Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Duke Energy and Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana and Piedmont. However, none of the registrants make any representation as to information related solely to Duke Energy or the Subsidiary Registrants of Duke Energy other than itself.

DUKE ENERGY

Duke Energy is an energy company headquartered in Charlotte, North Carolina, and operates in the U.S. primarily through its subsidiaries, Duke Energy Carolinas, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana and Piedmont. Duke Energy’s consolidated financial information includes the results of the Subsidiary Registrants, which along with Duke Energy are collectively referred to as the Duke Energy Registrants.

Management’s Discussion and Analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes for the nine months ended September 30, 2024, and with Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2023.

Executive Overview

Operational Excellence, Safety and Reliability**.** The reliable and safe operation of our power generating facilities, electric distribution system and natural gas infrastructure in our communities continues to be foundational to serving our customers, our financial results, and our credibility with stakeholders. In recent months, we have responded to several unprecedented and catastrophic weather events across our service territories.

In August 2024, Hurricane Debby made landfall in Florida as a Category 1 storm, impacting the Duke Energy Florida territory as well as the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina and causing approximately 700,000 customer outages. In late September 2024, Hurricane Helene made landfall in Florida as a Category 4 storm and subsequently impacted all of Duke Energy's service territories as the storm moved inland, with the most severe damage occurring in Florida and the Carolinas. Approximately 3.5 million customers were impacted by Hurricane Helene across Duke Energy's system, the largest number of companywide outages from a single event on our system ever reported. Then, in October 2024, Hurricane Milton made landfall in Florida as a Category 3 storm, causing severe damage across our Florida service territory as a result of high winds, rain and flooding and resulting in more than 1 million customer outages.

In such extreme circumstances, our immediate priority is, and always will be, executing the extensive storm preparation and response work to ensure the safe, timely, and efficient restoration of service to impacted customers as quickly as possible. Round-the-clock power restoration efforts continued following the historic damage inflicted by these storms with lineworkers, tree trimmers and removal experts, state department of transportation workers and countless others, working to repair and, in certain areas, completely rebuild, the critical electricity infrastructure that powers and supports the communities we serve. We've also seen the benefits of ongoing grid hardening investments, leveraging self-healing technologies and remote restoration capabilities to automate the rerouting of power, more effectively deploy resources, and reduce the frequency or duration of outages for many of our customers during severe weather events.

We will continue the important work of rebuilding our communities in the weeks and months ahead, including power infrastructure in the hardest-hit areas of our service territories. We also plan to work with our state commissions to appropriately track and recover storm costs under approved regulatory frameworks on a timely basis. We will also remain focused on balancing the bill impacts on our customers from such catastrophic events, including seeking insurance recovery and exploring the potential securitization of related costs in certain jurisdictions, as appropriate. For more information, see "Matters Impacting Future Results," "Liquidity and Capital Resources," and Notes 4 and 6 to the Condensed Consolidated Financial Statements, "Regulatory Matters" and "Debt and Credit Facilities."

Advancing Our Clean Energy Transition. During the nine months ended September 30, 2024, we continued to execute on our clean energy transition, remaining focused on reliability and affordability while delivering increasingly clean energy and providing strong, sustainable value for shareholders, customers, communities and employees.

In May 2024, we entered into memorandums of understanding with several large customers, which propose exploring new and innovative approaches to support carbon-free energy generation and serve future energy needs of large businesses in North Carolina and South Carolina through the use of new tariff structures. The proposed Accelerating Clean Energy (ACE) tariff framework includes new, voluntary pricing structures for large commercial and industrial customers, which enable their direct support of carbon-free energy generation investments including facilitating beneficial customer on-site generation and load flexibility programs. The proposed ACE tariffs would be subject to regulatory approvals and include protections for non-participating customers.
In January 2024, we filed supplemental modeling and analysis with the NCUC and PSCSC related to our combined systemwide Carolinas Resource Plan filed in August 2023. These updates were necessary due to substantially increased load forecasts resulting from continued economic development successes in the Carolinas occurring since the systemwide integrated resource plan was prepared. In March 2024, we filed for: (i) CPCNs with the NCUC for new natural gas generation facilities at the sites of the current Marshall Steam Station and Roxboro Plant in the Carolinas; and (ii) a Certificate of Environmental Compatibility and Public Convenience and Necessity with the PSCSC for a new solar center and associated facilities in Chesterfield and Darlington counties, South Carolina. Our energy transition strategy continues to focus on delivering a path to cleaner energy in a manner that protects grid reliability and affordability, all while meeting the energy demands of the growing and economically vibrant communities that we serve.
As we continue to strengthen our grid and bring clean energy resources online, our customers are important partners in our clean energy future. In January 2024, we received approval for PowerPairSM, a new incentive-based pilot program for installing home solar generation with battery energy storage in our Duke Energy Carolinas and Duke Energy Progress North Carolina service territories. Enrollment options for residential customers that participate in the pilot include a one-time incentive of up to $9,000 for the installation of a solar plus battery system. The program was launched in May 2024 and successfully enrolled more than 1,300 customers in its first three months, providing another impactful way for our customers to save energy and money, while exploring new solutions to help manage low carbon grids of the future.


MD&A			DUKE ENERGY

Regulatory Activity. During the nine months ended September 30, 2024, we continued to move our regulatory strategy forward. See Note 4 to the Condensed Consolidated Financial Statements, "Regulatory Matters," for additional information.

In January 2024, Duke Energy Carolinas filed a South Carolina rate case, the first base rate case filed by Duke Energy Carolinas in the state since 2018 and reflecting the South Carolina retail allocation of significant investments, including approximately $1.5 billion of transmission and distribution assets. In May 2024, we reached a constructive comprehensive settlement with certain parties and in July 2024, the PSCSC issued an order approving the settlement and revising recovery of certain environmental compliance costs. New rates were effective August 1, 2024.
In April 2024, we filed formal requests for new base rates across several jurisdictions including Duke Energy Florida, Duke Energy Indiana and Piedmont.
Duke Energy Florida filed a three-year rate plan that will begin in January 2025, once its current base rate settlement agreement concludes at the end of 2024, and proposed approximately $4.9 billion in incremental investments to reduce outages, expand solar generation, and increase generation unit efficiency. In August 2024, the FPSC approved our constructive comprehensive settlement with certain parties, allowing us to continue making important investments to reduce outages, shorten response times, meet future energy demands, increase clean, solar generation and explore innovative technologies to generate cost savings for our customers.
Duke Energy Indiana filed a general rate case with the IURC requesting an overall increase in revenues of $492 million. This is the first base rate case filed by Duke Energy Indiana since 2019 and reflects strategic investments to improve grid reliability and security, serve a growing customer base, and meet environmental regulations. These investments, which include approximately 345 miles of new power lines expected to be constructed through 2025, will support the more than 60,000 new customers anticipated since our last base rate case.
Piedmont filed a general rate case with the NCUC, its first base rate case in North Carolina since 2021, reflecting significant investments to support ongoing service reliability, system growth, and compliance with federal pipeline safety regulations in addition to two energy reliability centers in eastern North Carolina. In September 2024, we reached a constructive comprehensive settlement with certain parties. Revised interim rates were effective November 1, 2024, subject to refund and pending NCUC approval of the settlement and a final order.
Also, in April 2024, Duke Energy Progress issued $177 million of storm recovery bonds, our first issuance under South Carolina's 2022 securitization legislation, which provided the necessary framework for us to lower the bill impacts on our customers related to critical storm restoration activities.

Matters Impacting Future Results

The matters discussed herein could materially impact the future operating results, financial condition and cash flows of the Duke Energy Registrants and Business Segments.

Regulatory Matters

Coal Ash Costs

Cost recovery for future expenditures is anticipated and will be pursued through the normal ratemaking process with federal and state utility commissions, which permit recovery of reasonable and prudently incurred costs associated with Duke Energy’s regulated operations. The majority of spend is expected to occur over the next 10 years. For more information, see "Other Matters" and Notes 4 and 7 to the Condensed Consolidated Financial Statements, "Regulatory Matters" and "Asset Retirement Obligations."

Fuel Cost Recovery

As a result of rapidly rising commodity costs during 2022, including natural gas, fuel and purchased power prices in excess of amounts included in fuel-related revenues led to an increase in the under collection of fuel costs from customers in jurisdictions including those served by Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida. These amounts have been deferred in regulatory assets and impacted the cash flows of the registrants, including increased borrowings to temporarily finance related expenditures until recovery. Regulatory filings have been made and approved for recovery of all remaining uncollected 2022 fuel costs. Across all jurisdictions, Duke Energy is currently on pace to recover approximately $1.8 billion of deferred fuel costs in 2024 and we anticipate being in line with our historical average balance of deferred fuel costs by the end of this year.

Storm Cost Recovery

Beginning in the third quarter of 2024, a series of major storm events occurred that resulted in significant damage to utility infrastructure within our service territories and primarily impacted Duke Energy Carolinas', Duke Energy Progress' and Duke Energy Florida's electric utility operations. Hurricanes Debby, Helene and Milton caused widespread outages and included unprecedented damage to certain assets, including the hardest-hit areas on the western coast of Florida and certain regions in western North Carolina and upstate South Carolina. Appropriate storm cost recovery mechanisms are in place to track and recover incremental costs from such events. Funding restoration activities and, in some cases, the complete rebuild of critical infrastructure, for a series of sequential events of this magnitude has resulted in incremental financing needs until cost recovery occurs and may impact the near-term results of operations, financial position, or cash flows of the impacted registrants. For more information related to storm cost estimates, regulatory asset deferrals, and financing activities, see "Liquidity and Capital Resources" and Notes 4 and 6 to the Condensed Consolidated Financial Statements, "Regulatory Matters" and "Debt and Credit Facilities."


MD&A			MATTERS IMPACTING FUTURE RESULTS

EPA Regulations of GHG Emissions

In April 2024, the EPA issued a final rule under section 111 of the Clean Air Act (EPA Rule 111) regulating GHG emissions from existing coal-fired and new natural gas-fired power plants. Duke Energy is analyzing the potential impacts the rule could have on the Company, which could be material and may influence the timing, nature, and magnitude of future generation investments in our service territories. Cost recovery for future expenditures will be pursued through the normal ratemaking process with federal and state utility commissions, which permit recovery of reasonable and prudently incurred costs associated with Duke Energy’s regulated operations. Duke Energy is participating in legal challenges to the final rule. For more information, see "Other Matters."

Supply Chain

The Company continues to monitor the ongoing stability of markets for key materials and other developments, including public policy outcomes, that could disrupt or impact the Company's supply chain and, as a result, may impact Duke Energy's execution of its capital plan, future financial results or the achievement of its clean energy goals.

Goodwill

The Duke Energy Registrants performed their annual goodwill impairment tests as of August 31, 2024. As of this date, all of the Duke Energy Registrants' reporting units' estimated fair values materially exceeded the carrying values except for the GU&I reporting unit of Duke Energy Ohio. While no goodwill impairment charges were recorded in 2024, the potential for deteriorating economic conditions impacting GU&I's future cash flows or equity valuations of peer companies could impact the estimated fair value of GU&I, and goodwill impairment charges could be recorded in the future.

Other

Duke Energy continues to monitor general market conditions, including the potential for interest rate pressures on the Company's cost of capital, which may impact Duke Energy's execution of its capital plan, future financial results, or the achievement of its clean energy goals.

Results of Operations

Non-GAAP Measures

Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP in the U.S., as well as certain non-GAAP financial measures, adjusted earnings and adjusted EPS, discussed below. Non-GAAP financial measures are numerical measures of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP measures presented may not be comparable to similarly titled measures used by other companies because other companies may not calculate the measures in the same manner.

Management evaluates financial performance in part based on non-GAAP financial measures, including adjusted earnings and adjusted EPS. Adjusted earnings and adjusted EPS represent income from continuing operations available to Duke Energy Corporation common stockholders in dollar and basic per share amounts, adjusted for the dollar and per share impact of special items. As discussed below, special items represent certain charges and credits, which management believes are not indicative of Duke Energy's ongoing performance. The most directly comparable GAAP measures for adjusted earnings and adjusted EPS are GAAP Reported Earnings (Loss) and GAAP Reported Basic Earnings (Loss) Per Share, respectively.

Special items included in the periods presented below include the following, which management believes do not reflect ongoing costs:

Regulatory Matters primarily represents impairment charges related to Duke Energy Carolinas' South Carolina rate case order in 2024 and the Duke Energy North Carolina rate case settlement and Duke Energy Progress' North Carolina rate case order in 2023.
System Post-Implementation Costs represents the net impact of charges related to nonrecurring customer billing adjustments as a result of implementation of a new customer system.
Preferred Redemption Costs represents charges related to the redemption of Series B Preferred Stock.

Discontinued operations primarily represents the operating results and impairments recognized related to the sale of Duke Energy's Commercial Renewables Disposal Groups.

Three Months Ended September 30, 2024, as compared to September 30, 2023

GAAP reported EPS was $1.60 for the three months ended September 30, 2024, compared to $1.59 for the three months ended September 30, 2023. In addition to the drivers below, GAAP reported EPS increased primarily due to higher impairments on the sale of the Commercial Renewables business in the prior year.

As discussed above, management also evaluates financial performance based on adjusted EPS. Duke Energy’s third quarter 2024 adjusted EPS was $1.62 compared to $1.94 for the third quarter of 2023. The decrease in adjusted EPS was primarily due to a higher effective tax rate, storm costs, interest expense, and depreciation expense on a growing asset base, partially offset by growth from rate increases and riders.


MD&A			DUKE ENERGY

The following table reconciles non-GAAP measures, including adjusted EPS, to their most directly comparable GAAP measures.


	Three Months Ended September 30,
	2024				2023
(in millions, except per share amounts)	Earnings		EPS		Earnings		EPS

GAAP Reported Earnings/GAAP Reported Earnings Per Share	$	1,226	$	1.60	$	1,213	$	1.59
Adjustments:
Regulatory Matters(a)	—		—		84		0.11
System Post-Implementation Costs(b)	16		0.02		—		—
Preferred Redemption Costs(c)	16		0.02		—		—


Discontinued Operations(d)	(22)		(0.03)		190		0.24
Adjusted Earnings/Adjusted EPS	$	1,236	$	1.62	$	1,487	$	1.94

Note: Total EPS may not foot due to rounding.

(a)Net of $27 million tax benefit. $95 million recorded within Impairment of assets and other charges and $16 million recorded within Operations, maintenance and other.

(b)Net of $5 million tax benefit. $17 million recorded within Operating Revenues, $1 million recorded within Operations, maintenance and other and $3 million recorded within Other Income and expenses.

(c)Recorded within Preferred Redemption Costs.

(d)Recorded in Income (Loss) from Discontinued Operations, net of tax, and Net Income Attributable to Noncontrolling Interests.

Nine Months Ended September 30, 2024, as compared to September 30, 2023

GAAP Reported EPS was $4.17 for the nine months ended September 30, 2024, compared to $2.27 for the nine months ended September 30, 2023. In addition to the drivers below, GAAP reported EPS increased primarily due to higher impairments on the sale of the Commercial Renewables business in the prior year.

As discussed above, management also evaluates financial performance based on adjusted EPS. Duke Energy’s adjusted EPS was $4.24 for the nine months ended September 30, 2024, compared to $4.05 for the nine months ended September 30, 2023. The increase in adjusted EPS was primarily due to growth from rate increases and riders, higher sales volumes and favorable weather, partially offset by a higher effective tax rate, interest expense, and depreciation expense on a growing asset base.

The following table reconciles non-GAAP measures, including adjusted EPS, to their most directly comparable GAAP measures.


	Nine Months Ended September 30,
	2024				2023
(in millions, except per share amounts)	Earnings		EPS		Earnings		EPS
GAAP Reported Earnings/GAAP Reported EPS	$	3,211	$	4.17	$	1,744	$	2.27
Adjustments:
Regulatory Matters(a)	25		0.03		84		0.11
System Post-Implementation Costs(b)	16		0.02		—		—
Preferred Redemption Costs(c)	16		0.02		—		—


Discontinued Operations(d)	(9)		(0.01)		1,283		1.67
Adjusted Earnings/Adjusted EPS	$	3,259	$	4.24	$	3,111	$	4.05

Note: Total EPS may not foot due to rounding.

(a)Net of $8 million tax benefit and $27 million tax benefit for the nine months ended September 30, 2024, and 2023, respectively. $42 million recorded within Impairment of assets and other charges, $2 million within Operations, maintenance and other, and an $11 million reduction recorded within Interest Expense for the nine months ended September 30, 2024. $95 million recorded within Impairment of assets and other charges and $16 million recorded within Operations, maintenance and other for the nine months ended September 30, 2023.

(c)Recorded within Preferred Redemption Costs.

(d)Recorded in Income (Loss) from Discontinued Operations, net of tax, and Net Income Attributable to Noncontrolling Interests.

SEGMENT RESULTS

The remaining information presented in this discussion of results of operations is on a GAAP basis. Management evaluates segment performance based on segment income. Segment income is defined as income from continuing operations net of income attributable to noncontrolling interests and preferred stock dividends. Segment income includes intercompany revenues and expenses that are eliminated in the Condensed Consolidated Financial Statements.

Duke Energy's segment structure includes the following segments: EU&I and GU&I. The remainder of Duke Energy’s operations is presented as Other. See Note 3 to the Condensed Consolidated Financial Statements, “Business Segments,” for additional information on Duke Energy’s segment structure.


MD&A			SEGMENT RESULTS — ELECTRIC UTILITIES AND INFRASTRUCTURE

Electric Utilities and Infrastructure


	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2024		2023		Variance		2024		2023		Variance
Operating Revenues	$	7,852	$	7,715	$	137	$	21,475	$	20,363	$	1,112
Operating Expenses
Fuel used in electric generation and purchased power	2,664		2,591		73		7,266		7,045		221
Operation, maintenance and other	1,387		1,398		(11)		3,965		4,008		(43)
Depreciation and amortization	1,352		1,209		143		3,823		3,493		330
Property and other taxes	345		392		(47)		1,033		1,077		(44)
Impairment of assets and other charges	(5)		88		(93)		38		100		(62)
Total operating expenses	5,743		5,678		65		16,125		15,723		402
Gains on Sales of Other Assets and Other, net	2		2		—		9		30		(21)
Operating Income	2,111		2,039		72		5,359		4,670		689
Other Income and Expenses, net	129		131		(2)		401		388		13
Interest Expense	514		468		46		1,501		1,364		137
Income Before Income Taxes	1,726		1,702		24		4,259		3,694		565
Income Tax Expense	244		224		20		631		531		100
Less: Income Attributable to Noncontrolling Interest	31		31		—		66		75		(9)
Segment Income	$	1,451	$	1,447	$	4	$	3,562	$	3,088	$	474

Duke Energy Carolinas GWh sales	24,848		24,810		38		69,720		66,367		3,353
Duke Energy Progress GWh sales	19,107		19,704		(597)		52,439		50,503		1,936
Duke Energy Florida GWh sales	13,423		13,665		(242)		34,124		34,055		69
Duke Energy Ohio GWh sales	6,804		6,356		448		18,494		17,694		800
Duke Energy Indiana GWh sales	8,550		8,526		24		23,541		22,803		738
Total Electric Utilities and Infrastructure GWh sales	72,732		73,061		(329)		198,318		191,422		6,896
Net proportional MW capacity in operation							54,416		54,407		9

Three Months Ended September 30, 2024, as compared to September 30, 2023

EU&I’s results were driven by higher revenues from rate cases across multiple jurisdictions and higher weather-normal retail sales volumes, offset by higher depreciation. The following is a detailed discussion of the variance drivers by line item.

Operating Revenues. The variance was driven primarily by:

a $152 million increase due to higher pricing from jurisdictional rate cases primarily at Duke Energy Carolinas and Duke Energy Progress and the 2021 Settlement at Duke Energy Florida;
a $96 million increase in weather-normal retail sales volumes; and
a $94 million increase in fuel revenues primarily due to net higher fuel cost recovery in the current year.

Partially offset by:

a $92 million decrease in storm revenues at Duke Energy Florida;
a $51 million decrease in rider revenues primarily due to a decrease in the return of EDIT to customers at Duke Energy Carolinas;
a $32 million decrease in retail sales due to unfavorable weather compared to prior year, including the impacts of decoupling; and
a $12 million decrease in franchise tax revenue primarily due to decreased revenues over prior year at Duke Energy Florida.

Operating Expenses*.* The variance was driven primarily by:

*•*a $143 million increase in depreciation and amortization primarily due to higher depreciable base and higher net amortizations driven by the North Carolina rate cases at Duke Energy Carolinas and Duke Energy Progress and lower amortization of the DOE settlement regulatory liability and higher depreciable base at Duke Energy Florida; and

a $73 million increase in fuel used in electric generation and purchased power due to higher recovery of fuel expense at Duke Energy Carolinas and Duke Energy Progress, partially offset by lower deferred fuel amortization and lower fuel prices and volumes at Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana.


MD&A			SEGMENT RESULTS — ELECTRIC UTILITIES AND INFRASTRUCTURE

Partially offset by:

*•*a $93 million decrease in impairments of assets and other charges primarily related to the prior year rate case impacts at Duke Energy Carolinas and Duke Energy Progress;

a $47 million decrease in property and other taxes due to lower property taxes and lower franchise and gross receipts tax driven by lower revenues at Duke Energy Florida; and
an $11 million decrease in operation, maintenance and other primarily driven by lower storm amortization at Duke Energy Florida, lower storm and nuclear outage costs at Duke Energy Progress, partially offset by higher storm costs at Duke Energy Carolinas.

Interest Expense. The increase was primarily driven by higher outstanding debt balances and interest rates.

Income Tax Expense. The increase in tax expense was primarily due to an increase in pretax income and the decrease in the amortization of EDIT. The ETRs for the three months ended September 30, 2024, and 2023, were 14.1% and 13.2%, respectively. The increase in the ETR is primarily due to a decrease in the amortization of EDIT.

Nine Months Ended September 30, 2024, as compared to September 30, 2023

EU&I’s results were driven by higher revenues from rate cases across multiple jurisdictions, improved weather, and higher weather-normal retail sales volumes, partially offset by higher depreciation. The following is a detailed discussion of the variance drivers by line item.

Operating Revenues. The variance was driven primarily by:

a $458 million increase due to higher pricing from jurisdictional rate cases primarily at Duke Energy Carolinas, Duke Energy Progress and Duke Energy Kentucky and the 2021 Settlement at Duke Energy Florida;
a $259 million increase in retail sales due to improved weather compared to prior year, including the impacts of decoupling;
a $204 million increase in weather-normal retail sales volumes;
a $195 million increase in fuel revenues primarily due to net higher fuel cost recovery in the current year;
a $63 million increase in other revenues for customer programs at Duke Energy Florida; and
a $50 million increase in rider revenues primarily for the Distribution Capital Investment Rider at Duke Energy Ohio.

Partially offset by:

a $127 million decrease in storm revenues at Duke Energy Florida.

Operating Expenses*.* The variance was driven primarily by:

*•*a $330 million increase in depreciation and amortization primarily due to lower amortization of the DOE settlement regulatory liability and higher depreciable base at Duke Energy Florida and higher depreciable base and higher net amortizations driven by the North Carolina rate cases at Duke Energy Carolinas and Duke Energy Progress; and

*•*a $221 million increase in fuel used in electric generation and purchased power due to higher recovery of fuel expense at Duke Energy Carolinas and Duke Energy Progress, partially offset by lower deferred fuel amortization and lower fuel prices and volumes at Duke Energy Indiana, Duke Energy Florida and Duke Energy Ohio.

Partially offset by:

a $62 million decrease in impairment of assets and other charges primarily related to the prior year North Carolina rate case impacts at Duke Energy Carolinas and Duke Energy Progress;
a $44 million decrease in property and other taxes due to lower property taxes and lower franchise and gross receipts tax driven by lower revenues at Duke Energy Florida; and
a $43 million decrease in operation, maintenance and other primarily driven by lower storm amortization at Duke Energy Florida and lower outage work at Duke Energy Indiana, partially offset by higher employee-related expenses, higher customer charge-offs and higher storm costs at Duke Energy Carolinas.

Gains on Sales of Other Assets and Other, net. The decrease was primarily due to the sale of the Mint Street parking deck in the prior year at Duke Energy Carolinas.

Interest Expense. The increase was primarily driven by higher outstanding debt balances and interest rates.

Income Tax Expense. The increase in tax expense was primarily due to an increase in pretax income. The ETRs for the nine months ended September 30, 2024, and 2023, were 14.8% and 14.4%, respectively.


MD&A			SEGMENT RESULTS — GAS UTILITIES AND INFRASTRUCTURE

Gas Utilities and Infrastructure


	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2024		2023		Variance		2024		2023		Variance
Operating Revenues	$	332	$	313	$	19	$	1,615	$	1,583	$	32
Operating Expenses
Cost of natural gas	70		57		13		380		434		(54)
Operation, maintenance and other	113		103		10		359		332		27
Depreciation and amortization	100		88		12		294		257		37
Property and other taxes	36		32		4		120		93		27
Impairment of assets and other charges	—		—		—		—		(4)		4
Total operating expenses	319		280		39		1,153		1,112		41
Losses on Sales of Other Assets and Other, net	—		—		—		—		(1)		1
Operating Income	13		33		(20)		462		470		(8)



Other Income and Expenses, net	15		39		(24)		49		86		(37)
Interest Expense	67		56		11		189		158		31
(Loss) Income Before Income Taxes	(39)		16		(55)		322		398		(76)
Income Tax (Benefit) Expense	(14)		1		(15)		57		71		(14)

Segment (Loss) Income	$	(25)	$	15	$	(40)	$	265	$	327	$	(62)

Piedmont LDC throughput (dekatherms)	162,163,516		143,224,608		18,938,908		453,695,306		426,926,457		26,768,849
Duke Energy Midwest LDC throughput (Mcf)	9,607,415		9,745,709		(138,294)		55,774,760		55,298,840		475,920

Three Months Ended September 30, 2024, as compared to September 30, 2023

GU&I’s results were impacted primarily by higher depreciation and amortization and interest expense, partially offset by higher margin growth. The following is a detailed discussion of the variance drivers by line item.

Operating Revenues. The variance was driven primarily by:

a $5 million increase due to higher base rates, primarily from the Duke Energy Ohio rate case, partially offset by lower rider revenue at Duke Energy Ohio;
a $4 million increase due to unregulated Renewable Natural Gas (RNG) revenue;
a $4 million increase due to the North Carolina IMR; and
a $4 million increase due to Tennessee ARM revenue.

Operating Expenses. The variance was driven primarily by:

a $13 million increase in cost of natural gas due to higher volumes and higher rates passed through to customers;
a $12 million increase in depreciation and amortization due to higher depreciable base; and
a $10 million increase in operations, maintenance and other primarily due to higher employee-related costs, higher operating costs for new RNG projects and higher spend for outside services.

Other Income and Expenses, net. The decrease was primarily due to the revision in the prior year related to the Atlantic Coast Pipeline (ACP) ARO closure cost.

Interest Expense. The increase was primarily due to higher outstanding debt balances and interest rates.

Income Tax (Benefit) Expense**.** The increase in tax benefit was primarily due to a decrease in pretax income. The ETRs for the three months ended September 30, 2024, and 2023, were 35.9% and 6.3%, respectively. The increase in the ETR was primarily due to the amortization of EDIT in relation to pretax losses.

Nine Months Ended September 30, 2024, as compared to September 30, 2023

GU&I’s results were impacted primarily by higher depreciation and amortization, higher interest expense and higher property and other taxes, partially offset by higher margin growth. The following is a detailed discussion of the variance drivers by line item.


MD&A			SEGMENT RESULTS — GAS UTILITIES AND INFRASTRUCTURE

Operating Revenues. The variance was driven primarily by:

a $31 million increase due to higher base rates, primarily from the Duke Energy Ohio rate case, partially offset by lower rider revenue at Duke Energy Ohio;
a $21 million increase due to Tennessee ARM revenue;
a $16 million increase due to the North Carolina IMR;
a $16 million increase due to unregulated RNG revenue; and
a $10 million increase due to rate stabilization mechanisms in South Carolina.

Partially offset by:

a $66 million decrease due to lower natural gas costs passed through to customers and lower rates, partially offset by higher volumes.

Operating Expenses. The variance was driven primarily by:

a $37 million increase in depreciation and amortization due to higher depreciable base, higher depreciation for certain unregulated RNG projects and lower CEP deferrals;
a $27 million increase in property and other taxes due to a higher base upon which property taxes are levied; and
a $27 million increase in operations, maintenance and other primarily due to higher operating costs for new RNG projects, higher employee-related costs, higher IT project costs and higher spend for outside services.

Partially offset by:

a $54 million decrease in cost of natural gas due to lower natural gas costs passed through to customers and lower rates, partially offset by higher volumes.

Other Income and Expenses, Net. The decrease was primarily due to the revision in the prior year related to the ACP ARO closure cost and lower revenue in the current year at SustainRNG.

Interest Expense. The increase was primarily due to higher outstanding debt balances and interest rates.

Income Tax (Benefit) Expense. The decrease in tax expense was primarily due to a decrease in pretax income. The ETRs for the nine months ended September 30, 2024, and 2023, were 17.7% and 17.8%, respectively.

Other


	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2024		2023		Variance		2024		2023		Variance
Operating Revenues	$	42	$	33	$	9	$	120	$	98	$	22






Operating Expenses	31		4		27		157		53		104
Gains on Sales of Other Assets and Other, net	5		5		—		16		16		—
Operating Income (Loss)	16		34		(18)		(21)		61		(82)
Other Income and Expenses, net	72		47		25		218		168		50
Interest Expense	321		283		38		921		810		111
Loss Before Income Taxes	(233)		(202)		(31)		(724)		(581)		(143)
Income Tax Benefit	(66)		(182)		116		(207)		(285)		78

Less: Preferred Dividends	39		39		—		92		92		—
Less: Preferred Redemption Costs	16		—		16		16		—		16
Net Loss	$	(222)	$	(59)	$	(163)	$	(625)	$	(388)	$	(237)

Three Months Ended September 30, 2024, as compared to September 30, 2023

Other's results were impacted by a favorable prior year adjustment related to certain allowable tax deductions and higher interest expense driven by higher outstanding long-term debt balances and interest rates.

Operating Expenses. The increase was driven by franchise tax benefits recognized in the prior year.

Other Income and Expenses, net. The variance was primarily due to higher return on investments that fund certain employee benefit obligations and higher yields on captive insurance investments, partially offset by lower equity earnings from the NMC investment.

Interest Expense. The increase was primarily due to higher outstanding long-term debt balances and interest rates.


MD&A			SEGMENT RESULTS — GAS UTILITIES AND INFRASTRUCTURE

Income Tax Benefit. The decrease in the tax benefit was primarily due to the benefits associated with the tax efficiency efforts in the prior year. The ETRs for the three months ended September 30, 2024, and 2023, were 28.3% and 90.1%, respectively. The decrease in the ETR was primarily due to benefits associated with tax efficiency efforts in the prior year. In 2023, the Company evaluated the deductibility of certain items spanning periods open under federal statute, including items related to interest on company-owned life insurance. As a result of this analysis, the Company recorded a favorable adjustment in the prior year of approximately $120 million.

Preferred Redemption Costs. The increase was due to the redemption of the Company’s Series B Preferred Stock.

Nine Months Ended September 30, 2024, as compared to September 30, 2023

Other's results were impacted by higher interest expense driven by higher outstanding long-term debt balances and interest rates and decreases in the income tax benefit and franchise tax benefits.

Operating Revenues. The increase was primarily driven by favorable premiums related to captive insurance.

Operating Expenses. The increase was driven by franchise tax benefits recognized in the prior year, higher claim reserves related to captive insurance, contributions to the Duke Energy Foundation and increased expense on certain employee benefit obligations in the current year.

Other Income and Expenses, net. The variance was primarily due to higher return on investments that fund certain employee benefit obligations and higher yields on captive insurance investments.

Interest Expense. The increase was primarily due to higher outstanding long-term debt balances and interest rates.

Income Tax Benefit. The decrease in the tax benefit was primarily due to the benefits associated with tax efficiency efforts in the prior year, partially offset by an increase in pretax losses. The ETRs for the nine months ended September 30, 2024, and 2023, were 28.6% and 49.1%, respectively. The decrease in the ETR was primarily due to benefits associated with tax efficiency efforts in the prior year. In 2023, the Company evaluated the deductibility of certain items spanning periods open under federal statute, including items related to interest on company-owned life insurance. As a result of this analysis, the Company recorded a favorable adjustment in the prior year of approximately $120 million.

Preferred Redemption Costs. The increase was due to the redemption of the Company’s Series B Preferred Stock.

INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX


	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2024		2023		Variance		2024		2023		Variance
Income (Loss) From Discontinued Operations, net of tax	$	25	$	(152)	$	177	$	12	$	(1,316)	$	1,328

Three Months Ended September 30, 2024, as compared to September 30, 2023

The variance was primarily driven by impairments on the sale of the Commercial Renewables business recorded in the prior year.

Nine Months Ended September 30, 2024, as compared to September 30, 2023

The variance was primarily driven by impairments on the sale of the Commercial Renewables business recorded in the prior year.

DUKE ENERGY CAROLINAS

Results of Operations


	Nine Months Ended September 30,
(in millions)	2024		2023		Variance
Operating Revenues	$	7,411	$	6,155	$	1,256
Operating Expenses
Fuel used in electric generation and purchased power	2,531		1,823		708
Operation, maintenance and other	1,358		1,285		73
Depreciation and amortization	1,306		1,186		120
Property and other taxes	271		276		(5)
Impairment of assets and other charges	32		70		(38)
Total operating expenses	5,498		4,640		858
Gains on Sales of Other Assets and Other, net	1		26		(25)
Operating Income	1,914		1,541		373
Other Income and Expenses, net	181		181		—
Interest Expense	537		504		33
Income Before Income Taxes	1,558		1,218		340
Income Tax Expense	153		97		56
Net Income	$	1,405	$	1,121	$	284


MD&A			DUKE ENERGY CAROLINAS

The following table shows the percent changes in GWh sales and average number of customers. The percentages for retail customer classes represent billed sales only. Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities, public and private utilities and power marketers. Amounts are not weather-normalized.


Increase (Decrease) over prior year	2024
Residential sales	5.8	%
General service sales	4.0	%
Industrial sales	(0.2)	%
Wholesale power sales	14.1	%
Joint dispatch sales	2.3	%
Total sales	5.1	%
Average number of customers	2.2	%

Nine Months Ended September 30, 2024, as compared to September 30, 2023

Operating Revenues. The variance was driven primarily by:

a $688 million increase in fuel revenues due to higher fuel rates and volumes;
a $277 million increase due to higher pricing from the North Carolina and South Carolina rate cases;
a $129 million increase in retail sales due to improved weather compared to prior year, including the impacts of decoupling;
a $93 million increase in weather-normal retail sales volumes; and
a $27 million increase in wholesale power revenues primarily due to higher contractual demand and sales.

Operating Expenses**.** The variance was driven primarily by:

a $708 million increase in fuel used in electric generation and purchased power primarily due to the recovery of fuel expense, and higher volumes, partially offset by lower natural gas prices;

*•*a $120 million increase in depreciation and amortization primarily due to higher depreciable base and higher net amortizations driven by the North Carolina rate case; and

*•*a $73 million increase in operation, maintenance and other primarily due to higher employee-related expenses, higher customer charge-offs and higher storm costs.

Partially offset by:

a $38 million decrease in impairment of assets and other charges primarily related to the prior year North Carolina rate case order and the current year South Carolina rate case order.

Gains on Sales of Other Assets and Other, net. The decrease was primarily due to the sale of the Mint Street parking deck in the prior year.

Interest Expense. The increase was primarily due to higher outstanding debt balances and interest rates.

Income Tax Expense. The increase in tax expense was primarily due to an increase in pretax income, partially offset by an increase in the amortization of EDIT.


MD&A			PROGRESS ENERGY

PROGRESS ENERGY

Results of Operations


	Nine Months Ended September 30,
(in millions)	2024		2023		Variance
Operating Revenues	$	10,445	$	10,315	$	130
Operating Expenses
Fuel used in electric generation and purchased power	3,729		3,902		(173)
Operation, maintenance and other	1,869		1,963		(94)
Depreciation and amortization	1,795		1,609		186
Property and other taxes	494		546		(52)
Impairment of assets and other charges	6		29		(23)
Total operating expenses	7,893		8,049		(156)
Gains on Sales of Other Assets and Other, net	20		20		—
Operating Income	2,572		2,286		286
Other Income and Expenses, net	178		146		32
Interest Expense	796		706		90
Income Before Income Taxes	1,954		1,726		228
Income Tax Expense	320		280		40
Net Income	$	1,634	$	1,446	$	188

Nine Months Ended September 30, 2024, as compared to September 30, 2023

Operating Revenues. The variance was driven primarily by:

a $150 million increase due to higher pricing from the North Carolina and South Carolina rate cases at Duke Energy Progress and the 2021 Settlement at Duke Energy Florida;
a $99 million increase in weather-normal retail sales volumes at Duke Energy Progress;
an $86 million increase in retail sales due to improved weather compared to prior year, including the impacts of decoupling, at Duke Energy Progress and Duke Energy Florida;
a $63 million increase in Clean Energy Connection subscription revenues, higher residential fixed bill program revenues and higher transmission revenues at Duke Energy Florida;
a $42 million increase in rider revenues primarily due to higher rates for the Storm Protection Plan at Duke Energy Florida; and
a $12 million increase in wholesale revenues, net of fuel, due to higher sales volumes and capacity rates at Duke Energy Progress.

Partially offset by:

a $159 million decrease in fuel and capacity revenues primarily due to lower fuel and capacity rates billed to retail customers at Duke Energy Florida, partially offset by an increase in fuel rates and volumes at Duke Energy Progress;
a $127 million decrease in storm revenues at Duke Energy Florida; and
a $25 million decrease in franchise tax revenue primarily due to decreased revenues over prior year at Duke Energy Florida.

Operating Expenses. The variance was driven primarily by:

*•*a $173 million decrease in fuel used in electric generation and purchased power primarily due to a decrease in purchased power costs driven by expiration of contracts in current year, lower fuel costs driven by lower natural gas prices and a decrease due to fuel cost recovery at Duke Energy Florida, partially offset by higher volumes and recovery of fuel expenses at Duke Energy Progress;

a $94 million decrease in operation, maintenance and other primarily due to lower storm amortization at Duke Energy Florida;
a $52 million decrease in property and other taxes primarily due to lower property taxes and lower franchise and gross receipts tax driven by lower revenues at Duke Energy Florida; and
a $23 million decrease in impairment of assets and other charges due to prior year rate case impacts at Duke Energy Progress.

Partially offset by:

*•*a $186 million increase in depreciation and amortization due to lower amortization of the DOE settlement regulatory liability and higher depreciable base at Duke Energy Florida and higher net amortizations driven by the North Carolina rate case and higher depreciable base at Duke Energy Progress.


MD&A			PROGRESS ENERGY

Other Income and Expenses, net. The increase was primarily driven by miscellaneous income and AFUDC equity due to higher AFUDC base compared to prior year at Duke Energy Progress and other post-employment benefit activity at Duke Energy Florida.

Interest Expense. The increase was primarily due to higher outstanding debt balances and interest rates at Duke Energy Progress.

Income Tax Expense. The increase in tax expense was primarily due to an increase in pretax income, partially offset by an increase in PTCs.

DUKE ENERGY PROGRESS

Results of Operations


	Nine Months Ended September 30,
(in millions)	2024		2023		Variance
Operating Revenues	$	5,338	$	4,844	$	494
Operating Expenses
Fuel used in electric generation and purchased power	1,896		1,685		211
Operation, maintenance and other	1,077		1,051		26
Depreciation and amortization	999		935		64
Property and other taxes	144		143		1
Impairment of assets and other charges	6		31		(25)
Total operating expenses	4,122		3,845		277
Gains on Sales of Other Assets and Other, net	2		2		—
Operating Income	1,218		1,001		217
Other Income and Expenses, net	107		92		15
Interest Expense	370		315		55
Income Before Income Taxes	955		778		177
Income Tax Expense	135		101		34
Net Income	$	820	$	677	$	143


Increase (Decrease) over prior period	2024
Residential sales	4.4	%
General service sales	3.6	%
Industrial sales	(3.5)	%
Wholesale power sales	4.3	%
Joint dispatch sales	4.8	%
Total sales	3.8	%
Average number of customers	2.1	%

Nine Months Ended September 30, 2024, as compared to September 30, 2023

Operating Revenues. The variance was driven primarily by:

a $227 million increase in fuel revenues due to higher fuel rates and volumes;
a $99 million increase in weather-normal retail sales volumes;
a $96 million increase due to higher pricing from the North Carolina and South Carolina rate cases;
a $74 million increase in retail sales due to improved weather compared to prior year, including the impacts of decoupling; and
a $12 million increase in wholesale revenues, net of fuel, due to higher sales volumes and capacity rates.

Operating Expenses. The variance was driven primarily by:

a $211 million increase in fuel used in electric generation and purchased power primarily due to the recovery of fuel expenses and higher volumes, partially offset by lower natural gas prices;

*•*a $64 million increase in depreciation and amortization primarily due to higher net amortizations driven by the North Carolina rate case and higher depreciable base; and

a $26 million increase in operation, maintenance and other primarily due to higher storm costs and higher employee-related expenses, partially offset by lower project costs.


MD&A			DUKE ENERGY PROGRESS

Partially offset by:

*•*a $25 million decrease in impairment of assets and other charges primarily due to prior year rate case impacts.

Other Income and Expenses, net. The increase was driven primarily by miscellaneous income and AFUDC equity due to higher AFUDC base compared to prior year.

Interest Expense. The increase was driven primarily by higher outstanding debt balances and interest rates.

Income Tax Expense. The increase in tax expense was primarily due to an increase in pretax income.

DUKE ENERGY FLORIDA

Results of Operations


	Nine Months Ended September 30,
(in millions)	2024		2023		Variance
Operating Revenues	$	5,092	$	5,456	$	(364)
Operating Expenses
Fuel used in electric generation and purchased power	1,833		2,218		(385)
Operation, maintenance and other	779		898		(119)
Depreciation and amortization	796		674		122
Property and other taxes	350		403		(53)
Impairment of assets and other charges	—		(1)		1
Total operating expenses	3,758		4,192		(434)
Gains on Sales of Other Assets and Other, net	2		1		1
Operating Income	1,336		1,265		71
Other Income and Expenses, net	67		56		11
Interest Expense	339		305		34
Income Before Income Taxes	1,064		1,016		48
Income Tax Expense	212		206		6
Net Income	$	852	$	810	$	42

The following table shows the percent changes in GWh sales and average number of customers. The percentages for retail customer classes represent billed sales only. Wholesale power sales include both billed and unbilled sales. Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities, public and private utilities and power marketers. Amounts are not weather-normalized.


Increase (Decrease) over prior period	2024
Residential sales	—	%
General service sales	0.7	%
Industrial sales	(1.1)	%
Wholesale power sales	(6.1)	%
Total sales	0.2	%
Average number of customers	2.2	%

Nine Months Ended September 30, 2024, as compared to September 30, 2023

Operating Revenues. The variance was driven primarily by:

a $385 million decrease in fuel and capacity revenues primarily due to lower fuel and capacity rates;
a $127 million decrease in storm revenues; and
a $25 million decrease in franchise tax revenue primarily due to decreased revenues over prior year.

Partially offset by:

a $63 million increase in higher transmission revenues, higher Clean Energy Connection subscription revenues and higher residential fixed bill program revenues;
a $54 million increase due to higher pricing from the 2021 Settlement;
a $42 million increase in rider revenues primarily due to higher rates for the Storm Protection Plan, Energy Conservation Cost Recovery and Environmental Cost Recovery; and
a $12 million increase in retail sales due to improved weather compared to prior year.


MD&A			DUKE ENERGY FLORIDA

Operating Expenses. The variance was driven primarily by:

a $385 million decrease in fuel used in electric generation and purchased power primarily due to lower purchased power costs driven by the expiration of contracts in the current year and lower fuel costs driven by lower natural gas prices and fuel cost recovery;
a $119 million decrease in operation, maintenance and other primarily due to lower storm amortization; and
a $53 million decrease in property and other taxes primarily due to lower property taxes and lower franchise and gross receipts tax driven by lower revenues.

Partially offset by:

a $122 million increase in depreciation and amortization primarily due to lower amortization of the DOE settlement regulatory liability and higher depreciable base.

Other Income and Expenses, net. The increase was primarily driven by other post-employment benefit activity.

Interest Expense. The increase was primarily driven by lower interest credits on recovery clauses due to lower deferred balances, higher outstanding debt balances and interest rates, partially offset by lower intercompany interest income.

DUKE ENERGY OHIO

Results of Operations


	Nine Months Ended September 30,
(in millions)	2024		2023		Variance
Operating Revenues
Regulated electric	$	1,431	$	1,411	$	20
Regulated natural gas	460		464		(4)

Total operating revenues	1,891		1,875		16
Operating Expenses
Fuel used in electric generation and purchased power	416		485		(69)
Cost of natural gas	100		118		(18)
Operation, maintenance and other	378		358		20
Depreciation and amortization	297		266		31
Property and other taxes	303		258		45

Total operating expenses	1,494		1,485		9

Operating Income	397		390		7
Other Income and Expenses, net	12		33		(21)
Interest Expense	144		125		19
Income Before Income Taxes	265		298		(33)
Income Tax Expense	42		47		(5)


Net Income	$	223	$	251	$	(28)

The following table shows the percent changes in GWh sales of electricity, dekatherms of natural gas delivered and average number of electric and natural gas customers. The percentages for retail customer classes represent billed sales only. Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities, public and private utilities and power marketers. Amounts are not weather-normalized.


	Electric		Natural Gas
Increase (Decrease) over prior year	2024		2024
Residential sales	4.8	%	(0.9)	%
General service sales	4.7	%	(0.8)	%
Industrial sales	(5.9)	%	18.7	%
Wholesale electric power sales	50.8	%	n/a
Other natural gas sales	n/a		(0.9)	%
Total sales	4.5	%	0.9	%
Average number of customers	1.1	%	0.9	%


MD&A			DUKE ENERGY OHIO

Nine Months Ended September 30, 2024, as compared to September 30, 2023

Operating Revenues. The variance was driven primarily by:

a $35 million increase in retail revenue riders primarily due to the Distribution Capital Investment Rider, Distribution Storm Rider and Uncollectible Expense Rider, partially offset by a decrease in the Energy Efficiency Rider;
a $31 million increase due to higher pricing from the Duke Energy Ohio natural gas rate case, net of decreases in the Ohio CEP rider and Accelerated Main Replacement Program Rider;
a $31 million increase due to higher pricing from the Duke Energy Kentucky electric rate case;
a $30 million increase in revenues related to higher Ohio Valley Electric Corporation (OVEC) rider collections and OVEC sales into PJM Interconnection, LLC;
a $16 million increase due to improved weather compared to prior year; and
a $14 million increase in transmission revenue.

Partially offset by:

a $147 million decrease in fuel-related revenues primarily due to lower full-service retail sales volumes, as well as decreased natural gas costs.

Operating Expenses. The variance was driven primarily by:

a $45 million increase in property and other taxes primarily due to a higher base upon which property taxes are levied, partially offset by lower franchise taxes;
a $31 million increase in depreciation and amortization primarily driven by an increase in distribution plant in service and depreciation rates resulting from the Duke Energy Kentucky electric rate case implemented in 2023 and CEP deferrals in 2024; and
a $20 million increase in operation, maintenance and other primarily due to higher employee-related expenses and storm costs.

Partially offset by:

an $87 million decrease in fuel expense primarily driven by lower retail prices for natural gas and purchased power and a decrease in purchased power volumes.

Other Income and Expenses, net. The decrease was primarily driven by lower intercompany interest income.

Interest Expense. The increase was primarily driven by higher outstanding debt balances and interest rates.

DUKE ENERGY INDIANA

Results of Operations


	Nine Months Ended September 30,
(in millions)	2024		2023		Variance
Operating Revenues	$	2,342	$	2,606	$	(264)
Operating Expenses
Fuel used in electric generation and purchased power	761		980		(219)
Operation, maintenance and other	510		524		(14)
Depreciation and amortization	507		500		7
Property and other taxes	37		42		(5)

Total operating expenses	1,815		2,046		(231)

Operating Income	527		560		(33)
Other Income and Expenses, net	44		58		(14)
Interest Expense	173		157		16
Income Before Income Taxes	398		461		(63)
Income Tax Expense	65		82		(17)
Net Income	$	333	$	379	$	(46)


MD&A			DUKE ENERGY INDIANA


Increase (Decrease) over prior year	2024
Residential sales	4.5	%
General service sales	2.1	%
Industrial sales	(0.4)	%
Wholesale power sales	(1.9)	%
Total sales	3.2	%
Average number of customers	1.7	%

Nine Months Ended September 30, 2024, as compared to September 30, 2023

Operating Revenues. The variance was driven primarily by:

a $233 million decrease in retail fuel revenues primarily due to lower fuel rates; and
a $44 million decrease in wholesale revenues, including fuel, primarily due to the expiration of wholesale customer contracts.

Partially offset by:

a $16 million increase in retail sales due to improved weather compared to prior year.

Operating Expenses. The variance was driven primarily by:

a $219 million decrease in fuel used in electric generation and purchased power primarily due to lower deferred fuel amortization as well as lower purchased power expense and natural gas costs, partially offset by higher coal costs; and
a $14 million decrease in operation, maintenance and other primarily due to lower outage costs.

Other Income and Expenses, net. The decrease was primarily due to lower intercompany interest income.

Interest Expense. The increase was primarily due to higher outstanding debt balances and interest rates.

Income Tax Expense. The decrease in tax expense was primarily due to a decrease in pretax income.

PIEDMONT

Results of Operations


	Nine Months Ended September 30,
(in millions)	2024		2023		Variance



Operating Revenues	$	1,139	$	1,119	$	20
Operating Expenses
Cost of natural gas	280		316		(36)
Operation, maintenance and other	267		248		19
Depreciation and amortization	191		175		16
Property and other taxes	47		46		1
Impairment of assets and other charges	—		(4)		4
Total operating expenses	785		781		4

Operating Income	354		338		16
Other Income and Expenses, net	48		49		(1)
Interest Expense	135		120		15
Income Before Income Taxes	267		267		—
Income Tax Expense	49		46		3
Net Income	$	218	$	221	$	(3)


MD&A			PIEDMONT

The following table shows the percent changes in dekatherms delivered and average number of customers. The percentages for all throughput deliveries represent billed and unbilled sales. Amounts are not weather-normalized.


Increase (Decrease) over prior year	2024
Residential deliveries	12.0	%
Commercial deliveries	10.3	%
Industrial deliveries	0.6	%
Power generation deliveries	6.7	%
For resale	(0.1)	%
Total throughput deliveries	6.3	%
Secondary market volumes	(8.9)	%
Average number of customers	1.6	%

Nine Months Ended September 30, 2024, as compared to September 30, 2023

Operating Revenues. The variance was driven primarily by:

a $21 million increase due to Tennessee ARM;
a $16 million increase due to North Carolina IMR;
a $10 million increase due to rate stabilization mechanisms in South Carolina; and
a $9 million increase due to customer growth.

Partially offset by:

a $36 million decrease due to lower natural gas costs passed through to customers and lower rates, partially offset by higher volumes.

Operating Expenses. The variance was driven primarily by:

a $19 million increase in operations, maintenance and other primarily due to higher employee-related costs, outside services, and service company costs; and
a $16 million increase in depreciation and amortization due to higher depreciable base.

Partially offset by:

a $36 million decrease in cost of natural gas due to lower natural gas costs passed through to customers and lower rates, partially offset by higher volumes.

Interest Expense. The increase was primarily due to higher outstanding debt balances and interest rates.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

Duke Energy relies primarily upon cash flows from operations, debt and equity issuances and its existing cash and cash equivalents to fund its liquidity and capital requirements. Duke Energy’s capital requirements arise primarily from capital and investment expenditures, repaying long-term debt and paying dividends to shareholders. Additionally, due to its existing tax attributes and projected tax credits to be generated relating to the IRA, Duke Energy does not expect to be a significant federal cash taxpayer until around 2030. Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2023, included a summary and detailed discussion of projected primary sources and uses of cash for 2024 to 2026.

In 2024, Duke Energy executed several equity forward sales agreements as part of the ATM program. Settlement of the forward sales agreements is expected to occur by December 31, 2024. See Note 15 to the Condensed Consolidated Financial Statements, “Stockholders’ Equity” for further details. Also in 2024, Duke Energy Carolinas and Duke Energy Progress began recording nuclear PTC deferred tax assets related to the IRA and began monetizing the PTCs in the transferability markets established by the IRA beginning in October 2024. Duke Energy Carolinas and Duke Energy Progress will work with the state utility commissions on the appropriate regulatory process to pass the net realizable value back to customers over time. See Note 17 to the Condensed Consolidated Financial Statements, “Income Taxes,” for further information.

As of September 30, 2024, Duke Energy had $376 million of cash on hand and $5.4 billion available under its $9 billion Master Credit Facility. Duke Energy expects to have sufficient liquidity in the form of cash on hand, cash from operations and available credit capacity to support its funding needs.

During the second quarter of 2024, Moody’s Investors Service, Inc. (Moody's) maintained the credit ratings and affirmed the ratings outlook for all of the Duke Energy Registrants, including Duke Energy Ohio. Operations in Kentucky are conducted through Duke Energy Ohio's wholly owned subsidiary, Duke Energy Kentucky. Moody's revised Duke Energy Kentucky's ratings outlook to stable, citing the expectation that a credit supportive outcome in the utility's most recent electric rate case will support credit metrics appropriate for its Baa1 rating.


MD&A			LIQUIDITY AND CAPITAL RESOURCES

As discussed in Note 13 to the Condensed Consolidated Financial Statements, "Variable Interest Entities," Duke Energy terminated and repaid CRC in March 2024 and Duke Energy Florida terminated and repaid DEFR in April 2024. As a result of these repayments, CRC and DEFR have ceased operations and no longer acquire the receivables of Duke Energy’s subsidiaries. Duke Energy Carolinas and Duke Energy Progress continue to evaluate financing opportunities and anticipate termination and repayment of the borrowing facilities of DERF and DEPR prior to their scheduled termination dates in January 2025 and April 2025, respectively.

Beginning in the third quarter of 2024, a series of major storm events occurred that resulted in significant damage to utility infrastructure within our service territories and primarily impacted Duke Energy Carolinas', Duke Energy Progress' and Duke Energy Florida's electric utility operations. As discussed in Note 4, to the Condensed Consolidated Financial Statements, "Regulatory Matters," hurricanes Debby, Helene and Milton caused widespread outages and included unprecedented damage to certain assets, including the hardest-hit areas on the western coast of Florida and certain regions in western North Carolina and upstate South Carolina. Funding restoration activities and, in some cases, the complete rebuild of critical infrastructure, for a series of sequential events of this magnitude has resulted in incremental financing needs until cost recovery occurs. See "Matters Impacting Future Results" for further details and Note 6 to the Condensed Consolidated Financial Statements, "Debt and Credit Facilities," for information regarding Duke Energy's debt issuances and maturities, available credit facilities including the Master Credit Facility, and term loans executed in response to these major storm events.

See Note 2 to the Condensed Consolidated Financial Statements, "Dispositions," for the timing and use of proceeds from the sale of certain Commercial Renewables assets to affiliates of Brookfield.

Cash Flow Information

The following table summarizes Duke Energy’s cash flows.


	Nine Months Ended
	September 30,
(in millions)	2024		2023
Cash flows provided by (used in):
Operating activities	$	8,951	$	7,309
Investing activities	(9,851)		(9,751)
Financing activities	990		2,413

Net increase (decrease) in cash, cash equivalents and restricted cash	90		(29)
Cash, cash equivalents and restricted cash at beginning of period	357		603
Cash, cash equivalents and restricted cash at end of period	$	447	$	574

OPERATING CASH FLOWS

The following table summarizes key components of Duke Energy’s operating cash flows.


	Nine Months Ended
	September 30,
(in millions)	2024		2023		Variance
Net income	$	3,387	$	1,878	$	1,509
Non-cash adjustments to net income	4,943		5,887		(944)
Contributions to qualified pension plans	(100)		(100)		—
Payments for asset retirement obligations	(417)		(423)		6
Working capital	763		(792)		1,555
Other assets and Other liabilities	375		859		(484)
Net cash provided by operating activities	$	8,951	$	7,309	$	1,642

The variance is primarily driven by:

a $1,071 million decrease in net working capital and other assets and liabilities amounts, primarily due to the recovery of deferred fuel costs and the timing of accruals and payments; and
a $565 million increase in net income, after adjustment for non-cash items, primarily due to growth from rate increases and riders, higher sales volumes and favorable weather, partially offset by higher interest expense and a higher effective tax rate.


MD&A			LIQUIDITY AND CAPITAL RESOURCES

INVESTING CASH FLOWS

The following table summarizes key components of Duke Energy’s investing cash flows.


	Nine Months Ended
	September 30,
(in millions)	2024		2023		Variance
Capital, investment and acquisition expenditures	$	(9,199)	$	(9,340)	$	141

Other investing items	(652)		(411)		(241)
Net cash used in investing activities	$	(9,851)	$	(9,751)	$	(100)

The variance is primarily due to higher costs of removal in the current year and net proceeds received in the prior year related to the sale of certain assets, partially offset by lower capital expenditures in the current year due to the prior year sale of the Commercial Renewables business.

FINANCING CASH FLOWS

The following table summarizes key components of Duke Energy’s financing cash flows.


	Nine Months Ended
	September 30,
(in millions)	2024		2023		Variance
Issuances of long-term debt, net	$	4,927	$	5,607	$	(680)


Redemption of preferred stock	(1,000)		—		(1,000)
Notes payable, commercial paper and other short-term borrowings	(515)		(939)		424
Dividends paid	(2,411)		(2,438)		27
Contributions from noncontrolling interests	47		278		(231)

Other financing items	(58)		(95)		37
Net cash provided by financing activities	$	990	$	2,413	$	(1,423)

The variance is primarily due to:

a $1 billion decrease due to the redemption of Series B preferred stock in the current year;
a $680 million decrease in proceeds from net issuances of long-term debt, primarily due to timing of issuances and redemptions of long-term debt; and
a $231 million decrease in contributions from noncontrolling interests, primarily due to the prior year sale of the Commercial Renewables business.

Partially offset by:

a $424 million increase in net borrowings from notes payable and commercial paper.

OTHER MATTERS

Environmental Regulations

The Duke Energy Registrants are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal, coal ash and other environmental matters. These regulations can be changed from time to time and result in new obligations of the Duke Energy Registrants. Refer to Note 4, "Regulatory Matters," in Duke Energy's Annual Report on Form 10-K for the year ended December 31, 2023, for more information regarding potential plant retirements and Note 4, "Regulatory Matters," to the Condensed Consolidated Financial Statements, for further information regarding regulatory filings related to the Duke Energy Registrants.

In April 2024, the EPA issued the 2024 CCR Rule under the Resource Conservation and Recovery Act, which significantly expands the scope of the 2015 CCR Rule by establishing regulatory requirements for inactive surface impoundments at retired generating facilities (Legacy CCR Surface Impoundments). The final rule also imposes a subset of the 2015 CCR Rule’s requirements, including groundwater monitoring, corrective action (where necessary), and in certain cases, closure, and post-closure care requirements, on previously unregulated coal ash sources at regulated facilities (CCR Management Units). CCR Management Units may include surface impoundments and landfills that closed prior to the effective date of the 2015 CCR Rule, inactive CCR landfills, and other areas where CCR is managed directly on the land at Duke Energy facilities. Duke Energy, as part of a group of similarly affected electric utilities, filed a petition to challenge the 2024 CCR Rule in the U.S. Court of Appeals for the District of Columbia Circuit on August 6, 2024. For more information, see Note 7 to the Condensed Consolidated Financial Statements, "Asset Retirement Obligations."


MD&A			OTHER MATTERS

In April 2024, the EPA issued a final rule under section 111 of the Clean Air Act (EPA Rule 111) regulating GHG emissions from existing coal-fired and new natural gas-fired power plants, referred to as electric generating units (EGUs). EPA Rule 111 requires existing coal-fired power plants expected to operate in 2039 and beyond to reduce GHG emissions by 90% through the use of carbon capture and sequestration starting in 2032, subject to certain modifications for coal plants that retire sooner and co-fire natural gas. EPA Rule 111 also establishes GHG emissions reduction standards for new natural gas-fired EGUs, subject to carve-outs for smaller peaking units that fill gaps that cannot be met with renewables or storage. The EPA did not finalize emission guidelines for GHG emissions from existing fossil fuel-fired stationary combustion turbines and intends to address these in a future rulemaking. Duke Energy is analyzing the potential impacts the rule could have on the Company, which could be material and may influence the timing, nature, and magnitude of future generation investments in our service territories. Duke Energy is participating in legal challenges to EPA Rule 111 as a member of Electric Generators for a Sensible Transition, a coalition of similarly affected utilities, and as a member of a utility trade group. The litigation is currently pending in the United States Court of Appeals for the D.C. Circuit.

Generation Mix Planning Process

In August 2023, Duke Energy Carolinas and Duke Energy Progress filed their 2023 systemwide Carolinas Resource Plan (the Plan) with the NCUC and PSCSC. The Plan provided a range of generation options, including three core portfolios, reflecting an “all of the above” approach to powering the energy needs of our growing region. In the Plan, Duke Energy Carolinas and Duke Energy Progress recommended Portfolio 3 as the most prudent path forward to comply with applicable state laws, providing a reliable and orderly energy transition that was proposed as the most reasonable, executable, and lowest-cost plan for the Carolinas. Portfolio 3 proposes a diverse and reliable set of generation and energy storage solutions and shrinks the challenges of growth and the transition from coal by expanding industry-leading energy efficiency and demand response options, laying out a path to reliably exit coal by 2035. Portfolio 3 also makes the most of existing system resources by extending the lives of Duke Energy’s nuclear plants and extending the license and doubling the peak hourly capacity of the Bad Creek pumped-hydro storage facility. Near-term actions consistent with Portfolio 3 were also proposed that will be executed between now and the end of 2026 to advance the orderly energy transition.

In November 2023, Duke Energy Carolinas and Duke Energy Progress provided notice to the NCUC and PSCSC of a substantially increased load forecast resulting from increased economic development in the Carolinas occurring since the systemwide Plan was prepared. The companies filed supplemental modeling and analysis with the NCUC and PSCSC in January 2024, demonstrating the need for additional resources beyond the set of resources identified by the companies in their initial plan.

In July 2024, Duke Energy Carolinas and Duke Energy Progress reached a broad settlement with the Public Staff of the NCUC, Walmart, and the Carolinas Clean Energy Business Association on the Plan, agreeing it is reasonable to use Portfolio 3 as the reference portfolio for planning purposes. Among other things, the settlement confirms a set of near-term activities, including development and procurement activities for solar, battery storage, onshore wind, and certain natural gas generation assets, as well as certain limited actions exploring initial development activities related to advanced nuclear, offshore wind, and to advance the potential for 1,834 MW of pumped storage hydro at the Bad Creek II facility by 2034. The NCUC conducted evidentiary hearings in July and August 2024 and issued an order accepting the settlement and providing further direction in November 2024. The order continues to emphasize the critical importance of reliability and maintaining affordability, while taking balanced actions to meet forecasted load growth.

The PSCSC held its hearings in September 2024 and in November 2024 voted to approve the Plan and directed Duke Energy Carolinas and Duke Energy Progress to work with the South Carolina Office of Regulatory Staff to provide alternative modeling around EPA Rule 111 compliance in a subsequent Carolinas Resource Plan filing.

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