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. Duke Energy 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. When discussing Duke Energy’s consolidated financial information, it necessarily 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, 2021, and with Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2020.

Executive Overview

Advancing Our Clean Energy Transformation

During the third quarter, we continued to execute on our clean energy transformation, delivering strong, sustainable value for shareholders, customers, communities and employees.

• In October 2021, North Carolina House Bill 951 was signed into law after legislative leaders announced bipartisan support for new state policy that would accelerate a clean energy transition for generation serving customers in the Carolinas, including providing a framework for a goal of 70% carbon reduction in electric generation from 2005 levels by 2030 and carbon neutrality by 2050 while continuing to prioritize affordability and reliability for our customers, who are located in both North and South Carolina. The legislation establishes a framework overseen by the NCUC to advance state CO2 emission reductions through the use of least cost planning, including stakeholder involvement, and also introduces modernized recovery mechanisms, including multi-year rate plans, that promote more efficient recovery of investments and align incentives between the company and the state’s energy policy objectives. The goals for a clean energy transition are generally consistent with Duke Energy Carolinas' and Duke Energy Progress' resource planning filings with the PSCSC.

• Also in October 2021, the Southeast Energy Exchange Market (SEEM) received clearance from the FERC. The new SEEM platform will facilitate sub-hourly, bilateral trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. Southeastern electricity customers are expected to see cost, reliability and environmental benefits.

• In a significant move to support the company’s path to net-zero strategy, in September 2021 we completed the first phase of the investment of a 19.9% minority interest in Duke Energy Indiana by an affiliate of GIC, transferring 11.05% interest in exchange for approximately $1.025 billion. The proceeds from the $2.05 billion investment are expected to address common equity needs through 2025 to partially fund the company’s $59 billion capital and investment expenditure plan. This plan includes grid improvement, investments in clean energy and an improved customer experience – keys to our strategy to reduce carbon emissions from electricity generation to net-zero by 2050.

• In September 2021, we announced Ledyard Windpower, a 207-MW project and our first wind farm in Iowa. Once in operation next year, this project will increase the company’s U.S. wind capacity to over 3,100 MW.

• In August 2021, we announced a partnership with Accenture and Microsoft to develop a novel technology platform with the intent of measuring baseline methane emissions from natural gas distribution systems with a high level of accuracy in near real time. Once deployed, we expect the use of satellite technology and the new platform will increase the speed of a field response team’s ability to identify and repair methane leaks along distribution lines and systems.

Regulatory Activity. During the third quarter of 2021, we continued to move our regulatory strategy forward. See Note 3 to the Condensed Consolidated Financial Statements, "Regulatory Matters," for additional information.

• In October 2021, Duke Energy Ohio filed a request to review the company’s electric distribution rates, seeking approval to increase current electric distribution rates by approximately $55 million. Duke Energy Ohio has invested more than $800 million in a variety of capital projects across southwest Ohio since it last requested a regulatory review of its electric distribution rates in 2017. Also, in October 2021, Duke Energy Kentucky reached a constructive natural gas rate case settlement with the Attorney General, subject to review and approval of the KPSC.

• In September 2021, Piedmont Natural Gas, the Public Staff of the NCUC, the Carolina Utility Customers Association, Inc., and the Carolina Industrial Group for Fair Utility Rates IV, filed a stipulation resolving all issues between these parties related to Piedmont’s rate case filed in March 2021. This constructive outcome provided for a return on equity of 9.60% and 51.60% equity component of the capital structure resulting in an overall rate of return of 6.90%, with an increase in pretax income (base rates) of approximately $67 million. The Stipulation is subject to the review and approval of the NCUC.

• We received approximately $418 million of coal ash insurance litigation proceeds from our settlements with insurer-defendants. Proceeds will be distributed in accordance with the terms of the CCR settlement agreement.

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.

MD&A			MATTERS IMPACTING FUTURE RESULTS

Regulatory Matters

Coal Ash Costs

As a result of the NCDEQ settlement on December 31, 2019, Duke Energy Carolinas and Duke Energy Progress agreed to excavate seven of the nine remaining coal ash basins in North Carolina with ash moved to on-site lined landfills. At the two remaining basins, uncapped basin ash will be excavated and moved to off-site lined landfills. The majority of spend is expected to occur over the next 15-20 years. In January 2021, Duke Energy Carolinas and Duke Energy Progress reached a settlement agreement on recovery of coal ash costs as outlined in Note 3, "Regulatory Matters." The company agreed not to seek recovery of approximately $1 billion of deferred coal ash expenditures and Duke Energy Carolinas and Duke Energy Progress took a charge of approximately $500 million each in 2020. On March 31, 2021, and April 16, 2021, the NCUC approved the coal ash settlement for Duke Energy Carolinas and Duke Energy Progress, respectively.

Duke Energy Indiana has interpreted the CCR rule to identify the coal ash basin sites impacted and has assessed the amounts of coal ash subject to the rule and a method of compliance. In 2020, the Hoosier Environmental Council filed a petition challenging the Indiana Department of Environmental Management's (IDEM) partial approval of five of Duke Energy Indiana’s ash pond site closure plans at Gallagher Station. The petition does not challenge the other 13 basin closures approved by IDEM at other Indiana stations. Interpretation of the requirements of the CCR rule is subject to further legal challenges and regulatory approvals, which could result in additional ash basin closure requirements, higher costs of compliance and greater AROs. Additionally, Duke Energy Indiana has retired facilities that are not subject to the CCR rule. Duke Energy Indiana may incur costs at these facilities to comply with environmental regulations or to mitigate risks associated with on-site storage of coal ash.

MGP

Duke Energy Ohio and other parties have filed with the PUCO a Stipulation and Recommendation that would resolve all open issues regarding manufactured gas plant remediation costs incurred between 2013 and 2019, including Duke Energy Ohio's request for additional deferral authority beyond 2019, and the pending issues related to the Tax Act as it relates to Duke Energy Ohio's natural gas operations. These impacts, if approved by the PUCO, are not expected to have a material impact on Duke Energy Ohio's financial statements. Failure to approve the Stipulation and Recommendation, disallowance of costs incurred, failure to complete the work by the deadline or failure to obtain an extension from the PUCO could result in an adverse impact.

For additional information, see Notes 3 and 4 to the Condensed Consolidated Financial Statements, “Regulatory Matters” and "Commitments and Contingencies," respectively.

Commercial Renewables

Duke Energy continues to monitor recoverability of renewable merchant plants located in the Electric Reliability Council of Texas West market and in the PJM West market, due to fluctuating market pricing and long-term forecasted energy prices. Based on the most recent recoverability test, the carrying value approximated the aggregate estimated future undiscounted cash flows for the assets under review. A continued decline in energy market pricing or other factors unfavorably impacting the economics would likely result in a future impairment. Impairment of these assets could result in adverse impacts. For additional information, see Note 2 to the Condensed Consolidated Financial Statements, "Business Segments."

In February 2021, a severe winter storm impacted certain Commercial Renewables assets in Texas. Extreme weather conditions limited the ability for these solar and wind facilities to generate and sell electricity into the Electric Reliability Council of Texas market. Lost revenues and higher than expected purchased power costs have negatively impacted the operating results of these generating units. The financial impact of the storm is expected to be material to the Commercial Renewables segment's 2021 operating results. In addition, Duke Energy has been named in multiple lawsuits arising out of this winter storm. For more information, see Notes 2 and 4 to the Condensed Consolidated Financial Statements, "Business Segments" and "Commitments and Contingencies," respectively.

COVID-19

Duke Energy continues to monitor the impacts of the COVID-19 pandemic on its results of operations, financial position and cash flows as a result of the economic slowdown caused by reduced operations of businesses and governmental agencies and the corresponding reduction in the demand for energy. Duke Energy has experienced improvement in energy sales, aging of receivables and operating results in recent periods and continues efforts to partially offset these impacts. Additionally, in light of learnings from COVID-19 regarding workforce deployment and technology capabilities, the company has reviewed the long-term real estate and future workforce strategy. The review has resulted in an initiative that will reduce physical workspace and includes reassessments of lease terms and lease modifications, termination penalties, as well as, asset impairments on property, plant and equipment and a change in workforce roles and responsibilities. For more information, see Notes 1 and 3 to the Condensed Consolidated Financial Statements, "Organization and Basis of Presentation" and "Regulatory Matters," respectively.

Activist Investor

On May 17, 2021, Elliott, who has indicated it holds an economic interest in outstanding Duke Energy common stock, publicly released a letter it had sent to the Board, which advocated for consideration of certain governance and strategic proposals. On May 17, 2021, management issued a response to Elliott. On July 19, 2021, Elliott publicly released a second letter to the Board and Duke Energy issued a response. Duke Energy is unable to predict the outcome of this matter.

Other Matters

See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," in the Duke Energy Registrants' Annual Reports on Form 10-K for the year ended December 31, 2020, for discussion of risks associated with the Tax Act.

MD&A			DUKE ENERGY

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 such as adjusted earnings and adjusted EPS discussed below. Generally, a non-GAAP financial measure is a numerical measure 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 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 Earnings (Loss) Per Share, respectively.

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

• Workplace and workforce realignment represents costs attributable to business transformation, including long-term real estate strategy changes and workforce realignment.

• Regulatory Settlements represents an impairment charge related to the 2018 South Carolina rate cases, charges related to the CCR settlement and insurance proceeds distributed in accordance with that agreement and Duke Energy Carolinas and Duke Energy Progress partial settlements in the 2019 North Carolina rate cases.

• Gas Pipeline Investments represents costs related to the cancellation of the ACP pipeline and additional exit obligations.

• Severance represents the reversal of 2018 severance charges, which were deferred as a result of partial settlements in the Duke Energy Carolinas and the Duke Energy Progress 2019 North Carolina rate cases.

Three Months Ended September 30, 2021, as compared to September 30, 2020

GAAP reported EPS was $1.79 for the third quarter of 2021 compared to a $1.74 in the third quarter of 2020. In addition to the drivers below, GAAP reported EPS increased due to the cancellation of the ACP pipeline in the prior year and partial settlements in the 2019 North Carolina rate cases in the prior year. This was partially offset by an impairment charge related to the 2018 South Carolina rate cases and charges related to the CCR settlement and insurance proceeds distributed in accordance with that agreement.

As discussed above, management also evaluates financial performance based on adjusted EPS. Duke Energy’s third quarter 2021 adjusted EPS was $1.88 compared to $1.87 for the third quarter of 2020. The increase in adjusted EPS was primarily due to positive rate case contributions and higher volumes. This was partially offset by higher operation and maintenance expenses, higher income tax expense and share dilution from equity issuances.

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

			Three Months Ended September 30,
			2021												2020
(in millions, except per share amounts)			Earnings						EPS						Earnings						EPS
GAAP Reported Earnings/GAAP Reported EPS			$	1,366					$	1.79					$	1,265					$	1.74
Adjustments:
Workplace and Workforce Realignment(a)			7						—						—						—
Regulatory Settlements(b)			64						0.09						27						0.04
Gas Pipeline Investments(c)			(2)						—						69						0.09
Adjusted Earnings/Adjusted EPS			$	1,435					$	1.88					$	1,361					$	1.87

(a)Net of tax benefit of $2 million.

(b)Net of tax benefit of $19 million and $8 million for the three months ended September 30, 2021, and 2020, respectively.

(c)Net of tax expense of $1 million and tax benefit of $21 million for the three months ended September 30, 2021, and 2020, respectively.

Nine Months Ended September 30, 2021, as compared to September 30, 2020

GAAP Reported EPS was $4.00 for the nine months ended September 30, 2021, compared to $1.85 for the nine months ended September 30, 2020. In addition to the drivers below, GAAP reported EPS increased due to the cancellation of the ACP pipeline in the prior year, partially offset by workplace and workforce realignment costs.

As discussed above, management also evaluates financial performance based on adjusted EPS. Duke Energy’s adjusted EPS was $4.30 for the nine months ended September 30, 2021, compared to $4.09 for the nine months ended September 30, 2020. The increase in adjusted EPS was primarily due to positive rate case contributions and higher volumes, partially offset by higher income tax expense and share dilution from equity issuances.

MD&A			DUKE ENERGY

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

			Nine Months Ended September 30,
			2021												2020
(in millions, except per share amounts)			Earnings						EPS						Earnings						EPS
GAAP Reported Earnings/GAAP Reported EPS			$	3,070					$	4.00					$	1,347					$	1.85
Adjustments:
Workplace and Workforce Realignment(a)			142						0.19						—						—
Regulatory Settlements(b)			64						0.09						27						0.04
Gas Pipeline Investments(c)			15						0.02						1,695						2.30
Severance(d)			—						—						(75)						(0.10)
Adjusted Earnings/Adjusted EPS			$	3,291					$	4.30					$	2,994					$	4.09

(a)Net of tax benefit of $42 million.

(b)Net of tax benefit of $19 million and $8 million for the nine months ended September 30, 2021, and 2020, respectively.

(c)Net of tax benefit of $4 million and $395 million for the nine months ended September 30, 2021, and 2020, respectively.

(d)Net of tax expense of $23 million.

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: Electric Utilities and Infrastructure, Gas Utilities and Infrastructure and Commercial Renewables. The remainder of Duke Energy’s operations is presented as Other. See Note 2 to the Condensed Consolidated Financial Statements, “Business Segments,” for additional information on Duke Energy’s segment structure.

Electric Utilities and Infrastructure

			Three Months Ended September 30,																		Nine Months Ended September 30,
(in millions)			2021						2020						Variance						2021						2020						Variance
Operating Revenues			$	6,569					$	6,379					$	190					$	17,185					$	16,596					$	589
Operating Expenses
Fuel used in electric generation and purchased power			1,864						1,869						(5)						4,760						4,703						57
Operation, maintenance and other			1,363						1,326						37						3,907						3,891						16
Depreciation and amortization			1,084						1,053						31						3,154						3,023						131
Property and other taxes			330						286						44						949						885						64
Impairment of assets and other charges			202						20						182						203						23						180
Total operating expenses			4,843						4,554						289						12,973						12,525						448
Gains on Sales of Other Assets and Other, net			9						3						6						11						11						—
Operating Income			1,735						1,828						(93)						4,223						4,082						141
Other Income and Expenses, net			220						67						153						421						241						180
Interest Expense			365						308						57						1,066						991						75
Income Before Income Taxes			1,590						1,587						3						3,578						3,332						246
Income Tax Expense			160						206						(46)						393						493						(100)
Less: Income Attributable to Noncontrolling Interest			5						—						5						5						—						5
Segment Income			$	1,425					$	1,381					$	44					$	3,180					$	2,839					$	341
Duke Energy Carolinas GWh sales			25,033						23,726						1,307						67,357						64,045						3,312
Duke Energy Progress GWh sales			19,219						19,035						184						51,555						49,512						2,043
Duke Energy Florida GWh sales			12,983						12,973						10						32,731						32,390						341
Duke Energy Ohio GWh sales			6,844						6,678						166						18,586						17,763						823
Duke Energy Indiana GWh sales			8,788						8,463						325						23,880						22,842						1,038
Total Electric Utilities and Infrastructure GWh sales			72,867						70,875						1,992						194,109						186,552						7,557
Net proportional MW capacity in operation																					49,749						50,371						(622)

MD&A			SEGMENT RESULTS — ELECTRIC UTILITIES AND INFRASTRUCTURE

Three Months Ended September 30, 2021, as compared to September 30, 2020

Electric Utilities and Infrastructure’s higher segment income is due to higher revenues from rate cases in various jurisdictions, weather-normal sales volumes, and coal ash insurance litigation proceeds partially offset by an impairment charge related to the South Carolina rate cases and higher operating expenses. The following is a detailed discussion of the variance drivers by line item.

Operating Revenues. The variance was driven primarily by:

• a $144 million increase in retail base rate pricing due to general rate cases in North Carolina and Indiana net of rider impacts as well as multiyear rate adjustments in Florida; and

• a $114 million increase in weather-normal retail sales volumes.

Partially offset by

• a $48 million decrease in storm revenues at Duke Energy Florida due to full recovery of Hurricane Dorian costs in the prior year; and

• a $17 million decrease in retail sales due to less favorable weather in the current year.

Operating Expenses. The variance was driven primarily by:

• a $182 million increase in impairment of assets and other charges primarily due to the 2018 South Carolina rate case settlements at Duke Energy Carolinas and Duke Energy Progress, partially offset by a prior year impairment of Duke Energy Carolina's Clemson assets;

• a $44 million increase in property and other taxes primarily due to higher property taxes at Duke Energy Carolinas and Duke Energy Ohio and a prior year sales and use tax refund at Duke Energy Carolinas;

• a $37 million increase in operation, maintenance and other primarily driven by higher employee-related costs, partially offset by lower storm and outage costs; and

• a $31 million increase in depreciation and amortization primarily due to resolution of rate cases and higher plant in service, partially offset by lower depreciation related to the extension of the lives of nuclear facilities.

Other Income and Expense, net. The increase is primarily due to coal ash insurance litigation proceeds at Duke Energy Carolinas and Duke Energy Progress and lower non-service pension costs.

Interest Expense. The variance was primarily due to lower debt return on coal ash at Duke Energy Carolinas, Duke Energy Progress and Duke Energy Indiana.

Income Tax Expense. The decrease in tax expense was primarily due to an increase in the amortization of excess deferred taxes. The ETRs for the three months ended September 30, 2021, and 2020, were 10.1% and 13.0%, respectively. The decrease in the ETR was primarily due to an increase in the amortization of excess deferred taxes.

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Electric Utilities and Infrastructure’s variance is due to higher revenues from rate cases in various jurisdictions, higher retail sales volumes, and coal ash insurance litigation proceeds, partially offset by an impairment charge related to the South Carolina rate cases, higher depreciation and amortization and interest expense. The following is a detailed discussion of the variance drivers by line item.

Operating Revenues. The variance was driven primarily by:

• a $297 million increase in retail base rate pricing due to general rate cases in Indiana and North Carolina net of rider impacts as well as multiyear settlement rate adjustments in Florida;

• a $188 million increase in weather-normal retail sales volumes;

• an $86 million increase in retail sales, net of fuel revenues, due to favorable weather;

• a $61 million increase in fuel revenues primarily driven by higher sales volumes; and

• a $21 million increase in wholesale revenues primarily due to higher rates at Duke Energy Indiana and higher volumes at Duke Energy Progress, partially offset by a restructured capacity contract at Duke Energy Florida.

Partially offset by:

• a $103 million decrease in storm revenues due to full recovery of Hurricane Dorian costs in the prior year.

MD&A			SEGMENT RESULTS — ELECTRIC UTILITIES AND INFRASTRUCTURE

Operating Expenses. The variance was driven primarily by:

• a $180 million increase in impairment of assets and other charges primarily due to the 2018 South Carolina rate case settlements at Duke Energy Carolinas and Duke Energy Progress, partially offset by a prior year impairment of Duke Energy Carolinas' Clemson assets;

• a $131 million increase in depreciation and amortization primarily due to resolution of rate cases and higher plant in service, partially offset by lower depreciation related to the extension of the lives of nuclear facilities;

• a $64 million increase in property and other taxes primarily due to higher property taxes at Duke Energy Carolinas and Duke Energy Ohio, and a prior year sales and use tax refund at Duke Energy Carolinas;

• a $57 million increase in fuel used in electric generation and purchased power primarily due to higher sales volumes; and

• a $16 million increase in operations, maintenance and other driven by higher employee-related expenses, partially offset by decreased storm amortization at Duke Energy Florida and lower COVID-19 costs.

Other Income and Expenses, net. The increase is primarily due to coal ash insurance litigation proceeds at Duke Energy Carolinas and Duke Energy Progress and lower non-service pension costs.

Interest Expense. The variance was primarily due to lower debt return on coal ash at Duke Energy Carolinas, Duke Energy Progress and Duke Energy Indiana.

Income Tax Expense. The decrease in tax expense was primarily due to an increase in the amortization of excess deferred taxes, partially offset by an increase in pretax income. The ETRs for the nine months ended September 30, 2021, and 2020, were 11.0% and 14.8%, respectively. The decrease in the ETR was primarily due to an increase in the amortization of excess deferred taxes.

Gas Utilities and Infrastructure

			Three Months Ended September 30,																		Nine Months Ended September 30,
(in millions)			2021						2020						Variance						2021						2020						Variance
Operating Revenues			$	289					$	241					$	48					$	1,391					$	1,194					$	197
Operating Expenses
Cost of natural gas			75						41						34						430						300						130
Operation, maintenance and other			102						103						(1)						302						312						(10)
Depreciation and amortization			74						65						9						216						193						23
Property and other taxes			30						26						4						92						82						10
Impairment of assets and other charges			—						7						(7)						—						7						(7)
Total operating expenses			281						242						39						1,040						894						146
Operating Income (Loss)			8						(1)						9						351						300						51
Other Income and Expenses
Equity in earnings (losses) of unconsolidated affiliates			10						(71)						81						2						(2,004)						2,006
Other income and expenses, net			15						16						(1)						50						42						8
Total other income and expenses			25						(55)						80						52						(1,962)						2,014
Interest Expense			37						35						2						105						103						2
(Loss) Income Before Income Taxes			(4)						(91)						87						298						(1,765)						2,063
Income Tax (Benefit) Expense			(1)						(18)						17						39						(365)						404
Segment (Loss) Income			$	(3)					$	(73)					$	70					$	259					$	(1,400)					$	1,659
Piedmont LDC throughput (dekatherms)			134,549,588						115,549,371						19,000,217						390,210,785						360,861,306						29,349,479
Duke Energy Midwest LDC throughput (Mcf)			10,268,918						9,678,342						590,576						62,220,827						58,570,583						3,650,244

Three Months Ended September 30, 2021, as compared to September 30, 2020

Gas Utilities and Infrastructure’s results were impacted primarily by the cancellation of the ACP pipeline in the prior year. The following is a detailed discussion of the variance drivers by line item.

Operating Revenues. The variance was driven primarily by:

• a $34 million increase due to higher natural gas costs passed through to customers, higher volumes, and higher off-system sales natural gas costs; and

• a $12 million increase due to growth in base rates and riders at Piedmont and growth in riders in the Midwest.

MD&A			SEGMENT RESULTS — GAS UTILITIES AND INFRASTRUCTURE

Operating Expenses. The variance was driven primarily by:

• a $34 million increase in cost of natural gas due to higher natural gas prices, higher volumes, and increased off-system sales natural gas costs; and

• a $9 million increase in depreciation due to additional plant in service.

Equity in earnings (losses) of unconsolidated affiliates. The variance was primarily driven by the cancellation of the ACP pipeline in the prior year.

Income Tax Benefit. The decrease in tax benefit was primarily due to a decrease in pretax losses. The ETRs for the three months ended September 30, 2021, and 2020, were 25.0% and 19.8%, respectively. The increase in the ETR was primarily due to certain favorable tax credits.

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Gas Utilities and Infrastructure’s results were impacted primarily by the cancellation of the ACP pipeline in the prior year and margin growth. The following is a detailed discussion of the variance drivers by line item.

Operating Revenues. The variance was driven primarily by:

• a $130 million increase due to higher natural gas costs passed through to customers, higher volumes, and increased off-system sales natural gas costs;

• a $15 million increase due to Tennessee base rate case increases;

• an $11 million increase due to North Carolina IMR; and

• a $10 million increase due to revenue from the Capital Expenditure Program (CEP) rider related to 2019 and 2020 activity.

Operating Expenses. The variance was driven primarily by:

• a $130 million increase in cost of natural gas due to higher natural gas prices, higher volumes, and increased off-system sales natural gas costs; and

• a $23 million increase in depreciation due to additional plant in service.

Equity in earnings (losses) of unconsolidated affiliates. The variance was driven primarily by the cancellation of the ACP pipeline in the prior year.

Income Tax Expense. The increase in tax expense was primarily due to the cancellation of the ACP pipeline project recorded in the prior year*.* The ETRs for the nine months ended September 30, 2021, and 2020, were 13.1% and 20.7%, respectively. The decrease in the ETR was primarily due to the cancellation of the ACP pipeline project recorded in the prior year.

Commercial Renewables

			Three Months Ended September 30,																		Nine Months Ended September 30,
(in millions)			2021						2020						Variance						2021						2020						Variance
Operating Revenues			$	117					$	126					$	(9)					$	355					$	378					$	(23)
Operating Expenses
Operation, maintenance and other			90						72						18						240						204						36
Depreciation and amortization			58						52						6						167						148						19
Property and other taxes			10						8						2						28						24						4
Impairment of assets and other charges			—						—						—						—						6						(6)
Total operating expenses			158						132						26						435						382						53
Operating Loss			(41)						(6)						(35)						(80)						(4)						(76)
Other Income and Expenses, net			(2)						(1)						(1)						(24)						—						(24)
Interest Expense			20						18						2						53						49						4
Loss Before Income Taxes			(63)						(25)						(38)						(157)						(53)						(104)
Income Tax Benefit			(6)						(15)						9						(56)						(52)						(4)
Add: Loss Attributable to Noncontrolling Interests			135						70						65						253						208						45
Segment Income			$	78					$	60					$	18					$	152					$	207					$	(55)
Renewable plant production, GWh			2,567						2,563						4						7,942						7,660						282
Net proportional MW capacity in operation(a)																					4,630						3,984						646

(a)Certain projects are included in tax equity structures where investors have differing interests in the project's economic attributes. One hundred percent of the tax equity project's capacity is included in the table above.

MD&A			SEGMENT RESULTS — COMMERCIAL RENEWABLES

Three Months Ended September 30, 2021, as compared to September 30, 2020

Commercial Renewables' results were favorable to prior year primarily driven by the growth of new project investments. Since the prior year period, Commercial Renewables has placed in service approximately 650 MW.

Operating Revenues. The variance was primarily driven by an $8 million decrease due to lower wind resource and operating downtime.

Operating Expenses. The variance was primarily driven by a $12 million increase in operating expenses, depreciation expense and property tax expense associated with the growth of new project investments placed in service, $8 million increase for higher engineering and construction costs within the distributed energy portfolio and $3 million increase attributed to maintenance at several facilities.

Income Tax Benefit. The decrease in the tax benefit was primarily driven by an increase in taxes associated with tax equity investments and a decrease in production tax credits generated partially offset by an increase in pretax losses.

Loss Attributable to Noncontrolling Interests. The increase was primarily driven by the growth of new wind and solar project investments financed with tax equity.

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Commercial Renewables' results were unfavorable to prior year primarily driven by the impacts from Texas Storm Uri, which resulted in a $35 million pretax loss, as well as unfavorable wind resource and fewer projects being placed in service in the current year.

Operating Revenues. The variance was primarily driven by a $20 million decrease due to lower wind resource and operating downtime and a $15 million decrease for lower market prices in the current year impacting the wind portfolio. This was partially offset by an $8 million increase for market sales in excess of market purchases during Texas Storm Uri and a $4 million increase due to growth of new projects.

Operating Expenses. The increase was primarily due to $33 million for higher operating expenses, depreciation expense and property tax expense as a result of the growth in new projects placed in service since prior year, $11 million increase for higher operating expenses attributed to maintenance at several wind and solar facilities, an $11 million increase for higher engineering and construction costs within the distributed energy portfolio and a $2 million increase associated with Texas Storm Uri. This was partially offset by a $6 million decrease related to an impairment charge in the prior year for a non-contracted wind project.

Other Income and Expenses, net. The variance was primarily driven by a $29 million loss in equity earnings due to the impacts of Texas Storm Uri, partially offset by $4 million in equity earnings from the wind and distributed asset portfolios.

Income Tax Benefit. The increase in the tax benefit was primarily driven by an increase in pretax losses partially offset by an increase in taxes associated with tax equity investments and a decrease in production tax credits generated.

Loss Attributable to Noncontrolling Interests. The variance was primarily driven by a $57 million net increase from the growth of new project investments financed with tax equity, partially offset by a $12 million loss resulting from Texas Storm Uri.

Other

			Three Months Ended September 30,																		Nine Months Ended September 30,
(in millions)			2021						2020						Variance						2021						2020						Variance
Operating Revenues			$	28					$	24					$	4					$	81					$	73					$	8
Operating Expenses			46						37						9						282						(15)						297
Losses on Sales of Other Assets and Other, net			(1)						—						(1)						(1)						—						(1)
Operating (Loss) Income			(19)						(13)						(6)						(202)						88						(290)
Other Income and Expenses, net			25						43						(18)						78						55						23
Interest Expense			163						160						3						470						498						(28)
Loss Before Income Taxes			(157)						(130)						(27)						(594)						(355)						(239)
Income Tax Benefit			(63)						(66)						3						(166)						(149)						(17)
Less: Income Attributable to Noncontrolling Interests			1						—						1						1						—						1
Less: Preferred Dividends			39						39						—						92						93						(1)
Net Loss			$	(134)					$	(103)					$	(31)					$	(521)					$	(299)					$	(222)

Three Months Ended September 30, 2021, as compared to September 30, 2020

The higher net loss was driven by interest income related to a tax refund recorded in the prior year, impairments to optimize the company’s real estate portfolio and reduce office space as parts of the business move to a hybrid and remote workforce strategy and a lower income tax benefit due to higher tax optimization achieved in the prior year partially offset by higher pretax loss.

Operating Expenses. The increase was primarily driven by asset impairments to optimize the company's real estate portfolio and reduce office space as parts of the business move to a hybrid and remote workforce strategy.

Other Income and Expenses, net. The variance was primarily due to higher interest income in the prior year related to a tax refund of AMT credit carryforwards.

Interest Expense. The variance was primarily due to higher outstanding long-term debt.

MD&A			SEGMENT RESULTS - OTHER

Nine Months Ended September 30, 2021, as compared to September 30, 2020

The higher net loss was driven by asset impairments to optimize the company's real estate portfolio and reduce office space as parts of the business move to a hybrid and remote workforce strategy as well as a reversal of severance costs in the prior year.

Operating Expenses. The increase was primarily due to asset impairments to optimize the company's real estate portfolio and reduce office space as parts of the business move to a hybrid and remote workforce strategy as well as a reversal of severance costs in the prior year.

Other Income and Expenses, net. The variance was primarily due to higher equity earnings from the NMC investment and market returns on investments that fund certain employee benefit obligations, partially offset by lower interest income in the prior year related to a tax refund of AMT credit carryforwards.

Interest Expense. The variance was primarily due to lower interest rates.

Income Tax Benefit. The increase in the tax benefit was primarily driven by an increase in pretax losses, partially offset by lower state tax expense in the prior year. The ETRs for the nine months ended September 30, 2021, and 2020, were 27.9% and 42.0%, respectively. The decrease in the ETR was primarily due to lower state tax expense in the prior year.

DUKE ENERGY CAROLINAS

Results of Operations

			Nine Months Ended September 30,
(in millions)			2021						2020						Variance
Operating Revenues			$	5,430					$	5,416					$	14
Operating Expenses
Fuel used in electric generation and purchased power			1,218						1,326						(108)
Operation, maintenance and other			1,347						1,218						129
Depreciation and amortization			1,088						1,090						(2)
Property and other taxes			248						213						35
Impairment of assets and other charges			238						22						216
Total operating expenses			4,139						3,869						270
Gains on Sales of Other Assets and Other, net			1						1						—
Operating Income			1,292						1,548						(256)
Other Income and Expenses, net			218						128						90
Interest Expense			400						370						30
Income Before Income Taxes			1,110						1,306						(196)
Income Tax Expense			40						178						(138)
Net Income			$	1,070					$	1,128					$	(58)

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			2021
Residential sales			4.9		%
General service sales			2.0		%
Industrial sales			5.8		%
Wholesale power sales			6.0		%
Joint dispatch sales			23.0		%
Total sales			5.2		%
Average number of customers			2.4		%

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Operating Revenues. The variance was driven primarily by:

• an $88 million increase in weather-normal retail sales volumes;

• a $57 million increase in retail sales due to more favorable weather; and

• a $22 million increase due to higher pricing from the North Carolina retail rate case, net of a return of EDIT to customers.

Partially offset by:

• a $115 million decrease in fuel revenues due to lower prices, partially offset by higher retail sales volumes; and

• a $40 million decrease in rider revenues primarily due to energy efficiency programs.

MD&A			DUKE ENERGY CAROLINAS

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

• a $216 million increase in impairment of assets and other charges due to the 2018 South Carolina rate case settlement and optimization of the company's real estate portfolio and reduction of office space as parts of the business move to a hybrid and remote workforce strategy, partially offset by a prior year Clemson University Combined Heat and Power Plant impairment;

• a $129 million increase in operation, maintenance and other expense primarily due to higher employee-related expenses and a severance cost adjustment in the prior year related to the 2019 North Carolina retail rate case, and higher costs associated with the implementation of Customer Connect; and

• a $35 million increase in property and other taxes primarily due to property tax valuation adjustments and a prior year sales and use tax refund.

Partially offset by:

• a $108 million decrease in fuel used in electric generation and purchased power primarily associated with the recovery of fuel expenses, partially offset by higher natural gas prices and changes in the generation mix.

Other Income and Expense, net. The variance was primarily due to coal ash insurance proceeds and lower non-service pension costs.

Interest Expense. The variance was driven by amortization of carrying costs related to excess deferred taxes, and lower debt return on coal ash projects.

Income Tax Expense. The decrease in tax expense was primarily due to an increase in the amortization of excess deferred taxes and a decrease in pretax income.

PROGRESS ENERGY

Results of Operations

			Nine Months Ended September 30,
(in millions)			2021						2020						Variance
Operating Revenues			$	8,417					$	8,117					$	300
Operating Expenses
Fuel used in electric generation and purchased power			2,702						2,628						74
Operation, maintenance and other			1,863						1,789						74
Depreciation and amortization			1,430						1,356						74
Property and other taxes			419						419						—
Impairment of assets and other charges			79						1						78
Total operating expenses			6,493						6,193						300
Gains on Sales of Other Assets and Other, net			9						9						—
Operating Income			1,933						1,933						—
Other Income and Expenses, net			167						89						78
Interest Expense			592						599						(7)
Income Before Income Taxes			1,508						1,423						85
Income Tax Expense			174						190						(16)
Net Income			1,334						1,233						101
Less: Net Income Attributable to Noncontrolling Interests			1						1						—
Net Income Attributable to Parent			$	1,333					$	1,232					$	101

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Operating Revenues. The variance was driven primarily by:

• a $146 million increase in fuel cost recovery driven by higher fuel prices, higher volumes in the current year and accelerated recovery of retired Crystal River coal units;

• a $136 million increase in retail pricing due to the North Carolina rate case and base rate adjustments at Duke Energy Florida related to annual increases from the 2017 Settlement Agreement and the solar base rate adjustment;

• a $73 million increase in weather-normal retail sales volumes;

• a $32 million increase in other revenues at Duke Energy Florida primarily due to higher transmission revenues and higher customer charges that were waived due to COVID-19 in the prior year; and

• a $19 million increase in rider revenues at Duke Energy Florida primarily due to increased retail sales volumes.

MD&A			PROGRESS ENERGY

Partially offset by:

• a $103 million decrease in storm revenues at Duke Energy Florida due to full recovery of Hurricane Dorian costs in the prior year.

Operating Expenses. The variance was driven primarily by:

• a $78 million increase in impairment of assets and other charges primarily due to the 2018 South Carolina rate case settlement at Duke Energy Progress and optimization of the company's real estate portfolio and reduction of office space as parts of the business move to a hybrid and remote workforce strategy;

• a $74 million increase in fuel used in electric generation and purchased power primarily due to higher demand, changes in generation mix and recognition of RECs used for compliance at Duke Energy Progress, and outside fuel purchases during a major plant outage;

• a $74 million increase in operation, maintenance and other expense driven by a prior year severance cost adjustment related to the 2019 North Carolina retail rate case, outage costs and other employee-related costs, partially offset by reduced storm amortization at Duke Energy Florida; and

• a $74 million increase in depreciation and amortization primarily due to accelerated depreciation of retired Crystal River coal units and an increase in plant base at Duke Energy Florida, partially offset by the extension of the lives at nuclear facilities at Duke Energy Progress.

Other Income and Expenses, net. The increase is primarily due to coal ash insurance litigation proceeds at Duke Energy Progress, lower non-service pension costs and unrealized gains on the nuclear decommissioning trust fund at Duke Energy Florida.

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

DUKE ENERGY PROGRESS

Results of Operations

			Nine Months Ended September 30,
(in millions)			2021						2020						Variance
Operating Revenues			$	4,417					$	4,207					$	210
Operating Expenses
Fuel used in electric generation and purchased power			1,368						1,337						31
Operation, maintenance and other			1,092						970						122
Depreciation and amortization			811						833						(22)
Property and other taxes			129						129						—
Impairment of assets and other charges			60						5						55
Total operating expenses			3,460						3,274						186
Gains on Sales of Other Assets and Other, net			8						8						—
Operating Income			965						941						24
Other Income and Expenses, net			111						52						59
Interest Expense			226						203						23
Income Before Income Taxes			850						790						60
Income Tax Expense			50						79						(29)
Net Income			$	800					$	711					$	89

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 period			2021
Residential sales			6.5		%
General service sales			3.9		%
Industrial sales			2.7		%
Wholesale power sales			5.2		%
Joint dispatch sales			(2.6)		%
Total sales			4.1		%
Average number of customers			0.4		%

MD&A			DUKE ENERGY PROGRESS

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Operating Revenues. The variance was driven primarily by:

• a $72 million increase due to higher pricing from the North Carolina retail rate case, net of a return of EDIT to customers;

• a $54 million increase in weather-normal retail sales volumes in the current year;

• a $46 million increase in retail sales due to more favorable weather;

• a $24 million increase in fuel cost recovery driven by higher fuel prices and volumes in the current year; and

• a $15 million increase in wholesale revenues due to higher capacity volumes, partially offset by lower recovery of coal ash costs.

Operating Expenses. The variance was driven primarily by:

• a $122 million increase in operation, maintenance and other expense primarily due to higher employee-related costs and a severance cost adjustment in the prior year related to the 2019 North Carolina retail rate case, increased outage costs and energy efficiency program costs;

• a $55 million increase in impairment of assets and other charges primarily due to the 2018 South Carolina rate case settlement at Duke Energy Progress and optimization of the company's real estate portfolio and reduction of office space as parts of the business move to a hybrid and remote workforce strategy; and

• a $31 million increase in fuel used in electric generation and purchased power primarily due to higher demand and changes in generation mix as well as recognition of RECs used for compliance.

Partially offset by:

• a $22 million decrease in depreciation and amortization expense, primarily driven by the extension of the lives of nuclear facilities.

Other Income and Expense, net. The increase is primarily due to coal ash insurance litigation proceeds and lower non-service pension costs.

Interest Expense. The variance was driven primarily by lower debt return on coal ash projects.

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

DUKE ENERGY FLORIDA

Results of Operations

			Nine Months Ended September 30,
(in millions)			2021						2020						Variance
Operating Revenues			$	3,987					$	3,897					$	90
Operating Expenses
Fuel used in electric generation and purchased power			1,335						1,291						44
Operation, maintenance and other			760						806						(46)
Depreciation and amortization			619						523						96
Property and other taxes			290						290						—
Impairment of assets and other charges			19						(4)						23
Total operating expenses			3,023						2,906						117
Gains on Sales of Other Assets and Other, net			1						—						1
Operating Income			965						991						(26)
Other Income and Expenses, net			54						36						18
Interest Expense			239						245						(6)
Income Before Income Taxes			780						782						(2)
Income Tax Expense			149						159						(10)
Net Income			$	631					$	623					$	8

MD&A			DUKE ENERGY FLORIDA

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			2021
Residential sales			(0.5)		%
General service sales			3.1		%
Industrial sales			8.1		%
Wholesale and other			20.1		%
Total sales			1.1		%
Average number of customers			1.9		%

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Operating Revenues. The variance was driven primarily by:

• a $122 million increase in fuel and capacity revenues primarily due to higher retail sales volumes and accelerated recovery of the retired coal units Crystal River 1 and 2;

• a $64 million increase in retail pricing due to base rate adjustments related to annual increases from the 2017 Settlement Agreement and the solar base rate adjustment;

• a $32 million increase in other revenues primarily due to lower revenues in the prior year due to the moratorium on customer late payments and service charges in response to the COVID-19 pandemic, lower outdoor lighting equipment rentals in the prior year, and higher transmission revenues due to prior year customer settlement and the increased network billing rates;

• a $19 million increase in rider revenues primarily due to increased volumes; and

• a $16 million increase in weather-normal retail sales volumes.

Partially offset by:

• a $103 million decrease in storm revenues due to full recovery of Hurricane Dorian costs in the prior year;

• a $37 million decrease in retail sales, net of fuel revenues, due to unfavorable weather in the current year; and

• an $18 million decrease in wholesale power revenues, net of fuel, primarily due to a restructured capacity contract.

Operating Expenses. The variance was driven primarily by:

• a $96 million increase in depreciation and amortization primarily due to accelerated depreciation of retired coal units Crystal River 1 and 2 and an increase in plant base;

• a $44 million increase in fuel used in electric generation and purchased power primarily due to higher natural gas prices, and outside fuel purchases during a major plant outage at the Hines facility; and

• a $23 million increase in impairment of assets and other charges to optimize the company's real estate portfolio and reduce office space as parts of the business move to a hybrid and remote workforce strategy.

Partially offset by:

• a $46 million decrease in operation, maintenance and other expense primarily due to decreased storm amortization costs, partially offset by outage maintenance costs at Hines.

Other Income and Expense, net. The increase is primarily due to lower non-service pension costs and gains on the nuclear decommissioning trust fund.

Income Tax Expense. The decrease in tax expense was primarily due to unfavorable tax adjustments in the prior year.

MD&A			DUKE ENERGY OHIO

DUKE ENERGY OHIO

Results of Operations

			Nine Months Ended September 30,
(in millions)			2021						2020						Variance
Operating Revenues
Regulated electric			$	1,119					$	1,070					$	49
Regulated natural gas			375						324						51
Total operating revenues			1,494						1,394						100
Operating Expenses
Fuel used in electric generation and purchased power			294						258						36
Cost of natural gas			76						46						30
Operation, maintenance and other			335						333						2
Depreciation and amortization			228						208						20
Property and other taxes			266						244						22
Impairment of assets and other charges			5						—						5
Total operating expenses			1,204						1,089						115
Operating Income			290						305						(15)
Other Income and Expenses, net			14						11						3
Interest Expense			82						75						7
Income Before Income Taxes			222						241						(19)
Income Tax Expense			34						40						(6)
Net Income			$	188					$	201					$	(13)

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			2021			2021
Residential sales			2.6		%	6.8		%
General service sales			3.8		%	9.8		%
Industrial sales			5.5		%	4.2		%
Wholesale electric power sales			104.7		%	n/a
Other natural gas sales			n/a			2.5		%
Total sales			4.6		%	6.2		%
Average number of customers			0.5		%	0.8		%

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Operating Revenues. The variance was driven primarily by:

• a $31 million increase in fuel related revenues primarily due to higher natural gas prices and increased volumes;

• a $27 million increase in revenues related to OVEC collections and OVEC sales into PJM;

• a $16 million increase in PJM transmission revenues as a result of increased capital spend;

• an $11 million increase in retail pricing primarily due to the Duke Energy Kentucky general rate case; and

• a $6 million increase in revenues due to favorable weather.

Operating Expenses. The variance was driven primarily by:

• a $66 million increase in fuel expense primarily driven by higher retail prices and increased volumes for natural gas and purchased power;

• a $22 million increase in property and other taxes primarily due to increased plant in service, higher kilowatt and natural gas distribution taxes due to increased usage and a lower Network Integration Transmission Service tax deferral;

• a $20 million increase in depreciation and amortization primarily driven by an increase in distribution plant in service; and

• a $5 million increase in impairment of assets and other charges to optimize the company's real estate portfolio and reduce office space as parts of the business moves to a hybrid and remote workforce strategy.

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

MD&A			DUKE ENERGY INDIANA

DUKE ENERGY INDIANA

Results of Operations

			Nine Months Ended September 30,
(in millions)			2021						2020						Variance
Operating Revenues			$	2,366					$	2,070					$	296
Operating Expenses
Fuel used in electric generation and purchased power			710						577						133
Operation, maintenance and other			543						564						(21)
Depreciation and amortization			458						415						43
Property and other taxes			57						57						—
Impairment of assets and other charges			8						—						8
Total operating expenses			1,776						1,613						163
Operating Income			590						457						133
Other Income and Expenses, net			31						28						3
Interest Expense			148						114						34
Income Before Income Taxes			473						371						102
Income Tax Expense			77						72						5
Net Income			$	396					$	299					$	97

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			2021
Residential sales			3.0		%
General service sales			4.6		%
Industrial sales			5.5		%
Wholesale power sales			7.8		%
Total sales			4.5		%
Average number of customers			1.0		%

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Operating Revenues. The variance was driven primarily by:

• a $128 million increase primarily due to higher base rate pricing from the Indiana retail rate case, net of lower rider revenues;

• a $109 million increase in fuel revenues primarily due to higher fuel cost recovery driven by customer demand and fuel prices;

• a $29 million increase in weather-normal retail sales volumes driven by higher nonresidential customer demand; and

• a $24 million increase in wholesale revenues primarily related to the true up of wholesale transmission revenues and higher rates in the current year.

Operating Expenses. The variance was driven primarily by:

• a $133 million increase in fuel used in electric generation and purchased power expense primarily due to higher purchased power expense, higher coal and natural gas costs and higher amortization of deferred fuel costs;

• a $43 million increase in depreciation and amortization primarily due to a change in depreciation rates from the Indiana retail rate case, amortization of deferred coal ash pond ARO and additional plant in service; and

• an $8 million increase in impairment of assets and other charges to optimize the company’s real estate portfolio and reduce office space as parts of the business move to a hybrid workforce strategy.

Partially offset by:

• a $21 million decrease in operation, maintenance and other primarily due to major outage costs incurred in the prior year and outage delays in the current year.

Interest Expense. The variance is primarily due to higher post-in-service carrying costs interest resulting from the Indiana retail rate case and higher prior year coal ash spend debt returns on the Indiana Department of Environmental Management's approved ash basin closure projects.

MD&A			DUKE ENERGY INDIANA

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 excess deferred taxes.

PIEDMONT

Results of Operations

			Nine Months Ended September 30,
(in millions)			2021						2020						Variance
Operating Revenues			$	1,016					$	871					$	145
Operating Expenses
Cost of natural gas			354						254						100
Operation, maintenance and other			231						234						(3)
Depreciation and amortization			150						133						17
Property and other taxes			44						37						7
Impairment of assets and other charges			9						7						2
Total operating expenses			788						665						123
Operating Income			228						206						22
Other Income and Expenses, net			51						44						7
Interest Expense			88						89						(1)
Income Before Income Taxes			191						161						30
Income Tax Expense			16						6						10
Net Income			$	175					$	155					$	20

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			2021
Residential deliveries			16.0		%
Commercial deliveries			14.3		%
Industrial deliveries			5.4		%
Power generation deliveries			6.7		%
For resale			20.0		%
Total throughput deliveries			8.1		%
Secondary market volumes			(0.9)		%
Average number of customers			2.0		%

The margin decoupling mechanism adjusts for variations in residential and commercial use per customer, including those due to weather and conservation. The weather normalization adjustment mechanisms mostly offset the impact of weather on bills rendered, but do not ensure full recovery of approved margin during periods when winter weather is significantly warmer or colder than normal.

Nine Months Ended September 30, 2021, as compared to September 30, 2020

Operating Revenues. The variance was driven primarily by:

• a $100 million increase due to higher natural gas costs passed through to customers and increased off-system sales natural gas costs;

• a $15 million increase due to Tennessee base rate case increases; and

• an $11 million increase due to North Carolina IMR.

Operating Expenses. The variance was driven primarily by:

• a $100 million increase due to higher natural gas costs passed through to customers and increased off-system sales natural gas costs;

• a $17 million increase in depreciation expense due to additional plant in service and software projects in service; and

• a $7 million increase in property and other taxes due to higher current year property taxes in North Carolina and South Carolina.

Other Income and Expense, net. The variance is primarily driven by favorable AFUDC equity and intercompany interest income.

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

MD&A			LIQUIDITY AND CAPITAL RESOURCES

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. Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2020, included a summary and detailed discussion of projected primary sources and uses of cash for 2021 to 2023.

In January 2021, Duke Energy entered into a definitive agreement with an affiliate of GIC, for GIC to make an indirect minority interest investment of 19.9% in Duke Energy Indiana. The investment will be completed following two closings for an aggregate purchase price of approximately $2 billion. The first closing occurred on September 8, 2021, and Duke Energy Indiana Holdco, LLC, the holding company for Duke Energy Indiana, issued 11.05% of its membership interests in exchange for 50% of the total investment amount. Duke Energy has the discretion to determine the timing of the second closing, but the closing will occur no later than January 2023. At the second closing, Duke Energy Indiana Holdco, LLC will issue additional membership interests for the remaining 50% of the total investment amount, and GIC's minority interest ownership in Duke Energy Indiana Holdco, LLC will be 19.9%. Proceeds from the minority interest investment are expected to address common equity needs through 2025 to partially fund Duke Energy's $59 billion capital and investment expenditure plan.

As of September 30, 2021, Duke Energy had approximately $548 million of cash on hand, $6.3 billion available under its $8 billion Master Credit Facility and $500 million available under the $1 billion Three-Year Revolving 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. Refer to Note 5 to the Condensed Consolidated Financial Statements, "Debt and Credit Facilities," for information regarding Duke Energy's debt issuances and maturities, and available credit facilities including the Master Credit Facility.

Credit Ratings

In March 2021, Moody's Investors Services, Inc. (Moody's) downgraded by one notch the long-term credit ratings for Duke Energy (Parent) and Duke Energy Carolinas. The downgrade reflects Duke Energy's balance sheet objectives. The downgrade for Duke Energy (Parent) and Duke Energy Carolinas also considers the impact for Duke Energy Carolinas and Duke Energy Progress as a result of the 2019 rate case orders and approval of the CCR Settlement Agreement. While these agreements are indicative of a regulatory environment that remains broadly supportive of utility credit quality, their financial terms resulted in current impairment charges and lowered the amount of future cash flow Duke Energy Carolinas and Duke Energy Progress will receive in conjunction with their coal ash remediation spending. As part of the credit rating action, Moody's affirmed Duke Energy's (Parent) short-term and commercial paper credit ratings and confirmed the credit ratings for Duke Energy Progress. Following a January 2021, credit rating downgrade of Duke Energy (Parent) and its subsidiaries, Standard & Poor's Rating Services continues to maintain a stable outlook on Duke Energy Corporation and its subsidiaries as of September 30, 2021.

Cash Flow Information

The following table summarizes Duke Energy’s cash flows.

						Nine Months Ended
						September 30,
(in millions)						2021						2020
Cash flows provided by (used in):
Operating activities						$	7,227					$	6,766
Investing activities						(8,200)						(7,964)
Financing activities						1,160						1,225
Net increase in cash, cash equivalents and restricted cash						187						27
Cash, cash equivalents and restricted cash at beginning of period						556						573
Cash, cash equivalents and restricted cash at end of period						$	743					$	600

OPERATING CASH FLOWS

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

						Nine Months Ended
						September 30,
(in millions)						2021						2020						Variance
Net income						$	2,915					$	1,232					$	1,683
Non-cash adjustments to net income						4,556						6,204						(1,648)
Payments for asset retirement obligations						(389)						(463)						74
Refund of AMT credit carryforwards						—						572						(572)
Working capital						145						(779)						924
Net cash provided by operating activities						$	7,227					$	6,766					$	461

The variance was primarily due to timing of accruals and payments in working capital accounts, partially offset by prior year $572 million refund of AMT credit carryforwards.

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)						2021						2020						Variance
Capital, investment and acquisition expenditures						$	(7,119)					$	(7,684)					$	565
Other investing items						(1,081)						(280)						(801)
Net cash used in investing activities						$	(8,200)					$	(7,964)					$	(236)

The variance relates primarily to payment made to fund ACP's outstanding debt, partially offset by decreases in capital expenditures due to lower overall investments in the Electric Utilities and Infrastructure, Gas Utilities and Infrastructure and Commercial Renewables segments.

FINANCING CASH FLOWS

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

						Nine Months Ended
						September 30,
(in millions)						2021						2020						Variance
Issuances of long-term debt, net						$	2,683					$	2,694					$	(11)
Issuances of common stock						5						75						(70)
Notes payable, commercial paper and other short-term borrowings						(723)						260						(983)
Dividends paid						(2,340)						(2,113)						(227)
Contributions from noncontrolling interests						1,556						402						1,154
Other financing items						(21)						(93)						72
Net cash provided by financing activities						$	1,160					$	1,225					$	(65)

The variance was primarily due to:

• a $983 million decrease in net proceeds from issuances of notes payable and commercial paper; and

• a $227 million increase in dividends paid.

Partially offset by:

• a $1.154 billion increase in contributions from noncontrolling interests, primarily due to the $1 billion receipt from GIC to make an indirect minority interest investment of 11.05% in Duke Energy Indiana.

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 3 to the Condensed Consolidated Financial Statements, "Regulatory Matters," for further information regarding potential plant retirements and regulatory filings related to the Duke Energy Registrants.

Off-Balance Sheet Arrangements

During the three and nine months ended September 30, 2021, there were no material changes to Duke Energy’s off-balance sheet arrangements. For additional information on Duke Energy’s off-balance sheet arrangements, see “Off-Balance Sheet Arrangements” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2020.

Contractual Obligations

Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. During the three and nine months ended September 30, 2021, there were no material changes in Duke Energy's contractual obligations. For an in-depth discussion of Duke Energy’s contractual obligations, see “Contractual Obligations” and “Quantitative and Qualitative Disclosures about Market Risk” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Duke Energy’s Annual Report on Form 10-K for the year ended December 31, 2020.