_filing; published 2026-02-20; Items 1, 1A, 7 and 8; regulatory schedule pp. 38–39; construction schedule p. 42; consolidated statements pp. 51–53; interest expense lines 2042–2048; AFUDC components lines 3121–3127.
• S2: Alliant Energy third-quarter 2026 Form 10-Q — primary_SEC_filing; published 2026-10-30; Statements pp. 4–12; Notes 1–8, 12–14; MD&A pp. 30–39; O&M bridge lines 2031–2043; financing lines 2047–2062; capital structure lines 2071–2093; trust purchases and trading arrangements pp. 40–41.
• S3: Alliant Energy third-quarter 2026 results and 2027 guidance — primary_company_release_filed_with_SEC; published 2026-10-29; Exhibit 99.1; EPS reconciliation, guidance assumptions, dividend target and capital schedule; lines 19–102.
• S4: Company Financials — Alliant Energy third-quarter 2026 earnings-call transcript — third_party_transcript_of_management_commentary; published 2026-10-30; October 30 Barton and Durian prepared remarks; Q&A on growth bases, equity horizons, O&M recurrence, permitting, tax credits, incremental capital and Clinton filing timing.
• S5: Company Financials — Alliant Energy second-quarter 2026 earnings-call transcript — third_party_transcript_of_management_commentary; published 2026-07-31; July 31 prepared remarks and Q&A; customer milestones, remaining equity, generation planning, and expected later-2026 Clinton customer-rate filing.
• S6: Alliant Energy 2026 definitive proxy statement — primary_SEC_proxy; published 2026-03-31; Director compensation pp. 17–18; ownership p. 19; adjusted-EPS reconciliation p. 22; annual incentive p. 25; long-term awards pp. 26–29.
• S7: Alliant utility federal loan agreements — October 2026 Form 8-K — primary_SEC_financing_disclosure; published 2026-10-28; Items 1.01 and 2.03; separate borrower obligations, limits, eligible-cost reimbursement, draw conditions, pricing, maturity and mandatory prepayment; lines 212–264.
• S8: Department of Energy closes Alliant loan package — primary_federal_government_release; published 2026-10-28; October 28 financial-close announcement; $5.1 billion package, planned capacity and projected customer savings.
• S9: Iowa commission subsequent review and IPL management-efficiency investigation — primary_regulator_release; published 2026-08-26; Electric and gas return findings, residential gas reduction, charter flights, severance, outsourcing, partial dissent and docket INU-2026-0002; lines 14–27.
• S10: Company Financials — Alliant Energy five-year daily price history — third_party_market_price_data; publication date unavailable; Two cursor pages; 1,256 split-adjusted daily observations; range, event-map, inter-report return and peer-regression calculations.
• S11: Company Financials — Alliant Energy latest completed-session price — third_party_market_price_data; published 2026-10-30; October 30, 2026 daily resource; close $71.65.
• S12: Company Financials — Alliant Energy annual income statements — third_party_standardized_financials_with_definition_limitations; publication date unavailable; FY2021–FY2025 income and share data; material values reconciled to filings; standardized interest fields differ from filed expense.
• S13: Company Financials — Alliant Energy annual balance sheets — third_party_standardized_financials; publication date unavailable; FY2021–FY2025 assets, net plant, equity, funded debt, cash and shares; matched to annual filings.
• S14: Company Financials — Alliant Energy annual cash-flow statements — third_party_standardized_financials_with_classification_limitations; publication date unavailable; FY2021–FY2025 cash flows; construction mapped to acquisition-related fields and missing capex require primary-statement correction.
• S15: Company Financials — Alliant Energy profitability ratios — third_party_standardized_ratios; publication date unavailable; Annual ROE and available 2022–2023 ROIC; later missing ROIC values.
• S16: Company Financials — Alliant Energy credit ratios — third_party_standardized_ratios_with_definition_limitations; publication date unavailable; Annual debt, coverage and capitalization; standardized interest denominator compared with filed expense before use.
• S17: Company Financials — Alliant Energy enterprise-value snapshot — third_party_valuation_snapshot_stale; publication date unavailable; Latest retrieved resource has March 31, 2026 period end; used to identify staleness.
• S18: Company Financials — Alliant Energy valuation-multiple snapshot — third_party_valuation_snapshot_stale; publication date unavailable; March 31, 2026 financial period and $71.76 snapshot price; current multiples reconstructed independently.
• S19: Alliant Energy 2024 Form 10-K — primary_SEC_filing; published 2025-02-21; Items 7–8; statements, construction, cash receipts, segment expense and interest comparisons.
• S20: Alliant Energy 2023 Form 10-K — primary_SEC_filing; published 2024-02-16; Consolidated statements pp. 47–50; filed 2021–2023 interest and common income, lines 1904–1944; construction and receivable receipts, lines 2057–2067.
• S21: Alliant Energy 2022 Form 10-K — primary_SEC_filing; publication date unavailable; Items 1, 7–8; 2021–2022 income, preferred dividends, equity and financial statements.
• S22: Alliant Energy 2021 Form 10-K — primary_SEC_filing; published 2022-02-18; Items 1, 1A, 7–8; consolidated income p. 43, balance sheet p. 44, operating risks and regulatory accounting.
• S23: Alliant Energy second-quarter 2026 Form 10-Q — primary_SEC_filing; published 2026-07-31; First-half statements and MD&A; forward equity, financing and transmission guarantees.
• S24: Alliant Energy first-quarter 2026 Form 10-Q — primary_SEC_filing; published 2026-05-01; Quarterly statements, regulatory developments, financing and customer-demand disclosures.
• S25: Alliant Energy 2025 year-end earnings presentation — primary_company_presentation; publication date unavailable; Slides 3–4, 13–14; financial highlights, prior outlook and 2016–2025 GAAP/ongoing reconciliation.
• S26: WEC Energy Group third-quarter 2026 earnings release — primary_peer_company_release; published 2026-10-29; Pages 1–2; $5.60–$5.64 guidance, weather-normal deliveries, specified large-customer exclusions and geographic footprint.
• S27: CMS Energy third-quarter 2026 results and guidance — primary_peer_company_release; published 2026-10-27; Opening release; 2026 and 2027 adjusted EPS, restructuring and financial-measure definitions; lines 267–286.
• S28: American Electric Power third-quarter 2026 earnings presentation — primary_peer_company_presentation; published 2026-10-28; Slides 5–8; 2027 operating EPS $6.75–$7.05, current-year high-end expectation, growth framework, transmission scale and ESA/LOA distinction.
• S29: Xcel Energy third-quarter 2026 Form 10-Q — primary_peer_SEC_filing; published 2026-10-29; MD&A pp. 33–34; 2026 ongoing EPS $4.10–$4.16 and 2027 $4.48–$4.62; financing and liability context.
• S30: Company Financials — WEC matched daily prices — third_party_market_price_data; publication date unavailable; 37 daily observations; September 10 close $105.35 and October 30 $116.07.
• S31: Company Financials — CMS matched daily prices — third_party_market_price_data; publication date unavailable; 37 daily observations; September 10 close $67.68 and October 30 $70.10.
• S32: Company Financials — AEP matched daily prices — third_party_market_price_data; publication date unavailable; 37 daily observations; September 10 close $123.47 and October 30 $130.21.
• S33: Company Financials — Xcel matched daily prices — third_party_market_price_data; publication date unavailable; 37 daily observations; September 10 close $75.41 and October 30 $79.82.
• S34: the factor model — supplied_internal_statistical_diagnostic; published 2026-10-30; Supplied October 30 exposures, residual signals and diagnostics; methodology, window and scaling unspecified.
• S35: Antonio Smyth February 2026 Form 4 — primary_SEC_ownership_filing; published 2026-02-23; Table I; February 19 code-A awards and code-F withholding; RSU footnote and February 23 signature.
• S36: Company Financials — Alliant Energy company profile — third_party_company_profile_with_description_limitations; publication date unavailable; Exchange-qualified identity and profile; descriptive fields checked against current filings because generated profile text contains stale or inconsistent details.
• S37: Wisconsin PSC announcement on Alliant data-center service — primary_regulator_announcement; published 2026-05-07; May 7 announcement, pp. 1–4; transparency, termination charges, financial safeguards, reporting and broader tariff direction.
• S38: Alliant Energy 2025 results release and accompanying Form 8-K — primary_company_release_filed_with_SEC; published 2026-02-19; Exhibit 99.1; annual and fourth-quarter GAAP/ongoing EPS, including Q4 2025 ongoing EPS $0.60; prior construction schedule.
• S39: Department of Energy Alliant project summary — primary_federal_government_project_summary; publication date unavailable; Project, energy-impact and economic-impact sections; loan-supported resources and conditional projected annual interest/customer savings.
• S40: Alliant Energy third-quarter 2025 Form 10-Q — primary_SEC_filing; publication date unavailable; MD&A customer demand, regulatory proposals, tax legislation and financing; distinguishes then-pending rates from later outcomes.
• S41: Alliant Energy second-quarter 2024 Form 10-Q — primary_company_hosted_SEC_filing; publication date unavailable; Consolidated statements and regulatory discussion; Lansing charge and historical construction/recovery context.
• S42: IPL August 2026 debt-offering Form 8-K — primary_SEC_financing_filing; published 2026-08-21; Item 8.01; $500 million 5.100% senior debentures due September 30, 2031.