DUK Duke Energy 10-Q 2026-09-30 section summaries

Duke Energy Corporation — Q3 and nine months ended September 30, 2026

Dollar amounts in millions unless otherwise stated.

Consolidated results

Revenue grew about 6.6% in Q3 and 6.5% in 9M. Higher fuel and purchased-power costs partly offset the revenue growth; lower operation and maintenance expense supported operating income. Nine-month results also benefited from a $405 gain on sales of other assets, including the $368 gain Duke recorded on Piedmont’s Tennessee business. That sale generated $2,501 in proceeds.

Reportable segments

For 9M 2026 versus 9M 2025, EU&I revenue was $23,800 versus $22,365 and segment income was $4,342 versus $4,128; GU&I revenue was $2,172 versus $2,027 and segment income was $523 versus $329; Other recorded losses of $714 versus $713. GU&I’s improvement included asset-sale gains. Segment income reconciles to common-stockholder net income; consolidated net income also reflects noncontrolling interests and preferred dividends.

Cash flow, balance sheet and capital investment

Capital spending substantially exceeded operating cash flow. Financing cash inflow was $3,130, including $9,554 of long-term debt issuance, $6,412 of long-term debt redemptions and $2,839 of noncontrolling-interest contributions; dividends paid were $2,555. Cash, cash equivalents and restricted cash were $558 at September 30, versus $363 at the start of the year.

No separate consolidated line for intangible assets other than goodwill was presented. The three disclosed debt lines totaled $92,789, versus $89,836 at year-end. Duke extended its $10 billion Master Credit Facility to March 2031; $7,972 of capacity was available at September 30. Current maturities totaled $6,116, and the company expects to fund maturities with cash and additional borrowings.

Portfolio, financing and significant developments

• Brookfield’s first Florida Progress investment closed in March: $2.8 billion for a 9.19% interest. Duke and Progress retained control, so no gain or loss was recorded; the transaction increased equity by $1.9 billion net of about $30 million of transaction costs. Additional investments are scheduled through June 2028 toward the $6 billion commitment. Proceeds are intended to support the capital plan and reduce planned debt and common-equity issuance.
• Piedmont sold its Tennessee business for approximately $2.5 billion. Piedmont recorded a $652 million pretax gain; the transaction reduced its assets and debt, and its proceeds supported Duke’s capital plan.
• Duke issued $2.0 billion of equity units in August. Distributions are 7.75% annually; Duke elected to defer $159 million of contract adjustment payments, which accrue at that rate. Depending on settlement terms and share price, the purchase contracts could require up to 16.5 million shares, or 29.9 million upon specified early settlement.
• In April, Duke settled $1.7 billion of 4.125% convertible notes due 2026, paying principal in cash and issuing 1.4 million shares for the conversion premium. It also issued $1.5 billion of 3.000% convertible notes due 2029.
• Duke agreed to sell up to $3.1 billion of net tax credits expected to be earned in 2025–2028, with proceeds expected in 2026–2029. Net realizable value is expected to flow back to customers over time, subject to regulatory approval.
• Duke canceled its Carolina Long Bay offshore-wind lease effective September 23, recognizing a $129 million receivable and derecognizing a $21 million bid-credit obligation. The settlement was received in October.

Regulation, investment and risks

Duke’s utilities continued major generation and grid investment. Projects include hydrogen-capable combined-cycle and peaking plants in the Carolinas and Indiana’s Cayuga replacement project, with Cayuga estimated at approximately $3.3 billion plus actual AFUDC. Duke Carolinas and Duke Progress target combining into one utility on January 1, 2027, subject to the approved customer protections and savings commitments. North Carolina settlements for 2025 rate cases provided net increases of $496 million for Duke Carolinas and $338 million for Duke Progress over two years, with a 9.8% authorized ROE for each; commission approval remained pending.

The Florida storm-recovery charge for Hurricanes Debby, Helene and Milton was removed in February 2026 after $903 million of costs were recovered; the Florida commission approved a $91 million refund of overcollections. Duke Carolinas and Duke Progress also received approval to recover under-recovered fuel costs of $500 million and $309 million, respectively, over 19 months.

Asset retirement obligations were $9,332 at September 30, including $4,986 for nuclear decommissioning and $3,983 for ash-impoundment closure. Environmental remediation reserves were $95, versus $72 at year-end; additional site costs remain uncertain. Duke’s recurring fair-value net assets were $14,321, while the fair value of long-term debt, including current maturities, was $79,858 versus book value of $90,448. Credit-contingent derivative provisions could require $195 of additional collateral or letters of credit if triggered.

Duke Energy — nine months ended September 30, 2026

Results benefited from regulated rate recovery, customer and load growth, improved weather and lower storm-related O&M. Higher fuel and purchased-power costs, depreciation and interest expense partly offset those gains. Duke completed two transactions that generated approximately $5.3 billion in cash proceeds to support its capital plan: a 9.19% minority investment in Florida Progress for approximately $2.8 billion, and the sale of Piedmont’s Tennessee business for approximately $2.5 billion.

Earnings

Q3 GAAP and adjusted EPS were both $1.99, compared with $1.81 in Q3 2025. For the first nine months, GAAP EPS was $5.34 versus $4.81, and adjusted EPS was $5.35 versus $4.81.

The earnings reconciliation included +$189M of legal and regulatory settlement charges, −$171M of asset-sale gains and −$13M from discontinued operations in 2026. The Tennessee sale gain contributed to reported growth, while legal and regulatory settlement charges partly offset it.

Business-unit results

The following nine-month comparisons reflect the periods ended September 30; dollar amounts are in millions. The operating-unit figures are shown alongside the broader reported segment results.

Piedmont’s results included a $652M gain on the Tennessee-business sale, which closed March 31, 2026; GU&I’s operating-income increase also reflects a $374M gain on the sale, net of allocated goodwill. Progress Energy’s 2026 net income included $70M attributable to noncontrolling interests (NCI) following the Florida Progress investment; income attributable to Progress Energy was $1,986M, versus $1,910M.

EU&I’s Q3 revenue was $8.747B versus $8.180B; operating income was $2.734B versus $2.314B, and segment income was $1.817B versus $1.658B. Segment-income growth was slower for the nine months than in Q3. Q3 GU&I revenue was $390M versus $394M, operating income $17M versus $12M, and segment loss $19M versus a $26M loss. Other’s Q3 net loss was $247M versus $225M.

EU&I revenue growth reflected rate increases, higher weather-normal retail volumes, rider revenues and improved weather, partly offset by lower Florida storm-recovery revenue. For the nine months, fuel revenue increased $758M, rate-case pricing $485M, rider revenue $229M and weather-normal retail sales volumes $224M; Florida storm-recovery revenue declined $602M. EU&I fuel and purchased-power expense rose to $7.129B from $6.326B, while O&M fell to $4.397B from $4.746B, mainly on lower Florida storm amortization. Depreciation and amortization rose to $4.532B from $4.184B, and interest expense to $1.765B from $1.587B. Winter Storm Fern, nuclear outages and legal-settlement costs partly offset O&M savings.

In other businesses, Indiana’s revenue growth reflected fuel revenues and 2024 rate-case pricing, partly offset by lower wholesale revenue after contracts expired; lower rider amortization and plant maintenance reduced O&M. Florida’s lower storm-recovery revenue was partly offset by new rates and riders, while lower storm amortization reduced O&M. Duke Energy Ohio’s growth included rate-case pricing, natural-gas pass-through costs and retail riders. The Tennessee sale also reduced Piedmont revenue and expenses; higher commodity prices lifted both revenue and natural-gas costs. GU&I’s effective tax rate rose to 35.6% from 19.0%, primarily because goodwill associated with the sale was nondeductible.

Customer, load and cash-flow trends

EU&I electricity sales were 77,147 GWh in Q3 versus 72,880 GWh, and 207,043 GWh for nine months versus 202,283 GWh. Net proportional generating capacity was 55,944 MW, up 674 MW year over year. Demand growth reflects population and economic development, electrification and data centers; data-center agreements include financial protections intended to align infrastructure costs with large-load customers and limit effects on other customers. Winter Storm Fern drove record winter peak demand across the Carolinas, and August heat set a new Carolinas summer-demand record; service was restored to affected customers within 48 hours.

Lower operating cash flow mainly reflected a $1.5B deterioration in cash flows from other assets and liabilities, including higher deferred fuel and purchased-power costs and severe-winter storm restoration costs. Working-capital cash use improved to $1.282B from $1.595B. Financing cash flow included $2.839B of NCI contributions from the Florida Progress investment. Investing cash flow included $2.501B of Tennessee-sale proceeds; the prior-year period included $559M from the Commercial Renewables disposal.

At September 30, 2026, Duke reported $451M of cash on hand and $8.0B available under its $10B Master Credit Facility, whose termination date was extended to March 2031. Cash, cash equivalents and restricted cash totaled $558M, compared with $739M a year earlier. An agreement provides for sales of up to $3.1B of net tax credits through 2029; Duke expects their net realizable value to be passed to customers over time through regulatory processes. Brookfield’s planned Florida Progress investment totals $6B for an anticipated 19.7% indirect interest in Duke Energy Florida; Brookfield indicated it intends to increase its December 2026 investment from $200M to $1.2B, with the remaining $2B expected in 2027.

Regulation, strategy and risks

Duke advanced the planned combination of its Carolinas electric utilities, targeted for January 1, 2027, following FERC authorization and state approvals. It received approvals for new generation projects in Anderson County, Marshall and Person County; revised rates took effect in South Carolina electric territories and Duke Energy Kentucky gas. The company also reached settlements in the Carolinas’ 2025 rate cases and Winter Storm Fern proceedings. Robinson’s renewed license extends operations through 2050, and Duke reported a record systemwide nuclear fleet capacity factor in 2025.

EPA’s 2026 coal-combustion-residual proposals could rescind or defer some requirements for legacy impoundments and other sites; Duke is assessing potential effects and expects to seek recovery of compliance costs through rates and wholesale contracts. EPA’s partial repeal of power-plant greenhouse-gas requirements removed carbon-capture-based requirements but retained efficiency standards for certain turbines; further repeal proposals, challenges and litigation leave outcomes uncertain. Duke cited potential supply-chain and cost risks from geopolitical developments, trade restrictions on rare-earth materials and technologies, and tariffs. In Indiana, new legislation requires Duke Energy Indiana to file its first multi-year rate plan between November 15 and December 15, 2026; Ohio legislation also permits multi-year natural-gas rate plans.

Item 3 reports no new market-risk metrics or developments. It refers readers to Duke Energy’s 2025 Form 10-K, Item 7, for the registrants’ detailed quantitative and qualitative market-risk disclosures.

Disclosure Controls and Internal Control over Financial Reporting

As of September 30, 2026, management, including the CEO and CFO, concluded that the Duke Energy Registrants’ disclosure controls and procedures were effective in providing reasonable assurance. During the quarter ended September 30, 2026, there were no changes in internal control over financial reporting that materially affected, or were reasonably likely to materially affect, those controls.

Duke Energy identifies no new risk factors or financial metrics in this section. It refers readers to the risks described in its 2025 Form 10-K and in supplemental risk factors filed by Duke Energy Carolinas on May 29, 2026, and Duke Energy Progress on August 27, 2026. Those risks are incorporated by reference and could materially affect the Duke Energy Registrants’ financial condition or future results.

For the three months ended September 30, 2026, no Duke Energy director or officer adopted, terminated, or modified a Rule 10b5-1 or non-Rule 10b5-1 trading arrangement. This section reports no financial results or other business developments.