Duke Energy

FY2025 Financial Architecture

FY2025 segment income was $5.337B in Electric Utilities & Infrastructure and $559M in Gas Utilities & Infrastructure, offset by a roughly $985M Other loss at the holding-company/corporate layer. [S2]

This is a useful reminder: regulated subsidiary earnings must ultimately support parent interest, corporate expense and financing. Revenue size alone says little about equity return.

Latest Financial State — Q2 2026

Q2 2026 operating revenue was $7.592B and net income was $1.145B. Reported EPS was $1.38 and adjusted EPS $1.43. [S6][S54]

Duke reaffirmed 2026 adjusted EPS guidance of $6.55–$6.80 and 5%–7% long-term adjusted EPS growth through 2030. [S6]

The Two Reportable Segments

EU&I contains regulated electric utilities in the Carolinas, Florida and Midwest. FY2025 revenue was $29.357B, segment income $5.337B and capex $12.553B. [S2][S51]

GU&I contains Piedmont Natural Gas, Ohio/Kentucky gas distribution and related storage/pipeline interests. FY2025 revenue was $3.003B, segment income $559M and capex $1.114B. [S2][S51]

Electric is clearly the economic center of Duke, supporting its Electric Utilities GICS classification.

How Regulated Utility Earnings Work

A regulated utility receives an exclusive service territory but does not have unrestricted pricing power. Regulators set a revenue requirement intended to recover prudent cost and offer an opportunity to earn a fair return.

A simplified revenue requirement is:

The allowed return is not guaranteed. Cost overruns, lag, disallowances or weak operations can cause under-earning.

Rate Base Is Not Revenue

Rate base is the regulatory investment base on which the utility may earn a return. It is neither annual revenue nor total corporate assets.

A $1B grid project can be financed and placed in service, then recovered over years through depreciation and return. The customer does not pay the entire construction cost in one year's bill.

Why Capital Spending Creates Earnings Growth

For most companies, capex is mainly a cash burden. For a regulated utility, approved capex can also grow future earnings base. Duke's $103B plan is expected to drive about 9.6% earnings-base growth, while EPS growth is guided at 5%–7%. [S3]

The gap reflects financing cost, depreciation, O&M, regulatory timing and parent-level effects.

Capital Plan Mix

Duke says nearly 60% of its five-year investment plan supports new generation while close to 40% expands and modernizes the grid. [S4]

That mix tells the current story: demand is growing quickly enough that Duke needs both more megawatts and more wires/substations to deliver them.

Customer Mix and Load Growth

FY2025 EU&I revenue included roughly $25.5B of retail electric revenue and $2.4B of wholesale electric revenue. [S52]

Residential growth remains important, but the step-change is commercial/industrial load from data centers, semiconductor projects and advanced manufacturing.

Data Centers Changed Planning

By Q1 2026 Duke said it had secured 7.6GW of economic-development projects under Electric Service Agreements. [S17]

A single hyperscale campus can require hundreds of megawatts. That changes utility planning from incremental growth to large discrete projects with transmission/generation consequences.

Customer Protection Plus

Large loads are valuable only if existing customers are protected from speculative buildout. Duke's Customer Protection Plus framework and October 2026 North Carolina settlement use contractual protections, minimum bills and other mechanisms to make large-load customers carry appropriate cost. [S15][S16]

The goal is to turn data-center growth into lower average system cost rather than stranded assets.

Electric Utility Footprint

Duke's current regulated electric footprint spans the Carolinas, Florida, Indiana and Ohio/Kentucky. The two Carolinas utilities remain separate through 2026 and are scheduled to combine Jan. 1, 2027. [S15]

State commissions will continue setting retail rates independently even after the legal utility combination.

Duke Energy Carolinas

DEC is the legacy Carolinas core: about 2.9M customers and 20.8GW of capacity across NC/SC in company disclosures. [S12] It contains major nuclear, hydro and gas assets and sits directly in high-growth Charlotte/Upstate/Triad corridors.

Duke Energy Progress

DEP, inherited through Progress Energy, serves about 1.8M customers with 13.8GW across NC/SC. [S12] It includes Brunswick, Harris and Robinson nuclear assets. DEC/DEP already jointly dispatch generation; the 2027 combination seeks deeper cost/regulatory efficiency.

Duke Energy Florida

Florida is a high-growth and high-storm-risk jurisdiction. Grid hardening includes stronger transmission structures, underground distribution and self-healing automation. By September 2026 Duke said ~82% of DEF customers were served by self-healing technology. [S34]

Florida Brookfield Financing

Brookfield agreed to invest $6B for an eventual 19.7% indirect Florida Progress interest. The first closing on Mar. 3, 2026 issued 9.19% for about $2.8B. [S18][S19]

Duke retains control. The transaction monetizes a minority stake to finance broader growth without selling the operating platform.

Duke Energy Indiana

Indiana is a major Midwest regulated electric business with an historically coal-heavy fleet and industrial customer base. Its challenge is replacing aging generation while preserving low-cost reliability and accommodating new large loads.

Duke Energy Ohio & Kentucky

Duke cites roughly 910,000 electric and 560,000 gas customers in Ohio/Kentucky. [S24] This is operationally multi-utility, but the parent remains GICS Electric Utilities because electric assets dominate corporate economics.

Natural Gas Utilities

After selling Piedmont's Tennessee LDC, Duke still serves about 1.6M gas customers in NC, SC, OH and KY. [S23] Gas utilities earn regulated returns on pipes, meters, safety upgrades and capacity rather than commodity price speculation.

Piedmont: Acquire, Then Refocus

Duke acquired Piedmont Natural Gas in 2016, adding about one million gas customers. [S22] In March 2026 it sold only the Tennessee local-distribution business to Spire for $2.48B. [S21]

This is portfolio refocusing, not a full natural-gas exit.

Nuclear Fleet

Duke operates six nuclear sites: Brunswick, Catawba, Harris, McGuire, Oconee and Robinson. [S26][S27] In 2025 the fleet achieved a 96.9% capacity factor, a company record. [S25]

Existing nuclear is central because it supplies firm carbon-free power with low fuel-price volatility and existing transmission.

Nuclear Life Extension and New Nuclear

Oconee received subsequent license renewal that extends its units into roughly 2053–2054. [S26] Duke is also evaluating new-nuclear options in the Carolinas without yet treating them as committed capacity. [S28]

Life extension and new build are economically different decisions and should not be collapsed.

Natural Gas Generation

Duke is adding dispatchable gas while retiring coal because system planning requires both energy and dependable peak capacity. South Carolina approved an approximately 1.4GW Anderson County combined-cycle facility for service around 2031. [S29]

Renewables, Storage and Hydro

Duke is expanding regulated solar and storage. At the former Allen coal site, a 50MW / four-hour battery entered service and a 167MW / four-hour project is planned; the Carolinas plan envisions 6.55GW of batteries by 2035. [S30]

Hydro and pumped storage add long-duration flexibility, especially Bad Creek.

Coal Transition

Duke has targeted coal below 5% of generation by 2030 and full exit by 2035, subject to approvals/reliability. [S31]

The replacement is a portfolio—not simply solar: nuclear life extension + gas + solar + batteries + hydro + efficiency + grid.

Grid and Transmission

Nearly 40% of the $103B plan supports grid expansion/modernization. [S4] Transmission is particularly critical because new generation and large data centers can be geographically distant. In September 2026 DOE selected Duke for $50M support for advanced Carolinas transmission upgrades. [S32]

Storm Resilience

Florida illustrates resilience economics. Hardening and self-healing systems can reduce outage minutes and restoration cost, but require upfront regulated capital. [S33][S34]

This is not cosmetic reliability spending: outage performance influences regulators, customers and future rate-plan support.

Affordability Is a Binding Constraint

A regulated utility cannot maximize capex without regard to customer bills. Regulators can rephase or disallow spending and customer affordability can become politically and financially binding.

Duke repeatedly pairs growth plans with tax credits, merger savings, large-load protections and cost reductions to limit bill impact. [S3][S35]

How Duke Finances the $103B Plan

Funding sources include operating cash, utility/parent debt, equity, hybrid securities and portfolio monetization.

Recent examples: $2.8B Brookfield first closing, $2.48B Tennessee gas sale and $1.75B August 2026 equity units. [S19][S21][S45]

The financing mix matters because higher leverage raises interest expense and can weaken credit metrics.

Dividend and Capital Tension

Duke has paid a common-stock cash dividend for 100 consecutive years. [S47] The quarterly dividend was raised to $1.085 in July 2026. [S46]

A large dividend and a $103B capex program compete for cash, making external financing a structural part of the growth model.

The Regulated Utility Flywheel

Duke's economic flywheel is not primarily customer-price expansion.

It is:

The loop works only if regulators and customers remain convinced that investment is necessary and affordable.

A utility can destroy the flywheel by overbuilding, losing regulatory trust or weakening its credit profile.

Why Load Growth Is So Valuable

For years, electric utilities often grew earnings mainly by replacing aging infrastructure and slowly expanding rate base.

Large-load growth creates a second engine.

A new high-load-factor customer can:

• use existing generation/grid more intensively;
• support new rate-base investment;
• spread fixed cost across more sales;
• create local tax/economic activity.

But only if the customer actually arrives and remains.

This is why data-center contract design is now a balance-sheet issue.

Energy Sales vs Capacity Needs

Annual electricity energy and peak capacity are different.

A data center can operate near 24/7, creating high annual MWh demand.

A residential system may peak on very hot summer afternoons or cold winter mornings.

Duke must plan for both:

A resource that produces inexpensive energy at noon may contribute less dependable capacity at a winter evening peak.

Why Coal Retirement Is Financially Complex

A coal plant can be physically retired before its remaining regulatory book value is fully depreciated.

Regulators must determine how remaining balances and environmental/remediation costs are recovered.

Potential tools include:

• accelerated depreciation;
• securitization;
• regulatory assets;
• replacement-resource savings.

Therefore, the timing of coal retirement affects both emissions and customer-rate trajectories.

Nuclear as an Existing-Asset Option

Duke's nuclear fleet is particularly valuable in a high-load-growth scenario because replacement capacity would be enormous.

At roughly 10 GW-class scale, an equivalent replacement portfolio might require:

• multiple gas plants;
• very large renewable + storage build;
• new transmission;
• major land/interconnection.

This does not make nuclear costless. It makes existing plants strategically difficult to replace.

New Nuclear: Option Value Before Commitment

Evaluating sites, licensing pathways and technologies creates option value.

Duke does not need to commit billions to a final plant immediately to gain value from:

• site control;
• early NRC work;
• vendor knowledge;
• transmission studies.

If load grows faster or gas/carbon constraints tighten, a mature nuclear option becomes more valuable.

If load slows or technology costs disappoint, Duke can delay a final investment decision.

Gas Generation and Fuel Infrastructure

New gas generation is only as reliable as fuel delivery.

System planning must evaluate:

• pipeline capacity;
• firm transportation;
• winter gas/electric competition;
• storage;
• dual-fuel capability where applicable.

A gas turbine with no assured fuel at peak is not fully firm capacity.

Grid as the Hidden Growth Constraint

Generation headlines attract attention, but grid equipment can become the binding constraint.

Large transformers and high-voltage equipment may have long lead times.

Siting a transmission line can take longer than ordering a power plant.

Duke's nearly 40% grid allocation reflects the fact that new megawatts have no value if they cannot be moved reliably to customers.

Regulatory Diversity as Portfolio Risk Management

Duke operates across multiple commissions.

That diversification can be valuable:

• one unfavorable rate case does not determine the entire company;
• customer/load trends differ by state;
• regulatory mechanisms differ.

But it also creates complexity.

Duke cannot apply one financing or rate-recovery structure everywhere.

The company must maintain constructive relationships across multiple political and regulatory environments simultaneously.

The Parent / Utility Financing Stack

Duke Energy Corporation is a holding company above regulated utility subsidiaries.

Cash can move through:

• subsidiary earnings/dividends;
• parent debt;
• utility debt;
• common equity;
• hybrid securities;
• asset sale proceeds.

Credit-rating agencies evaluate both utility and parent leverage.

Excess parent debt can weaken the overall credit profile even if operating utilities are healthy.

Why Minority Capital Can Be Attractive

The Brookfield Florida transaction provides an example.

Duke can: 1. sell a minority economic interest at an agreed value; 2. retain operating control; 3. receive billions of dollars of cash; 4. reinvest the cash in other regulated projects.

This can be less dilutive than issuing the same amount of parent common equity, depending on valuation and financing conditions.

The cost is that Duke gives up a share of future DEF earnings to the noncontrolling investor.

Customer Affordability as a Growth Constraint

A regulated utility cannot maximize investment without considering the customer's total bill.

Duke's customer bill can be influenced by:

• new capital;
• fuel;
• storm recovery;
• taxes;
• energy efficiency;
• federal tax credits;
• large-load contributions.

The strongest growth plan is one where system benefits offset enough of the capital burden that regulators continue to approve investment.

Dividend vs Growth

Duke's century-long dividend history attracts income-oriented investors.

But a $103B capex plan creates substantial equity needs.

The company therefore manages a three-way trade:

A dividend can remain stable/grow even while share count or hybrid capital rises.

Investors should analyze per-share growth after financing—not only total regulated earnings-base growth.

Interest-Rate Sensitivity

Utilities finance long-lived assets with large amounts of debt.

When interest rates rise:

• new debt costs more;
• equity required return can rise;
• customer revenue requirement increases;
• project economics may change.

Regulated recovery provides long-run protection, but timing matters.

A high-growth utility can face near-term cash pressure even when all investment is ultimately recoverable.