# Duke Energy Corporation (NYSE: DUK) — Business, Risks and Management's Discussion

Duke Energy Corporation, CIK 0001326160. Fiscal year ends December 31. Current reporting
period: second quarter of fiscal 2026, ended June 30, 2026.

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## Business

*From the fiscal 2025 Annual Report on Form 10-K (accession 0001326160-26-000014).*

Duke Energy is a regulated electric and natural gas utility holding company headquartered in
Charlotte, North Carolina. It sells electricity to approximately 8.7 million retail customers
across a roughly 90,000-square-mile service territory spanning six states in the Southeast and
Midwest with an estimated population of 27 million, and distributes natural gas to
approximately 1.8 million customers in the Carolinas, Tennessee, Ohio and Kentucky. Essentially
all of its revenue comes from rate-regulated service: state commissions set base rates on a
cost-of-service, rate-of-return basis, and fuel, purchased power, natural gas commodity costs
and a range of capital and program costs are recovered through separate rider and cost-recovery
clauses. Duke Energy is a holding company with no operations of its own and depends on dividends
and loans from its utility subsidiaries to service its debt and pay its dividend.

The company operates through two reportable segments — Electric Utilities and Infrastructure
(EU&I) and Gas Utilities and Infrastructure (GU&I) — with the remainder presented as Other.
Operations run primarily through seven subsidiaries that are themselves SEC registrants: Duke
Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio
(whose wholly owned subsidiary Duke Energy Kentucky conducts the Kentucky operations), Duke
Energy Indiana and Piedmont Natural Gas. Duke Energy was incorporated in Delaware on
May 3, 2005.

**Electric Utilities and Infrastructure.** EU&I generates, transmits, distributes and sells
electricity through Duke Energy Carolinas, Duke Energy Progress, Duke Energy Florida, Duke
Energy Indiana and Duke Energy Ohio, and also sells wholesale power to municipalities, electric
cooperatives and other load-serving entities. The segment owns approximately 55,713 MW of
generation capacity and relies principally on natural gas, nuclear fuel and coal, supplemented
by hydroelectric, solar and purchased power. Duke Energy owns, wholly or partially, 11 operating
nuclear reactors at six operating stations; Crystal River Unit 3 permanently ceased operation in
February 2013 and is in SAFSTOR. Nuclear fuel is contracted well forward — 100% of uranium
concentrate requirements through at least 2029, conversion through at least 2034, enrichment
through at least 2033 and fabrication through at least 2029. EU&I inventory stood at
approximately $4.4 billion at December 31, 2025. The electric business is regulated by the FERC,
the NRC and the state commissions of North Carolina, South Carolina, Florida, Indiana, Ohio and
Kentucky (NCUC, PSCSC, FPSC, IURC, PUCO and KPSC). Duke Energy Indiana serves approximately
930,000 customers across about 23,000 square miles; Duke Energy owns 80.1% of its holding
company, with the remaining 19.9% held by GIC.

Weather-normal sales volumes grew in 2025 versus 2024, driven by residential customer growth and
commercial strength including data center usage, while industrial sales remained soft on
broad-based class weakness, some manufacturing plant closures and high interest rates. Over a
longer horizon, more efficient housing and appliances are expected to weigh on average
residential usage, partly mitigated by decoupled rates in North Carolina and other rate-design
mechanisms; commercial and industrial volumes are expected to grow with the economic development
pipeline.

**Gas Utilities and Infrastructure.** GU&I distributes natural gas through Piedmont, Duke Energy
Ohio and Duke Energy Kentucky to approximately 1.8 million customers — about 1 million in the
Carolinas, 205,000 in Tennessee (the Nashville metropolitan area) and 565,000 in southwestern
Ohio and northern Kentucky. The segment earns its retail margin on transmission and distribution
service rather than on the gas commodity. Revenue is largely insulated from weather: margin
decoupling in North Carolina provides a set margin per customer independent of usage, weather
normalization adjusts revenues in South Carolina, Tennessee and Kentucky during the heating
season, and Duke Energy Ohio collects most non-fuel revenue through a fixed monthly charge.
Firm supply purchase commitments covered approximately 100% of winter-month gas supply for both
Piedmont and Duke Energy Ohio in 2025. GU&I inventory was $91 million at December 31, 2025,
excluding amounts held for sale. The segment also holds pipeline and storage equity interests:
Duke Energy owns 7.5% of Sabal Trail, and Piedmont holds 21.49% of Cardinal, 45% of Pine Needle
and 50% of Hardy Storage. In July 2025, Piedmont agreed to sell its Tennessee business to Spire
Inc.; that sale closed on March 31, 2026 (see Current quarter).

**Other.** Not a reportable segment, Other carries holding-company interest expense, unallocated
corporate costs, certain income tax amounts and companywide initiatives, plus Bison — a wholly
owned captive insurance company indemnifying Duke Energy subsidiaries for property, workers'
compensation and general liability losses — and a 17.5% equity interest in NMC, a Saudi joint
venture in Jubail that produces roughly 1 million metric tons each of MTBE and methanol annually
with capacity for 50,000 metric tons of polyacetal.

**Coal ash and nuclear obligations.** EPA coal combustion residuals (CCR) regulations, layered
over state rules such as North Carolina's Coal Ash Act, require site-specific remediation and
closure plans for coal ash landfills and surface impoundments; recovery of those costs runs
through ordinary ratemaking, and Duke Energy Carolinas' and Duke Energy Progress' wholesale
contracts include recovery of asset retirement obligations for basin closure. On the nuclear
side, the Price-Anderson Act sets maximum total financial protection liability at approximately
$16.3 billion, the NCUC and PSCSC require decommissioning cost estimates to be refreshed every
five years, and because the Department of Energy has never built a permanent repository, spent
fuel continues to be stored on site.

Harry K. Sideris is president and chief executive officer; Brian D. Savoy is executive vice
president and chief financial officer.

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## Risk factors

*From the fiscal 2025 Annual Report on Form 10-K (accession 0001326160-26-000014); the filing
groups these risks as applying generally to all of the Duke Energy registrants.*

**Rate regulation and cost recovery.** Earnings depend on the rates state commissions allow in
North Carolina, South Carolina, Florida, Ohio, Tennessee, Indiana and Kentucky. If earnings
exceed authorized returns, rates may be reviewed and cut; if regulators disallow costs or delay
recovery, results and cash flows suffer. Differences in regulation between jurisdictions serving
the same utility — North Carolina versus South Carolina for Duke Energy Carolinas and Duke
Energy Progress — can themselves cause under-recovery. Negative rate-case decisions, or adverse
rulings on appeal, have had and could again have a material adverse effect. Discontinuation of
margin-stabilizing mechanisms (decoupling, rate stabilization, performance incentive mechanisms)
or prudence disallowances of fuel and purchased power costs would hurt earnings directly.

**Business strategy execution.** Results depend on implementing a strategy that balances growing
customer demand, reliability, affordability and emissions reduction. Policy could restrict
access to or raise the cost of natural gas or nuclear generation; the loss or reduction of
nuclear production tax credits under the IRA and OBBBA would remove an expected customer cost
benefit. Siting and cost recovery for transmission and distribution upgrades, state approval to
retire carbon-emitting assets or add capacity, availability of labor and equipment at reasonable
cost, and the eventual commercial availability of unproven technologies (carbon capture,
advanced nuclear, hydrogen, long-duration storage) are all prerequisites that may not be met.

**Construction and large-project risk.** The long-term strategy requires extensive capital
investment in generation and transmission. Risks include construction delay, failure to obtain
regulatory approvals or siting and environmental permits, supplier nonperformance, cost
escalation, tariff impacts, and compounding risk from developing multiple facilities
simultaneously. Cancellation can trigger penalties under equipment and construction contracts or
impairment charges; completed projects can still be deemed imprudent and disallowed from rates.

**Environmental and climate regulation.** The registrants are subject to extensive rules on CCR,
air emissions, water quality, wastewater, solid and hazardous waste. Compliance requires
significant capital spending and may not be fully recoverable. CCR obligations are specifically
called out: large asset retirement obligations have been recognized, and as final closure plans
and corrective measures are approved site by site, the scope of work and volume of material could
exceed estimates and materially increase both compliance spending and rate impacts. Additional
GHG restrictions, reporting requirements and local bans on new natural gas infrastructure are
possible.

**Demand, growth and large loads.** Customer and usage growth drive demand and the need for new
generation and delivery assets, and are affected by efficiency mandates, distributed generation,
technology shifts among large commercial customers such as data centers, and macroeconomic
conditions. Federal legislation enacted in 2025 ended the long-term extension of certain
residential solar tax credits after 2025. Emerging large loads — hyperscale data centers and
industrial facilities — carry distinct risk from high demand, rapid fluctuation and unpredictable
operating profiles that can strain grid reliability; early termination of service agreements or
stranded assets could follow if the supporting investment is not recovered. Conversely, declining
demand or customer counts could leave major capital expenditures without the anticipated benefit.

**Weather, storms and seasonality.** Electric generation and gas distribution are seasonal, so
results fluctuate substantially quarter to quarter. Hurricanes, winter storms, droughts, heat
waves, tornadoes and wildfires cause outages, property damage, injury and unexpected restoration
expense; sustained drought can impair hydroelectric, fossil and nuclear operations that depend on
cooling water. Storm restoration cost may not be fully or timely recoverable through the
regulatory process.

**Operational and nuclear.** Generating electricity and transporting and storing natural gas
carry inherent risk of accidents involving injury, environmental damage or property damage, with
exposure to civil or criminal proceedings and insurance that may not cover the full loss.
Ownership and operation of nuclear stations by Duke Energy Carolinas, Duke Energy Progress and
Duke Energy Florida adds radioactive-material handling and disposal risk, limited insurance
availability, decommissioning uncertainty and terrorism or cyber-incident exposure; NRC
non-compliance can bring increased oversight, fines or a unit shutdown. Market declines in the
nuclear decommissioning trust funds could require significant additional funding.

**Cybersecurity and technology.** Cyberattack and data-breach risk has risen with new technology,
greater internet connectivity through grid modernization, and the use of AI — including
generative AI — by attackers, by the company and by its vendors. A significant breach could
disrupt gas and electric assets and the grid, expose confidential information, prevent the
company from serving customers or collecting revenue, and bring substantial costs, regulation,
litigation and reputational harm; cyber insurance is subject to exclusions and may be
insufficient. Advances such as quantum computing could eventually break standard encryption.
The registrants are subject to NERC standards enforced by FERC, NRC rules for nuclear digital
systems and TSA security directives for designated critical gas pipelines, and have at times
been found in violation. Failure of internal information technology systems, or failure to
modernize them, is a separate risk.

**Transmission access, pipeline capacity and RTO participation.** Disrupted or inadequate
transmission capacity limits the ability to sell and deliver power, and the growth of renewables
and storage strains existing assets. Almost all natural gas supply is purchased interstate, so
pipeline disruption or insufficient new infrastructure limits earnings and growth. Duke Energy
Ohio's and Duke Energy Indiana's RTO membership exposes them to changing market rules, cost
allocation for facilities built by others, expansion decided by the RTO rather than internal
planning, unreimbursed defaults by other RTO participants and refund complaints.

**Liquidity, credit and capital access.** The businesses are significantly financed with debt and
equity whose maturities do not match asset cash flows, so access to short-term money markets and
longer-term capital markets is critical — including for unexpected spending such as volatile
commodity costs or major storm restoration. Senior long-term debt is currently rated investment
grade at each registrant, but a downgrade below investment grade would raise borrowing costs
significantly, shrink the investor pool, restrict commercial paper access, and could require
posting collateral and trigger termination clauses in interest rate derivatives. Covenant
breaches could accelerate maturities. As a holding company, Duke Energy depends on upstream
dividends and loans from subsidiaries that face their own regulatory restrictions and
obligations.

**Strategic transactions.** Pending transactions are subject to closing conditions including
regulatory approvals. Failure to close would mean the anticipated proceeds are unavailable,
requiring alternative funding and preventing the displacement of planned long-term debt and
common equity issuances, with adverse effects on credit metrics and potential ratings pressure,
negative market reaction, lost strategic optionality and transaction costs for no benefit. Even
completed transactions may not deliver the expected results.

**Other.** Also disclosed: economic downturns reducing sales and raising bad debt expense;
inflation and tariffs outrunning cost recovery; commodity hedge collateral posting; competition
from deregulation, self-generation, municipalization and alternative fuels, with stranded-cost
exposure; increased competition for natural gas against electricity and other fuels; pension
investment performance; insurance availability and cost; activist shareholders; conflicting
stakeholder expectations on environmental, social and governance matters; pandemic health
events; terrorism and military action; and workforce attraction and retention.

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## Management's discussion — fiscal 2025

*From the fiscal 2025 Annual Report on Form 10-K (accession 0001326160-26-000014).*

**Results.** GAAP reported EPS was $6.31 for 2025 against $5.71 for 2024; adjusted EPS, which
excludes special items, was $6.31 against $5.90. The adjusted increase came primarily from
recovery of growing infrastructure investments and growth in the service territories, partly
offset by higher operation and maintenance expense, interest expense, property taxes and
depreciation on a larger asset base. On the GAAP line, the year-over-year increase also reflects
the absence of prior-year impairments tied to the 2024 South Carolina rate case, prior-year
charges for Duke Energy Indiana post-retirement benefits, and prior-year charges on certain joint
venture electric transmission projects and renewable natural gas investments.

**Electric Utilities and Infrastructure.** Results were driven by higher revenues from rate cases
across multiple jurisdictions, higher weather-normal retail volumes and higher transmission
revenues, offset by higher operation, maintenance and depreciation expense. Revenue movements
included a $951 million increase from jurisdictional rate-case pricing (primarily Duke Energy
Carolinas, Duke Energy Indiana, Duke Energy Florida and Duke Energy Progress), a $753 million
increase in storm recovery revenues at Duke Energy Florida, a $223 million increase in
weather-normal retail volumes, a $161 million increase in rider revenues, a $105 million increase
in other revenues and a $74 million increase from improved weather — against a $1,119 million
decrease in fuel revenues on lower rates. Expense movements included a $1,229 million increase in
operation, maintenance and other (higher storm amortization at Duke Energy Florida, litigation and
environmental costs at Duke Energy Carolinas, TDSIC rider amortization and plant maintenance at
Duke Energy Indiana), a $477 million increase in depreciation and amortization and a $113 million
increase in property and other taxes, offset by a $1,147 million decrease in fuel used in electric
generation and purchased power and a $46 million decrease in impairments. The segment effective
tax rate was 13.7% in 2025 versus 14.4% in 2024.

**Gas Utilities and Infrastructure.** Results benefited from higher revenues on the 2024 Piedmont
North Carolina rate case and lower impairments on certain renewable natural gas investments,
offset by higher operation, maintenance and depreciation expense. Revenues rose $429 million on
cost-of-gas recovery at higher commodity prices, $98 million on Piedmont North Carolina rate-case
pricing, $21 million on Midwest rider revenue and $13 million on improved Midwest weather;
expenses rose $418 million on the cost of natural gas, $40 million on operation and maintenance,
$35 million on depreciation and $15 million on property and other taxes. The segment effective
tax rate was 20.7% versus 17.9%, the increase driven by lower amortization of excess deferred
income taxes.

**Strategic transactions entered in 2025.** In July 2025, Piedmont agreed to sell its Tennessee
business to Spire Inc. for $2.48 billion, with closing expected on March 31, 2026 subject to TPUC
approval; proceeds were earmarked for debt reduction at Piedmont and to fund the capital plan by
displacing near-term common equity issuance. In August 2025, Duke Energy, Progress Energy and
Florida Progress entered an investment agreement under which Florida Progress would issue up to
19.7% of its membership interests to an affiliate of Brookfield Super-Core Infrastructure Partners
for an aggregate $6 billion through a series of closings running to June 30, 2028, with a first
closing targeted for March 2026 at expected proceeds of $2.8 billion (subject to adjustment).
Termination of that agreement before the first closing in specified circumstances would have
obliged the investor to pay Progress Energy a $240 million fee. Both transactions were intended to
displace previously planned long-term debt and common equity issuances.

**Regulatory and legislative outcomes.** New rates took effect in January 2025 for Duke Energy
Florida's three-year plan; Piedmont and Duke Energy Indiana received general rate case orders in
January; Duke Energy Kentucky's electric order produced new rates in July and its gas order
produced new rates in January 2026; the PSCSC issued orders on the Duke Energy Progress and Duke
Energy Carolinas South Carolina base rate cases in December 2025, with rates effective February
2026 and March 2026 respectively. Duke Energy Carolinas and Duke Energy Progress filed
performance-based regulation applications in North Carolina in November 2025 covering a two-year
multi-year rate plan, with evidentiary hearings set for the third quarter of 2026. New state
legislation was finalized in 2025 in Ohio (HB15, enabling a three-year rate plan with
forward-looking test periods), South Carolina (Act 41, establishing an electric rate stabilization
mechanism with annual base rate adjustments) and North Carolina (SB266, providing more timely
recovery of fuel costs and baseload generation financing costs). Duke Energy issued North Carolina
storm recovery bonds in September 2025 and South Carolina storm recovery bonds in November 2025,
fully recovering the 2024 hurricane season costs.

**Generation and nuclear milestones.** Duke Energy Progress received an NCUC CPCN in October 2025
for the second combined-cycle unit in Person County and Duke Energy Indiana received an IURC CPCN
for the Cayuga combined-cycle project; Duke Energy Carolinas filed in October 2025 for a CECPCN
for a new combined-cycle unit in Anderson County, South Carolina and in November 2025 for a CPCN
for two combustion turbines at the existing Buck station. The NRC issued a subsequent license
renewal for Oconee in March 2025 extending operation to 2054 — the first Duke Energy station
approved to 80 years — and an application was submitted in April 2025 to extend Robinson through
2050. In July 2025, Duke Energy Carolinas filed with FERC to extend the Bad Creek pumped-storage
license for 50 more years, to 2077. In August 2025 Duke Energy filed applications to combine its
two Carolinas electric utilities by merging Duke Energy Progress into Duke Energy Carolinas;
FERC approval came in January 2026 and the targeted effective date was January 1, 2027, subject to
remaining NCUC and PSCSC approvals.

**Capital plan and energy modernization.** Over the next decade Duke Energy expects to deploy
approximately $200 billion to $220 billion of capital into its regulated businesses, already
including about 7,500 MW of new natural gas generation under construction or awaiting regulatory
approval. Carbon emissions from electricity generation were down 43% from 2005 levels. In 2025,
self-healing distribution technology avoided roughly 2.2 million customer outages and about
5.2 million hours of outage time, roughly a third of that during major storms, with nearly 75% of
electric customers served by self-healing technology on main distribution lines at year end — more
than double three years earlier.

**Economic development and operations.** Duke Energy won 87 economic development projects in 2025
representing over $30 billion of new capital investment and approximately 29,000 new jobs in its
territories, including Amazon's planned $10 billion cloud computing and AI campus in Richmond
County, North Carolina. Duke Energy Carolinas and Duke Energy Progress set a combined winter peak
record in January 2025 and surpassed it in January 2026 during Winter Storm Fern; a June 2025 heat
wave set a new Carolinas summertime usage record. The 2025 OSHA total incident case rate again came
in better than target, finishing the year with 100 recordable injuries.

**Liquidity and capital resources.** At December 31, 2025, Duke Energy held $245 million of cash on
hand with $7.8 billion available under its Master Credit Facility, which carries a covenant
limiting debt to 65% of total capitalization for each borrower other than Piedmont (70% for
Piedmont); all registrants were in compliance. Because of existing tax attributes and projected
credits, Duke Energy does not expect to be a significant federal cash taxpayer until around 2030,
and Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are monetizing tax credits
in the IRA transferability markets. For 2026 the company anticipated issuing approximately $9
billion of debt, and plans $10 billion of common equity from 2027 through 2030 through its dividend
reinvestment and ATM programs; equity forward sales agreements executed in 2025 were expected to
settle by December 31, 2026. Other purchase obligations totaled $16,547 million. Duke Energy paid
quarterly cash dividends for the 99th consecutive year in 2025, targets a 60% to 70% payout ratio
on adjusted EPS, and raised the dividend approximately 2% annually in each of 2025 and 2024.

**Matters management flagged as affecting future results.** The 2024 CCR Rule materially expands
the 2015 rule to inactive impoundments at retired facilities and previously unregulated ash
sources, and Duke Energy is participating in legal challenges; EPA Rule 111, if implemented as
issued, would materially affect the timing, nature and magnitude of future generation investment,
and the EPA published a proposed repeal in June 2025. Supply chain stability for key materials,
including rare earth materials and the effect of tariffs and trade policy, remains a monitored
risk. On the August 31, 2025 annual goodwill test, every reporting unit's estimated fair value
materially exceeded carrying value except the GU&I reporting unit of Duke Energy Ohio; no
impairment was recorded, but deteriorating conditions could produce one in future periods.

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## Current quarter — three and six months ended June 30, 2026

*From the Form 10-Q for the quarter ended June 30, 2026 (accession 0001326160-26-000040), with
guidance and segment income from the second-quarter 2026 earnings release furnished on Form 8-K
(accession 0001326160-26-000037).*

**Earnings.** GAAP reported EPS was $1.38 for the second quarter of 2026 against $1.25 a year
earlier; adjusted EPS was $1.43 against $1.25. For the six months, GAAP reported EPS was $3.35
against $3.00 and adjusted EPS $3.36 against $3.00. The adjusted improvement came primarily from
recovery of infrastructure investments in growing jurisdictions, offset by higher depreciation on
a larger asset base and higher interest expense; the six-month comparison also carried higher
operation and maintenance expense including storm costs. The quarter's gap between reported and
adjusted results is the North Carolina rate case regulatory settlements: a pretax charge of
$51 million recorded within impairment of assets and other charges for the three months ended
June 30, 2026, which net of a $12 million tax benefit is the $39 million, or $0.05 per share,
regulatory settlements special item. That $51 million is the sum of a $29 million charge at Duke
Energy Carolinas and a $22 million charge at Duke Energy Progress, each recorded in the same amount
for the three and the six months ended June 30, 2026.
For the six months, special items were legal and regulatory settlements ($248 million pretax —
$172 million in operation, maintenance and other, the same $51 million in impairments and
$25 million in operating revenues — or $189 million and $0.24 per share after a $59 million tax
benefit), asset sales ($374 million in gains on sales of other assets and other,
net, less $7 million in property and other taxes, net of $196 million of tax expense that includes
nondeductible goodwill on the Piedmont Tennessee sale) and the resolution of an outstanding
liability from the Commercial Renewables disposal groups in discontinued operations.

By segment for the quarter, Electric Utilities and Infrastructure reported segment income of
$1,271 million versus $1,194 million, or $1,310 million versus $1,194 million on an adjusted basis
(a $0.15 per share increase). The $39 million regulatory settlements charge is the whole of the
$1,271 million reported to $1,310 million adjusted difference. Gas Utilities and Infrastructure
reported segment income of $10 million versus $6 million on both a reported and adjusted basis. Other recorded a segment loss
of $204 million versus $228 million, a $0.03 per share improvement on higher investment returns and
lower interest expense.

**Guidance.** Duke Energy reaffirmed 2026 adjusted EPS guidance of $6.55 to $6.80 and a long-term
adjusted EPS growth rate of 5% to 7% through 2030 measured off the 2025 midpoint of $6.30, stating
confidence in earning in the top half of that range beginning in 2028. Management does not forecast
reported GAAP EPS.

**Strategic transactions closed.** Duke Energy completed both previously announced transactions in
the first quarter of 2026, generating approximately $5.3 billion of proceeds. On March 3, 2026, the
first closing of the Florida Progress minority investment by an affiliate of Brookfield Super-Core
Infrastructure Partners transferred a 9.19% ownership interest for approximately $2.8 billion in
cash, with additional staged investments anticipated through June 30, 2028 toward the eventual
19.7% interest. On March 31, 2026, following TPUC approval, Piedmont closed the sale of its
Tennessee business to Spire, Inc. for approximately $2.5 billion in cash proceeds.

**Electric Utilities and Infrastructure drivers.** For the quarter, revenues rose on a $145 million
increase in fuel revenues, a $117 million increase from rate-case pricing across jurisdictions, an
$84 million increase in weather-normal retail volumes, a $74 million increase in rider revenue
(higher Storm Protection Plan rates at Duke Energy Florida and the Distribution Capital
Investment Rider at Duke Energy Ohio) and a $52 million increase in wholesale revenues net of fuel at Duke
Energy Progress, partly offset by a $278 million decrease in storm recovery revenues at Duke Energy
Florida and a $20 million decrease in retail sales on less favorable weather. Expenses fell
$255 million in operation, maintenance and other on lower storm amortization at Duke Energy Florida
and $28 million in property and other taxes on franchise tax refunds, offset by a $112 million
increase in depreciation and amortization, a $50 million year-over-year increase in impairment of
assets and other charges, reflecting the 2025 North Carolina rate case regulatory settlement
charges, and a $35 million increase in fuel and purchased
power. Interest expense rose on higher debt balances, lower returns on deferred storm cost balances
and higher accrued financing costs on deferred nuclear production tax credit liabilities at Duke
Energy Carolinas. The segment effective tax rate was 14.7% versus 14.1%. Net income attributable to
noncontrolling interests increased because of the Florida Progress minority investment closing.

For the six months, revenues rose $431 million on fuel, $319 million on rate-case pricing,
$117 million on weather-normal volumes, $87 million on wholesale net of fuel, $79 million on riders
and $50 million on other revenues including transmission, against a $261 million decrease in storm
recovery revenues at Duke Energy Florida. Expenses rose $356 million on fuel and purchased power
(higher natural gas prices and purchased power costs), $276 million on depreciation and
amortization, $50 million on impairments and $30 million on operation, maintenance and other —
a legal settlement, Winter Storm Fern storm costs, higher nuclear outage costs and customer
program costs, partly offset by lower storm amortization at Duke Energy Florida. The six-month
segment effective tax rate fell to 12.0% from 13.4% on higher nuclear production tax credit
amortization.

**Gas Utilities and Infrastructure drivers.** For the quarter, results reflected lower franchise
taxes offset by the loss of the Tennessee business: revenues fell $28 million on cost-of-gas
recovery at lower commodity prices and $24 million from the Tennessee sale, while expenses fell
$28 million on the cost of natural gas and $13 million on property and other taxes. The segment
effective tax rate was 23.1% against negative 200% a year earlier, the prior period reflecting
lower state tax expense. For the six months, results were driven by the gain on the Tennessee sale
and growth in capital riders: revenues rose $123 million on cost-of-gas recovery at higher
commodity prices, $24 million on Carolinas customer growth and the North Carolina Integrity
Management Rider, $14 million on Midwest rider revenue and $11 million on the 2025 Duke Energy
Kentucky gas rate case, with the cost of natural gas up a matching $123 million. The six-month
effective tax rate rose to 35.4% from 19.7% on nondeductible goodwill associated with the sale.

**Regulatory developments in the period.** Revised base rates took effect in the first quarter of
2026 for Duke Energy Carolinas' and Duke Energy Progress' South Carolina territories and Duke
Energy Kentucky's gas business, and during 2026 Duke Energy Ohio's electric and gas businesses and
Piedmont's South Carolina gas business filed new base rate applications. The PSCSC issued a final
order on April 24, 2026 approving the CECPCN for a new 1,365 MW hydrogen-capable combined-cycle
facility in Anderson County, South Carolina at a preliminary total project cost of approximately
$3.2 billion inclusive of financing costs, to be co-owned with North Carolina Electric Membership
Corporation and Central Electric Power Cooperative (Duke Energy Carolinas approximately 1,170 MW),
with construction anticipated to begin in 2027 and service by the end of 2030. The PSCSC issued an
order accepting the updated Carolinas systemwide resource plan on May 15, 2026; the NCUC held its
evidentiary hearing on the 2025 Carolinas Resource Plan in June 2026 with an order expected by
December 31, 2026. FERC issued an order authorizing the combination of the two Carolinas electric
utilities, comprehensive settlements were reached with intervenors in both Carolinas, and NCUC and
PSCSC approvals were obtained; the targeted effective date remains January 1, 2027. Indiana House
Enrolled Act 1002, signed February 26, 2026, introduced three-year rate plans and performance-based
affordability and reliability metrics and requires Duke Energy Indiana to file its first multi-year
rate plan between November 15 and December 15, 2026. Ohio Senate Bill 103, effective March 20,
2026, allows gas utilities to file multi-year rate plans with forward-looking test periods. On the
coal ash front, the EPA published a proposed rule on April 13, 2026 that would rescind all CCR
Management Unit requirements finalized in the 2024 CCR Rule (with alternatives under comment) and
expand closure and deferral pathways for legacy surface impoundments; a final rule is anticipated in
the fourth quarter of 2026, and Duke Energy says the impact could be material.

**Nuclear and operations.** The company announced in February 2026 that its nuclear fleet achieved a
record systemwide capacity factor in 2025, and in April 2026 the NRC issued a subsequent license
renewal for Robinson extending operations through 2050. In late January 2026, Winter Storm Fern
affected all service territories, with sustained subfreezing temperatures driving record winter peak
demand across the Carolinas.

**Liquidity.** At June 30, 2026, Duke Energy held $673 million of cash on hand with $8.0 billion
available under its Master Credit Facility, whose $10 billion commitment had its termination date
extended in March 2026 to March 2031. In April 2026 the company executed a multi-year agreement to
sell up to $3.1 billion of net tax credits, including nuclear production tax credits, with proceeds
expected through 2029. In March 2026 the company filed a prospectus supplement and executed an
Equity Distribution Agreement establishing an at-the-market program under which it may sell up to
$6.0 billion of common stock through September 2028, including an equity forward sales component;
the equity forward sales agreements already executed under that program are now expected to settle
by December 31, 2027. Six-month operating cash flow fell primarily on a $981 million decrease
from changes in other assets and liabilities — higher deferred fuel and purchased power costs and
storm restoration costs from severe winter weather — partly offset by a $334 million increase in net
income after non-cash adjustments. Investing cash flow reflected the Tennessee sale proceeds against
higher EU&I capital expenditures and the absence of prior-year Commercial Renewables proceeds.
Financing cash flow reflected a $2.8 billion increase from the Brookfield initial closing, against a
$1.4 billion decrease in net long-term debt issuance on timing and a $175 million decrease in net
notes payable and commercial paper borrowings. Behind that long-term debt line, the parent's March
issuance was a refinancing rather than new money: Duke Energy announced a $1.0 billion convertible
offering on March 9, 2026, priced it upsized at $1.3 billion on March 10 and closed $1.5 billion of
3.000% Convertible Senior Notes due March 2029 on March 12 with the initial purchasers' $200 million
option exercised in full, at an initial conversion price of approximately $160.57 per share. The
proceeds were used to repay a portion of the $1.725 billion of 4.125% convertible senior notes
maturing April 15, 2026, which Duke Energy settled upon conversion with approximately $1.7 billion
of cash for the principal plus 1.4 million common shares for the conversion premium. (The offering,
its upsized pricing and its closing were reported on Form 8-K, accessions 0001104659-26-024945,
0001104659-26-025530 and 0001104659-26-027080.)

---

## Subsequent events

*The Form 10-Q for the quarter ended June 30, 2026 (accession 0001326160-26-000040) does not carry a
standalone subsequent-events note; post-period developments are disclosed within its regulatory
matters, commitments and contingencies, and debt notes. Items after the filing date are from the
Current Reports on Form 8-K cited below.*

**Duke Energy Carolinas 2025 North Carolina rate case.** On July 2, 2026, Duke Energy Carolinas and
the North Carolina Public Staff entered a partial stipulation resolving certain issues while leaving
return on equity, capital structure and performance-based regulation for litigation. On July 6, 2026
the parties entered a separate storm cost stipulation resolving Hurricane Helene and Winter Storm
Fern cost recovery. On July 17, 2026, Duke Energy Carolinas, the Public Staff and other intervening
parties filed a comprehensive settlement with the NCUC resolving all remaining revenue requirement
issues at a 9.8% return on equity and a 53% equity ratio, with a net retail revenue increase of
$286 million in Year 1 and $210 million in Year 2 — a cumulative $496 million, or 7.4%. Consistent
with that framework, Duke Energy Carolinas recorded a $29 million impairment charge in the second
quarter of 2026. On July 24, 2026 a separate settlement on performance incentive mechanisms was
filed. The stipulations require NCUC approval, an order is expected by November 2026, and Year 1
rates have been requested no later than January 1, 2027. The July 2026 stipulations and settlement
were also reported on Form 8-K (accessions 0001104659-26-080476 and 0001104659-26-084653).

**Duke Energy Progress 2025 North Carolina rate case.** The evidentiary hearing was scheduled to
commence August 11, 2026, with an order expected by November 2026 and Year 1 rates requested no
later than January 1, 2027. On July 24, 2026, Duke Energy Progress filed an updated revenue
requirement in rebuttal testimony reducing its requested increase to approximately $610 million over
the two-year period, a roughly 12.3% overall increase, at a requested 10.48% return on equity with a
53% equity component — down from the approximately $729 million, or 15.1%, and 10.95% return on
equity in the original November 20, 2025 filing. On August 5, 2026, Duke Energy Progress, the Public
Staff and other intervening parties filed a Comprehensive Revenue Requirement Settlement with the
NCUC resolving all remaining revenue requirement issues, agreeing on a 9.8% return on equity and 53%
equity component, a North Carolina retail rate base of approximately $17.8 billion, approximately
$3.4 billion of multi-year rate plan capital (North Carolina retail allocation) with an annual refund
mechanism, resolution of the mechanics of the decoupling mechanism and the ESM, and an extension of the
amortization of deferred coal ash costs from five years to eight years. The settlement results in a
revised revenue requirement increase of $338 million over the two-year period — an average annual
rate increase of 3.4% over two years — and is expected to result in approximately $30 million of
one-time pretax accounting charges to be recognized by Duke Energy Progress in 2026, treated as
special items and excluded from adjusted earnings. Reported on Form 8-K, accession
0001104659-26-091159. Consistent with the Duke Energy Carolinas settlement framework, Duke Energy
Progress recorded a $22 million charge within Impairment of assets and other charges for the three
and six months ended June 30, 2026 (Form 10-Q, accession 0001326160-26-000040).

**South Carolina electric rate stabilization dispute.** On July 13, 2026, the PSCSC directed that
electric utilities electing into the eRSA may not implement rate adjustments until the year following
election, and on July 15, 2026 it issued an order denying the stipulation and rejecting Duke Energy
Progress' proposed 2026 rate adjustment. Duke Energy Progress filed a petition for reconsideration on
July 23, 2026 and appealed to the South Carolina Supreme Court on July 24, 2026; the timing and amount
of any authorized rate adjustment remain uncertain.

**Generation certificates.** On July 23, 2026, the PSCSC granted out-of-state certificates for the two
new advanced-class combustion turbines at the existing Marshall Steam Station in North Carolina and
for the two new combined-cycle units totaling approximately 2,720 MW at the Person County site in
North Carolina. On July 24, 2026, Duke Energy Carolinas and the Public Staff filed a settlement
recommending the NCUC approve the determination of need and the estimated construction cost and
schedule for the Anderson County facilities, with an NCUC decision anticipated in the fourth quarter
of 2026.

**FERC rehearing.** FERC's June 25, 2026 order on remand directed the removal of the ROE adder — the
50-basis-point adder associated with RTO membership — from Duke Energy Ohio's transmission formula
rate and required Duke Energy Ohio to provide refunds for the period beginning February 24, 2022. As
a result, Duke Energy Ohio recorded a $15 million reduction in Operating Revenues in the three months
ended June 30, 2026, and had recorded a $20 million regulatory liability at June 30, 2026; refunds
are expected to be issued by the first quarter of 2027. On July 24, 2026, Duke Energy Ohio filed a
request for rehearing of that order, including whether the order complies with the Federal Power
Act's requirements governing changes to existing rates. FERC was required to act on the rehearing
request by August 24, 2026, but could issue a further substantive order after that date.

**$2.0 billion equity units offering.** On August 13, 2026, Duke Energy consummated the issuance and
sale of 40,000,000 equity units, initially in the form of corporate units, under an underwriting
agreement dated August 10, 2026 with Barclays Capital Inc., BofA Securities, Inc. and Mizuho
Securities USA LLC as representatives of the underwriters. The total includes 5,000,000 corporate
units sold on the underwriters' full exercise of their over-allotment option, bringing the aggregate
offering amount to $2,000,000,000 and estimated net proceeds to the company to approximately
$1,965 million. Each corporate unit has a stated amount of $50 and comprises a stock purchase
contract obligating the holder to buy Duke Energy common stock for $50 in cash no later than
August 1, 2029, plus 1/40 undivided beneficial ownership interests in $1,000 principal amount each of
Duke Energy's 4.85% Remarketable Senior Notes due 2032 and 4.85% Remarketable Senior Notes due 2036.
Total annual distributions run at 7.75% of the stated amount — 2.90% in quarterly contract adjustment
payments plus 4.85% of interest on the remarketable senior notes. The notes are pledged as collateral
securing holders' purchase obligations and will be remarketed before the purchase contract settlement
date. Reported on Form 8-K, accession 0001104659-26-095903.

**Board appointment.** On September 24, 2026, the Board of Directors appointed Joyce Mullen as a
director effective September 28, 2026, with an initial term expiring at the 2027 Annual Meeting of
Shareholders, and named her to the Audit Committee and the Operations and Nuclear Oversight
Committee. Ms. Mullen retired as president and chief executive officer of Insight Enterprises, Inc.
in April 2026 and continues to advise Insight as executive vice president of strategic development;
she previously held executive positions at Dell Technologies and serves on the board of The Toro
Company. Reported on Form 8-K, accession 0001104659-26-110588.

No acquisitions or divestitures were disclosed in the period after June 30, 2026 in the 10-Q or in
the Current Reports on Form 8-K filed through the date of this report.