Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. The 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 as presented herein may not be comparable to similarly titled measures used by other companies.

The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Duke Energy Corporation and its subsidiaries. Duke Energy Carolinas, LLC, Progress Energy, Inc., Duke Energy Progress, LLC, Duke Energy Florida, LLC, Duke Energy Ohio, Inc., Duke Energy Indiana, LLC and Piedmont Natural Gas Company, Inc. 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.

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the years ended December 31, 2021, 2020 and 2019.

See "Item 7. 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, filed with the SEC on February 25, 2021, for a discussion of variance drivers for the year ended December 31, 2020, as compared to December 31, 2019.

DUKE ENERGY

Duke Energy is an energy company headquartered in Charlotte, North Carolina. Duke Energy operates in the U.S. primarily through its direct and indirect 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.

Executive Overview

At Duke Energy the fundamentals of our business are strong and allow us to deliver growth in earnings and dividends in a low-risk, predictable and transparent way. In 2021, we continued to make progress, meeting our near-term financial commitments, executing on strategic priorities, and continuing to provide safe and reliable service while managing the ongoing impacts of the COVID-19 pandemic.

In 2021, we continued to position the company for sustainable long-term growth, working with stakeholders to achieve comprehensive bipartisan energy legislation in North Carolina, executing an important North Carolina coal ash settlement agreement, and closing the first phase of the $2 billion investment of a minority interest in Duke Energy Indiana. We remain focused on executing on our clean energy transformation and a business portfolio that will deliver a reliable and growing dividend with 2021 representing the 95th consecutive year Duke Energy paid a cash dividend on its common stock.

Financial Results

(a)See Results of Operations below for Duke Energy’s definition of adjusted earnings and adjusted EPS as well as a reconciliation of this non-GAAP financial measure to net income available to Duke Energy and net income available to Duke Energy per basic share.


MD&A			DUKE ENERGY

Duke Energy's 2021 Net Income Available to Duke Energy Corporation (GAAP Reported Earnings) were impacted by favorable rate case outcomes and improved volumes offset by charges which management believes are not indicative of ongoing performance, including impairments related to workplace and workforce realignment and regulatory settlements. See “Results of Operations” below for a detailed discussion of the consolidated results of operations and a detailed discussion of financial results for each of Duke Energy’s reportable business segments, as well as Other.

2021 Areas of Focus and Accomplishments

Clean Energy Transformation. Our industry has been undergoing an incredible transformation and 2021 was a watershed year for our company where we executed on strategic priorities and delivered on our vision.

Coal Ash Settlement

In January 2021, we reached an agreement with the North Carolina Attorney General, the North Carolina Public Staff, and the Sierra Club on costs related to coal ash management and safe basin closure, resolving the last remaining major issues on coal ash management in North Carolina. This settlement is significant as it resolves pending issues in the multiyear coal ash basin closure debate in North Carolina, which is critical for paving the way toward our clean energy future. The agreement brought financial clarity to approximately $9 billion of mitigation costs, supporting coal ash cost recovery in North Carolina for Duke Energy Carolinas and Duke Energy Progress with a rate of return for the company. We agreed to reduce North Carolina customers’ costs by approximately $1 billion, while maintaining our ability to achieve our long-term financial goals and our transition to cleaner energy. The settlement agreement resolved all coal ash prudence and cost recovery issues in connection with the 2019 rate cases filed by Duke Energy Carolinas and Duke Energy Progress with the NCUC, as well as the equitable sharing issue on remand from the 2017 Duke Energy Carolinas and Duke Energy Progress North Carolina rate cases.

Minority Interest Investment in Duke Energy Indiana

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% ownership interest in exchange for approximately $1.025 billion. The proceeds from the two-phase $2.05 billion investment are expected to partially fund the company’s $63 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.

North Carolina Energy Legislation

In October 2021, North Carolina House Bill 951 was signed into law after legislative leaders announced bipartisan support for and the General Assembly passed this new legislation. House Bill 951 reflects 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 in the state from 2005 levels by 2030 and carbon neutrality by 2050 while continuing to prioritize affordability and reliability for our customers, who are located in North Carolina 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 multiyear rate plans, that promote more efficient recovery of investments and align incentives between the company and the state’s energy policy objectives.

Generating Cleaner Energy

We’re targeting energy generated from coal to represent less than 5% by 2030 and a full exit by 2035, subject to regulatory approvals. We’ve made strong progress to date in reducing carbon emissions from electricity generation (a 44% reduction from 2005) and have committed to do more (at least 50% reduction by 2030 and net-zero by 2050). We’ve filed and refined comprehensive IRPs consistent with this strategy in multiple jurisdictions and updated the enterprise capital plan through 2026 to increase planned investments to $63 billion with over 80% of this capital plan funding investments in the grid and clean energy transition. The increased capital plan will allow us to accelerate coal plant retirements, make needed grid investments to enable renewables and energy storage, increase resiliency, and allow for dynamic power flows.

Our commitment for 2030 includes retiring higher-emitting plants, operating our existing carbon-free resources and investing in renewables, our energy delivery system, and natural gas infrastructure. In 2021, we passed the milestone of 10,000 MW of solar and wind resources and plan to own or purchase 16,000 MW of renewables by 2025 and 24,000 MW by 2030. In June, we filed an application with the NRC to renew Oconee Nuclear Station's operating licenses for an additional 20 years and we intend to seek 20-year extensions and renewal of operating licenses for all 11 reactors. As we look beyond 2030, we will need additional tools to continue our progress. We will work actively to advocate for research and development and deployment of carbon-free, dispatchable resources. That includes longer-duration energy storage, advanced nuclear technologies, carbon capture and zero-carbon fuels.

Modernizing the Power Grid and Natural Gas Infrastructure

Our grid improvement programs continue to be a key component of our growth strategy. Modernization of the electric grid, including smart meters, storm hardening, self-healing and targeted undergrounding, helps to ensure the system is better prepared for severe weather, improves the system's reliability and flexibility, and provides better information and services for customers. We continue to expand our self-optimizing grid capabilities, and in 2021, smart, self-healing technologies helped to avoid more than 700,000 extended customer outages across our six-state electric service area, saving customers more than 1.2 million hours of lost outage time. We added 60 new self-healing networks in 2021 across our six-state service area and upgraded many existing systems to improve their smart capabilities and self-healing efficiency. Additionally, we expect to invest $100 million in electric vehicle charging over the next three years. Duke Energy has a demonstrated track record of driving efficiencies and productivity into the business and we continue to leverage new technology, digital tools and data analytics across the business in response to a transforming landscape.


MD&A			DUKE ENERGY

Recognizing the continued importance of natural gas to our plans, we continue to work toward a net-zero methane emission goal by 2030 related to our natural gas distribution business. 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.

Constructive Regulatory and Legislative Outcomes. One of our long-term strategic goals is to achieve modernized regulatory constructs in our jurisdictions. Modernized constructs provide benefits, which include improved earnings and cash flows through more timely recovery of investments, as well as stable pricing for customers. As highlighted above, House Bill 951 provides the framework for many of these benefits in North Carolina under the direction of the NCUC. 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 2021, we received constructive rate case orders related to our 2019 North Carolina rate cases for both Duke Energy Carolinas and Duke Energy Progress and also reached constructive settlement agreements in our natural gas businesses in Kentucky, North Carolina, and Tennessee. In October 2021, Duke Energy Ohio filed a request to review the company’s electric distribution rates. We have a multiyear rate plan in Florida and in January 2021, we reached a constructive settlement agreement with key consumer groups to bring additional certainty to rates through 2024. In addition, grid investment riders in the Midwest and Florida enable more timely cost recovery and earnings growth.

Customer Satisfaction**.** Duke Energy continues to transform the customer experience through our use of customer data to better inform operational priorities and performance levels. This data-driven approach allows us to identify the investments that are the most important to the customer experience. We successfully implemented the first three jurisdictional releases of Customer Connect, a new system that consolidates four legacy billing systems into one customer-service platform, allowing us to deliver the universal experience customers expect. Our work has been recognized by our customers and we have maintained our above-target performance throughout the year, despite the resumption of standard billing and payment practices in most jurisdictions.

Operational Excellence, Safety and Reliability**.** The reliable and safe operation of our power plants, electric distribution system and natural gas infrastructure in our communities is foundational to our customers, our financial results and our credibility with stakeholders. Our regulated generation fleet and nuclear sites had strong performance throughout the year and our electric distribution system performed well. The safety of our workforce is a core value. Our employees delivered strong safety results in 2021, and we are at or near the top of our industry.

Storm activity was limited in our regulated service territories in 2021, but we supported Entergy Louisiana, sending approximately 500 workers to aid in restoring power after Hurricane Ida. The February winter storm in Texas adversely impacted Duke Energy Renewables’ operations. In addition to operating at reduced capacity, we were required to purchase power at scarcity pricing levels to meet fixed volume commitments. Enterprisewide lessons learned were formed immediately following the Texas weather event to identify opportunities to ensure readiness for extreme weather. Our ability to effectively handle all facets of the 2021 storm response efforts, including navigating ongoing COVID-19 protocols, is a testament to our team’s extensive preparation and coordination, applying lessons learned from previous storms, and to on-the-ground management throughout the restoration efforts. Duke Energy has received over 20 Emergency Response Awards since EEI began recognizing storm response in 1998 (including eight for assisting other utilities, and eight in our service territories over the last decade).

Leading Through COVID-19**.** COVID-19 continued to impact all that we accomplished in 2021 and demonstrated our resiliency and agility:

In addition to achieving financial results in the upper half of our original guidance, we have continued our cost-management journey – focused on driving productivity, increasing flexibility and prioritizing spend based on risk and strategic value to our customers and investors. In 2021, we maintained approximately $200 million of O&M savings identified during the earliest days of the pandemic. We also have successfully navigated supply chain challenges and the impacts of inflation. Our procurement teams have created action plans to enhance planning, augment supply, amend operations and leverage our scale to mitigate these risks to the extent possible.
Duke Energy kept electricity and natural gas flowing while continuing to voluntarily make significant accommodations for our customers. To continue to support our customers, we extended the COVID-19 payment flexibility policies we developed in 2020 without compromising our financial performance. We extended payment arrangements for new arrearages, modified reconnection policies and increased the time customers had to restructure agreements. We analyzed each state’s regulatory environment to identify additional state-specific solutions. To better connect customers to federal and state assistance dollars: a dedicated Agency team was created to help local customer assistance agencies in making pledges for Duke Energy customers; a small team was established to work directly with state and federal agencies; and a team of “payment navigators” was piloted to work directly with customers to connect them with available assistance dollars in their local communities.
We implemented safety procedures designed to provide physical safety for our workers and provided support for our employees. Throughout the year, we aligned with local, state, and federal policies on COVID-19 protocols.
In May, we announced that the Duke Energy Plaza, a 40-floor office tower currently under construction in Uptown Charlotte, will become the company’s new corporate headquarters, allowing us to reduce occupied space in the Charlotte area by approximately 60% to optimize our real estate footprint. We've rolled out our new hybrid workplace model (WorkSmart) with about 85% of our office-based workforce working in the WorkSmart model. The WorkSmart team has prepared our buildings to ensure employees return to work safely and have put in place the tools and technologies needed to ensure the most effective transition.


MD&A			DUKE ENERGY

Duke Energy Objectives – 2022 and Beyond

Duke Energy will continue to deliver exceptional value to customers, be an integral part of the communities in which we do business and provide attractive returns to investors. We have an achievable, long-term strategy in place, and it is producing tangible results, yet the industry in which we operate is becoming more and more dynamic. We are adjusting, where necessary, and accelerating our focus in key areas to ensure the company is well positioned to be successful for many decades into the future. As we look ahead to 2022, our plans include:

Continuing to place the customer at the center of all that we do, which includes providing customized products and solutions
Strengthening our relationships with our stakeholders in the communities in which we operate and invest
Generating cleaner energy and working to achieve net-zero carbon emissions by 2050 and net-zero methane emissions by 2030
Modernizing and strengthening a green-enabled energy grid and our natural gas infrastructure
Maintaining the safety of our communities and employees
Deploying digital tools across our business
Working to encourage greenhouse gas emission reductions in our supply chain as we implement the update to our goals to include Scope 2 and certain Scope 3 emissions in our 2050 net-zero goal. The Scope 3 emissions included in our goal include emissions from upstream fossil fuel procurement, production of power purchased for resale, and from downstream use of sold products in our natural gas distribution business.

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

Duke Energy Carolinas and Duke Energy Progress have approximately $1.2 billion and $1.4 billion, respectively, in regulatory assets related to coal ash retirement obligations as of December 31, 2021. Future spending, including amounts recorded for depreciation and liability accretion, is expected to continue to be deferred. The majority of spend is expected to occur over the next 15-20 years.

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 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. Duke Energy Indiana has approximately $749 million in regulatory assets related to coal ash asset retirement obligations as of December 31, 2021. In January 2022, Duke Energy Indiana received a letter from the EPA regarding interpretation of the CCR rule. See Note 4 to the Consolidated Financial Statements, "Commitments and Contingencies" for more information.

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. Duke Energy Ohio has approximately $104 million in regulatory assets related to MGP as of December 31, 2021. 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 Note 3 to the Consolidated Financial Statements, “Regulatory Matters."

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. Duke Energy has approximately $200 million in property, plant and equipment related to these assets as of December 31, 2021. Impairment of these assets could result in adverse impacts. For additional information, see Note 10 to the Consolidated Financial Statements, "Property, Plant and Equipment."

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. 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 Consolidated Financial Statements, "Business Segments" and "Commitments and Contingencies," respectively.


MD&A			DUKE ENERGY

Duke Energy is also monitoring supply chain disruptions, including the cost and availability of key components of planned generating facilities, which could impact the timing of in-service or economics of commercial renewables projects and may result in adverse impacts on operating results.

Results of Operations

Non-GAAP Measures

Management evaluates financial performance in part based on non-GAAP financial measures, including adjusted earnings and adjusted EPS. These items represent income from continuing operations available to Duke Energy common stockholders in dollar and per share amounts, adjusted for the dollar and per share impact of special items. As discussed below, special items include certain charges and credits, which management believes are not indicative of Duke Energy's ongoing performance. Management believes the presentation of adjusted earnings and adjusted EPS provides useful information to investors, as it provides them with an additional relevant comparison of Duke Energy’s performance across periods.

Management uses these non-GAAP financial measures for planning and forecasting, and for reporting financial results to the Board of Directors, employees, stockholders, analysts and investors. Adjusted EPS is also used as a basis for employee incentive bonuses. The most directly comparable GAAP measures for adjusted earnings and adjusted EPS are GAAP Reported Earnings and EPS Available to Duke Energy Corporation common stockholders (GAAP Reported EPS), respectively.

Special items included in the periods presented 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 South Carolina Supreme Court decision on coal ash, insurance proceeds, the Duke Energy Carolinas and Duke Energy Progress coal ash settlement and the partial settlements in the 2019 North Carolina rate cases.
Gas Pipeline Investments represents costs related to the cancellation of the ACP investment and additional exit obligations.
Severance represents the reversal of 2018 Severance charges, which were deferred as a result of a partial settlement in the Duke Energy Carolinas and Duke Energy Progress 2019 North Carolina rate cases.

Duke Energy’s adjusted earnings and adjusted EPS may not be comparable to similarly titled measures of another company because other companies may not calculate the measures in the same manner.

Reconciliation of GAAP Reported Amounts to Adjusted Amounts

The following table presents a reconciliation of adjusted earnings and adjusted EPS to the most directly comparable GAAP measures.


	Years Ended December 31,
	2021				2020
(in millions, except per share amounts)	Earnings		EPS		Earnings		EPS
GAAP Reported Earnings/EPS	$	3,802	$	4.94	$	1,270	$	1.72
Adjustments to Reported:
Workplace and Workforce Realignment(a)	148		0.20		—		—
Regulatory Settlements(b)	69		0.09		872		1.19
Gas Pipeline Investments(c)	15		0.02		1,711		2.32
Severance(d)	—		—		(75)		(0.10)
Discontinued Operations	(7)		(0.01)		(7)		(0.01)
Adjusted Earnings/Adjusted EPS	$	4,027	$	5.24	$	3,771	$	5.12

(a) Net of tax benefit of $44 million.

(b) Net of tax benefit of $21 million and tax benefit of $263 million for the years ended December 31, 2021, and 2020, respectively.

(c) Net of tax benefit of $5 million and tax benefit of $399 million for the years ended December 31, 2021, and 2020, respectively.

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

Year Ended December 31, 2021, as compared to 2020

GAAP Reported EPS was $4.94 for the year ended December 31, 2021, compared to $1.72 for the year ended December 31, 2020. The increase in GAAP Reported Earnings/EPS was primarily due to prior year charges related to the cancellation of the ACP pipeline and the CCR Settlement Agreement filed with the NCUC, partially offset by workplace and workforce realignment costs in the current year.

As discussed and shown in the table above, management also evaluates financial performance based on adjusted EPS. Duke Energy’s adjusted EPS was $5.24 for the year ended December 31, 2021, compared to $5.12 for the year ended December 31, 2020. The increase in Adjusted Earnings/Adjusted EPS was primarily due to positive rate case contributions and higher volumes, partially offset by higher operation and maintenance expenses, lower Commercial Renewables earnings and share dilution from equity issuances.


MD&A			SEGMENT RESULTS

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 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 Consolidated Financial Statements, “Business Segments,” for additional information on Duke Energy’s segment structure.

Electric Utilities and Infrastructure


	Years Ended December 31,


(in millions)	2021		2020		Variance
Operating Revenues	$	22,603	$	21,720	$	883
Operating Expenses
Fuel used in electric generation and purchased power	6,332		6,128		204
Operations, maintenance and other	5,340		5,391		(51)
Depreciation and amortization	4,251		4,068		183
Property and other taxes	1,233		1,188		45
Impairment of assets and other charges	204		971		(767)
Total operating expenses	17,360		17,746		(386)
Gains on Sales of Other Assets and Other, net	13		11		2
Operating Income	5,256		3,985		1,271
Other Income and Expenses, net	534		344		190
Interest Expense	1,432		1,320		112
Income Before Income Taxes	4,358		3,009		1,349
Income Tax Expense	494		340		154
Less: Income Attributable to Noncontrolling Interest	14		—		14
Segment Income	$	3,850	$	2,669	$	1,181

Duke Energy Carolinas GWh sales	87,796		84,574		3,222
Duke Energy Progress GWh sales	66,797		65,240		1,557
Duke Energy Florida GWh sales	42,422		42,490		(68)
Duke Energy Ohio GWh sales	24,129		23,484		645
Duke Energy Indiana GWh sales	31,388		30,528		860
Total Electric Utilities and Infrastructure GWh sales	252,532		246,316		6,216
Net proportional MW capacity in operation	49,871		50,419		(548)

Year Ended December 31, 2021, as compared to 2020

Electric Utilities and Infrastructure’s variance is due to higher revenues from rate cases in various jurisdictions, higher retail sales volumes and the prior year coal ash settlement agreement filed with the NCUC, partially offset by an impairment charge related to the South Carolina Supreme Court decision on coal ash, 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 $420 million increase in retail base rate pricing due to general rate cases in Indiana and North Carolina net of rider impacts as well as annual increases from the multiyear settlement rate adjustments in Florida;
a $192 million increase in weather-normal retail sales volumes;
a $172 million increase in fuel revenues primarily driven by higher sales volumes; and
a $145 million increase in wholesale revenues primarily due to a prior year coal ash settlement agreement filed with the NCUC.

Partially offset by:

a $140 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 $767 million decrease in impairment of assets and other charges primarily due to the prior year CCR Settlement Agreement filed with the NCUC in January 2021, partially offset by the South Carolina Supreme Court decision on coal ash at Duke Energy Carolinas and Duke Energy Progress in the current year; and
a $51 million decrease in operations, maintenance and other driven by decreased storm amortization at Duke Energy Florida and lower COVID-19 costs, partially offset by higher employee-related expenses.

Partially offset by:

a $204 million increase in fuel used in electric generation and purchased power primarily due to higher sales volumes;
a $183 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 at Duke Energy Carolinas and Duke Energy Progress; and
a $45 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.

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 driven by interest expense on excess deferred tax liabilities removed from rate base as a result of the North Carolina rate cases, debt returns on a lower coal ash regulatory asset balance resulting from the CCR Settlement Agreement as well lower debt returns resulting from the Indiana rate case.

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.

Gas Utilities and Infrastructure


	Years Ended December 31,


(in millions)	2021		2020		Variance
Operating Revenues	$	2,112	$	1,748	$	364
Operating Expenses
Cost of natural gas	705		460		245
Operation, maintenance and other	442		430		12
Depreciation and amortization	303		258		45
Property and other taxes	120		112		8
Impairment of assets and other charges	19		7		12
Total operating expenses	1,589		1,267		322

Operating Income	523		481		42
Other Income and Expenses
Equity in earnings (losses) of unconsolidated affiliates	8		(2,017)		2,025
Other Income and Expenses, net	62		56		6
Total other income and expenses	70		(1,961)		2,031
Interest Expense	142		135		7
Income (Loss) Before Income Taxes	451		(1,615)		2,066
Income Tax Expense (Benefit)	55		(349)		404

Segment Income (Loss)	$	396	$	(1,266)	$	1,662

Piedmont Local Distribution Company (LDC) throughput (Dth)	542,759,891		490,071,039		52,688,852
Duke Energy Midwest LDC throughput (MCF)	85,787,624		84,160,162		1,627,462

Year Ended December 31, 2021, as compared to 2020

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

Operating Revenues. The variance was driven primarily by:

a $245 million increase due to higher natural gas costs passed through to customers, higher volumes and increased off-system sales natural gas costs;
a $52 million increase due to base rate increases;
a $22 million increase due to rider revenues related to the Ohio Capital Expenditure Program (CEP);


MD&A			SEGMENT RESULTS - GAS UTILITIES AND INFRASTRUCTURE

a $12 million increase due to customer growth; and
an $11 million increase due to North Carolina IMR.

Operating Expenses. The variance was driven primarily by:

a $245 million increase in cost of natural gas due to higher natural gas prices, higher volumes and increased off-system sales natural gas costs;
a $45 million increase in depreciation due to additional plant in service and depreciation adjustments; and
a $12 million increase in impairment of assets and other charges related to the propane caverns in Ohio and Kentucky, partially offset by an impairment of ACP redelivery projects in the prior year.

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.

Commercial Renewables


	Years Ended December 31,


(in millions)	2021		2020		Variance
Operating Revenues	$	476	$	502	$	(26)
Operating Expenses
Operation, maintenance and other	342		285		57
Depreciation and amortization	225		199		26
Property and other taxes	34		27		7
Impairment of assets and other charges	—		6		(6)
Total operating expenses	601		517		84
Losses on Sales of Other Assets and Other, net	—		(1)		1
Operating Loss	(125)		(16)		(109)
Other Income and Expenses, net	(24)		7		(31)
Interest Expense	72		66		6
Loss Before Income Taxes	(221)		(75)		(146)
Income Tax Benefit	(78)		(65)		(13)
Add: Loss Attributable to Noncontrolling Interests	344		296		48
Segment Income	$	201	$	286	$	(85)

Renewable plant production, GWh	10,701		10,204		497
Net proportional MW capacity in operation(a)	4,729		3,937		792

(a) Certain projects are included in tax-equity structures where investors have differing interests in the project's economic attributes. Amounts shown represent 100% of the tax-equity project's capacity.

Year Ended December 31, 2021, as compared to 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 lower earnings from unfavorable wind resource and fewer projects financed with tax equity being placed in service in the current year.

Operating Revenues. The variance was primarily driven by a $19 million decrease due to lower wind resource and operating downtime, a $15 million decrease for lower market prices in the current year impacting the wind portfolio, and a $4 million decrease due to fewer distributed energy projects placed into service. This was partially offset by an $8 million increase for market sales in excess of market purchases during Texas Storm Uri and a $6 million increase due to growth of new projects.

Operating Expenses. The variance was primarily due to $49 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, $31 million increase for higher operating expenses attributed to maintenance at several wind and solar facilities, an $8 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.

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 PTCs generated.

Loss Attributable to Noncontrolling Interests. The variance was primarily driven by the net increase of losses allocated to tax equity members of $60 million from existing and new projects financed with tax equity, partially offset by a $12 million loss resulting from Texas Storm Uri.


MD&A			SEGMENT RESULTS - OTHER

Other


	Years Ended December 31,


(in millions)	2021		2020		Variance
Operating Revenues	$	111	$	97	$	14






Operating Expenses	412		12		400
Losses on Sales of Other Assets and Other, net	(1)		—		(1)
Operating (Loss) Income	(302)		85		(387)
Other Income and Expenses, net	121		92		29
Interest Expense	643		657		(14)
Loss Before Income Taxes	(824)		(480)		(344)
Income Tax Benefit	(279)		(162)		(117)
Less: Net Income Attributable to Noncontrolling Interests	1		1		—
Less: Preferred Dividends	106		107		(1)
Net Loss	$	(652)	$	(426)	$	(226)

Year Ended December 31, 2021, as compared to 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 in operations, maintenance and other of $248 million was primarily due to a reversal of severance costs in the prior year and higher obligations to the Duke Energy Foundation in the current year. The increase in impairment of assets and other charges of $132 million was due to asset impairments taken in order 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 equity earnings from the NMC investment.

Income Tax Benefit. The increase in the tax benefit was primarily driven by an increase in pretax losses and a reduction of a valuation allowance relating to a capital loss carryforward, partially offset by lower state tax expense in the prior year.


MD&A			DUKE ENERGY CAROLINAS

SUBSIDIARY REGISTRANTS

Basis of Presentation

The results of operations and variance discussion for the Subsidiary Registrants is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.

DUKE ENERGY CAROLINAS

Results of Operations


	Years Ended December 31,
(in millions)	2021		2020		Variance
Operating Revenues	$	7,102	$	7,015	$	87
Operating Expenses
Fuel used in electric generation and purchased power	1,601		1,682		(81)
Operation, maintenance and other	1,833		1,743		90
Depreciation and amortization	1,468		1,462		6
Property and other taxes	320		299		21
Impairment of assets and other charges	227		476		(249)
Total operating expenses	5,449		5,662		(213)
Gains on Sales of Other Assets and Other, net	2		1		1
Operating Income	1,655		1,354		301
Other Income and Expenses, net	270		177		93
Interest Expense	538		487		51
Income Before Income Taxes	1,387		1,044		343
Income Tax Expense	51		88		(37)
Net Income	$	1,336	$	956	$	380

The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Carolinas. The below 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	4.6	%
General service sales	2.7	%
Industrial sales	5.2	%
Wholesale power sales	4.5	%
Joint dispatch sales	2.8	%
Total sales	3.8	%
Average number of customers	2.3	%

Year Ended December 31, 2021, as compared to 2020

Operating Revenues. The variance was driven primarily by:

a $98 million increase in weather-normal retail sales volumes;
a $53 million increase in wholesale revenue primarily driven by the CCR Settlement Agreement filed with the NCUC in January 2021;
a $51 million increase due to higher pricing from the North Carolina retail rate case, net of a return of EDIT to customer; and
a $13 million increase in retail sales due to more favorable weather.

Partially offset by:

an $87 million decrease in fuel revenues due to lower prices, partially offset by higher retail sales volumes; and
a $26 million decrease in rider revenues primarily due to energy efficiency programs.

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

a $249 million decrease in impairment of assets and other charges due to the prior year CCR Settlement Agreement filed with the NCUC in January 2021, partially offset by the South Carolina Supreme Court decision on coal ash 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
an $81 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.


MD&A			DUKE ENERGY CAROLINAS

Partially offset by:

a $90 million increase in operation, maintenance and other expense primarily due to higher employee-related expenses; and
a $21 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 sales and use tax refunds in the current year and lower payroll tax due to the CARES Act employee retention credits.

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

Interest Expense. The variance was driven by interest expense on excess deferred tax liabilities removed from rate base as a result of the North Carolina rate case and debt returns on a lower coal ash regulatory asset balance resulting from the CCR Settlement Agreement.

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.

PROGRESS ENERGY

Results of Operations


	Years Ended December 31,
(in millions)	2021		2020		Variance
Operating Revenues	$	11,057	$	10,627	$	430
Operating Expenses
Fuel used in electric generation and purchased power	3,584		3,479		105
Operation, maintenance and other	2,529		2,479		50
Depreciation and amortization	1,929		1,818		111
Property and other taxes	542		545		(3)
Impairment of assets and other charges	82		495		(413)
Total operating expenses	8,666		8,816		(150)
Gains on Sales of Other Assets and Other, net	14		9		5
Operating Income	2,405		1,820		585
Other Income and Expenses, net	215		129		86
Interest Expense	794		790		4
Income Before Income Taxes	1,826		1,159		667
Income Tax Expense	227		113		114


Net Income	1,599		1,046		553
Less: Net Income Attributable to Noncontrolling Interests	1		1		—
Net Income Attributable to Parent	$	1,598	$	1,045	$	553

Year Ended December 31, 2021, as compared to 2020

Operating Revenues. The variance was driven primarily by:

a $223 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 $176 million increase in fuel cost recovery driven by higher volumes in the current year and accelerated recovery of retired Crystal River coal units;
a $70 million increase in weather-normal retail sales volumes;
a $58 million increase in wholesale revenues, net of fuel, primarily driven by a prior year coal ash settlement and higher capacity volumes at Duke Energy Progress, partially offset by a restructured capacity contract at Duke Energy Florida;
a $25 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 $20 million increase in rider revenues at Duke Energy Florida primarily due to increased retail sales volumes.

Partially offset by:

a $140 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 $413 million decrease in impairment of assets and other charges primarily due to the prior year CCR Settlement Agreement filed with the NCUC in January 2021, partially offset by the current year South Carolina Supreme Court decision on coal ash 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.


MD&A			PROGRESS ENERGY

Partially offset by:

a $111 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;
a $105 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; and
a $50 million increase in operation, maintenance and other expense driven by higher employee-related costs, a prior year severance cost adjustment related to the 2019 North Carolina retail rate case and outage costs, partially offset by reduced storm amortization at Duke Energy Florida.

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 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.

DUKE ENERGY PROGRESS

Results of Operations


	Years Ended December 31,
(in millions)	2021		2020		Variance
Operating Revenues	$	5,780	$	5,422	$	358
Operating Expenses
Fuel used in electric generation and purchased power	1,778		1,743		35
Operation, maintenance and other	1,467		1,332		135
Depreciation and amortization	1,097		1,116		(19)
Property and other taxes	159		167		(8)
Impairment of assets and other charges	63		499		(436)
Total operating expenses	4,564		4,857		(293)
Gains on Sales of Other Assets and Other, net	13		8		5
Operating Income	1,229		573		656
Other Income and Expenses, net	143		75		68
Interest Expense	306		269		37
Income Before Income Taxes	1,066		379		687
Income Tax Expense (Benefit)	75		(36)		111
Net Income	$	991	$	415	$	576

The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Progress. The below 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	6.0	%
General service sales	(0.4)	%
Industrial sales	(7.7)	%
Wholesale power sales	4.0	%
Joint dispatch sales	(2.2)	%
Total sales	2.4	%
Average number of customers	1.5	%

Year Ended December 31, 2021, as compared to 2020

Operating Revenues. The variance was driven primarily by:

a $140 million increase due to higher pricing from the North Carolina retail rate case, net of a return of EDIT to customers;
an $80 million increase in wholesale revenues, net of fuel, primarily due to a coal ash settlement in the prior year, and higher capacity volumes, partially offset by lower recovery of coal ash costs;
a $58 million increase in weather-normal retail sales volumes in the current year;


MD&A			DUKE ENERGY PROGRESS

a $44 million increase in retail sales due to more favorable weather; and
a $14 million increase in fuel cost recovery driven by higher fuel prices and volumes in the current year.

Operating Expenses. The variance was driven primarily by:

a $436 million decrease in impairment of assets and other charges primarily due to the prior year CCR Settlement Agreement filed with the NCUC in January 2021; and
a $19 million decrease in depreciation and amortization expense, primarily driven by the extension of the lives of nuclear facilities.

Partially offset by:

a $135 million increase in operation, maintenance and other expense primarily due to higher employee-related costs and a prior year severance cost adjustment related to the 2019 North Carolina retail rate case, increased outage costs and energy efficiency program costs; and
a $35 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.

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 by interest expense on excess deferred tax liabilities removed from rate base as a result of the North Carolina rate case and debt returns on a lower coal ash regulatory asset balance resulting from the CCR Settlement Agreement.

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

DUKE ENERGY FLORIDA

Results of Operations


	Years Ended December 31,
(in millions)	2021		2020		Variance
Operating Revenues	$	5,259	$	5,188	$	71
Operating Expenses
Fuel used in electric generation and purchased power	1,806		1,737		69
Operation, maintenance and other	1,048		1,131		(83)
Depreciation and amortization	831		702		129
Property and other taxes	383		381		2
Impairment of assets and other charges	19		(4)		23
Total operating expenses	4,087		3,947		140
Gains on Sales of Other Assets and Other, net	1		1		—
Operating Income	1,173		1,242		(69)
Other Income and Expenses, net	71		53		18
Interest Expense	319		326		(7)
Income Before Income Taxes	925		969		(44)
Income Tax Expense	187		198		(11)
Net Income	$	738	$	771	$	(33)

The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Florida. The below 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 year	2021
Residential sales	(1.2)	%
General service sales	2.3	%
Industrial sales	4.6	%
Wholesale power sales	22.6	%
Total sales	(0.2)	%
Average number of customers	1.5	%


MD&A			DUKE ENERGY FLORIDA

Year Ended December 31, 2021, as compared to 2020

Operating Revenues. The variance was driven primarily by:

a $162 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;
an $83 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 $25 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 $20 million increase in rider revenues primarily due to increased volumes; and
a $12 million increase in weather-normal retail sales volumes.

Partially offset by:

a $140 million decrease in storm revenues due to full recovery of Hurricane Dorian costs in the prior year;
a $63 million decrease in retail sales, net of fuel revenues, due to unfavorable weather in the current year; and
a $22 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 $129 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 $69 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:

an $83 million decrease in operation, maintenance and other expense primarily due to decreased storm amortization costs, partially offset by outage maintenance costs at Hines and the timing of Customer Connect costs including training and labor.

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 a decrease in pretax income.


MD&A			DUKE ENERGY OHIO

DUKE ENERGY OHIO

Results of Operations


	Years Ended December 31,
(in millions)	2021		2020		Variance
Operating Revenues
Regulated electric	$	1,493	$	1,405	$	88
Regulated natural gas	544		453		91

Total operating revenues	2,037		1,858		179
Operating Expenses
Fuel used in electric generation and purchased power	409		339		70

Cost of natural gas	136		73		63
Operation, maintenance and other	479		463		16
Depreciation and amortization	307		278		29
Property and other taxes	355		324		31
Impairment of assets and other charges	25		—		25
Total operating expenses	1,711		1,477		234
Gains on Sales of Other Assets and Other, net	1		—		1
Operating Income	327		381		(54)
Other Income and Expenses, net	18		16		2
Interest Expense	111		102		9
Income Before Income Taxes	234		295		(61)
Income Tax Expense	30		43		(13)


Net Income	$	204	$	252	$	(48)

The following table shows the percent changes in GWh sales of electricity, MCF of natural gas delivered and average number of electric and natural gas customers for Duke Energy Ohio. The below 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	2.7	%		—	%
General service sales	3.0	%		4.8	%
Industrial sales	4.0	%		3.2	%
Wholesale electric power sales	45.8	%		n/a
Other natural gas sales	n/a			1.6	%
Total sales	2.7	%		1.9	%
Average number of customers	0.6	%		0.8	%

Year Ended December 31, 2021, as compared to 2020

Operating Revenues. The variance was driven primarily by:

an $88 million increase in fuel-related revenues primarily due to higher natural gas prices and increased volumes;
a $35 million increase in revenues related to OVEC collections and OVEC sales into PJM;
a $22 million increase due to revenues related the Ohio CEP;
an $18 million increase in PJM transmission revenues as a result of increased capital spend;
a $12 million increase in retail pricing primarily due to the Duke Energy Kentucky electric general rate case; and
a $5 million increase in revenues due to favorable weather.

Operating Expenses. The variance was driven primarily by:

a $133 million increase in fuel expense primarily driven by higher retail prices and increased volumes for natural gas and purchased power;
a $31 million increase in property and other taxes primarily due to increased plant in service, and higher kilowatt and natural gas distribution taxes due to increased usage;


MD&A			DUKE ENERGY OHIO

a $28 million increase in depreciation and amortization primarily driven by an increase in distribution plant in service and decreased Ohio CEP deferrals; and
a $25 million increase in impairment of assets and other charges related to the propane caverns in Ohio and Kentucky 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.

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

DUKE ENERGY INDIANA

Results of Operations


	Years Ended December 31,
(in millions)	2021		2020		Variance
Operating Revenues	$	3,174	$	2,795	$	379
Operating Expenses
Fuel used in electric generation and purchased power	985		767		218
Operation, maintenance and other	750		762		(12)
Depreciation and amortization	615		569		46
Property and other taxes	73		81		(8)
Impairment of assets and other charges	9		—		9
Total operating expenses	2,432		2,179		253

Operating Income	742		616		126
Other Income and Expenses, net	42		37		5
Interest Expense	196		161		35
Income Before Income Taxes	588		492		96
Income Tax Expense	107		84		23
Net Income	$	481	$	408	$	73

The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Indiana. The below 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	4.3	%
Industrial sales	2.9	%
Wholesale power sales	5.8	%
Total sales	2.8	%
Average number of customers	1.1	%

Year Ended December 31, 2021, as compared to 2020

Operating Revenues. The variance was driven primarily by:

a $175 million increase in fuel revenues primarily due to higher fuel cost recovery driven by customer demand and fuel prices;
a $134 million increase primarily due to higher base rate pricing from the Indiana retail rate case, net of lower rider revenues;
a $34 million increase in wholesale revenues primarily related to higher rates in the current year;
a $22 million increase in weather-normal retail sales volumes driven by higher nonresidential customer demand; and
a $14 million increase in retail sales due to favorable weather in the current year.

Operating Expenses. The variance was driven primarily by:

a $218 million increase in fuel used in electric generation and purchased power expense primarily due to higher natural gas prices and increased purchased power;
a $46 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
a $9 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.


MD&A			DUKE ENERGY INDIANA

Partially offset by:

a $12 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; and
an $8 million decrease in property and other taxes attributable to property tax true ups for prior periods, utility receipts tax refunds and lower payroll tax due to the CARES Act employee retention credits.

Interest Expense. The variance is primarily driven by lower post-in-service carrying costs and higher debt returns in the prior year on ash basin closure costs resulting from the Indiana retail rate case.

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

PIEDMONT

Results of Operations


	Years Ended December 31,
(in millions)	2021		2020		Variance



Operating Revenues	$	1,569	$	1,297	$	272
Operating Expenses
Cost of natural gas	569		386		183
Operation, maintenance and other	327		322		5
Depreciation and amortization	213		180		33
Property and other taxes	55		53		2
Impairment of assets and other charges	10		7		3
Total operating expenses	1,174		948		226

Operating Income	395		349		46
Equity in earnings of unconsolidated affiliates	9		9		—

Other income and expenses, net	55		51		4
Total other income and expenses	64		60		4
Interest Expense	119		118		1
Income Before Income Taxes	340		291		49
Income Tax Expense	30		18		12
Net Income	$	310	$	273	$	37

The following table shows the percent changes in Dth 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	7.0	%
Commercial deliveries	6.9	%
Industrial deliveries	4.1	%
Power generation deliveries	14.0	%
For resale	13.2	%
Total throughput deliveries	10.8	%
Secondary market volumes	37.2	%
Average number of customers	1.9	%

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.

Year Ended December 31, 2021, as compared to 2020

Operating Revenues. The variance was driven primarily by:

a $183 million increase due to higher natural gas costs passed through to customers, higher volumes, and increased off-system sales natural gas costs;
a $52 million increase due to base rate increases;
a $12 million increase due to customer growth; and
an $11 million increase due to North Carolina IMR.


MD&A			PIEDMONT

Operating Expenses. The variance was driven primarily by:

a $183 million increase due to higher natural gas costs passed through to customers, higher volumes, and increased off-system sales natural gas costs; and
a $33 million increase in depreciation expense due to additional plant in service and depreciation adjustments.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Preparation of financial statements requires the application of accounting policies, judgments, assumptions and estimates that can significantly affect the reported results of operations, cash flows or the amounts of assets and liabilities recognized in the financial statements. Judgments made include the likelihood of success of particular projects, possible legal and regulatory challenges, earnings assumptions on pension and other benefit fund investments and anticipated recovery of costs, especially through regulated operations.

Management discusses these policies, estimates and assumptions with senior members of management on a regular basis and provides periodic updates on management decisions to the Audit Committee. Management believes the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions that are inherently uncertain and that may change in subsequent periods.

For further information, see Note 1 to the Consolidated Financial Statements, "Summary of Significant Accounting Policies."

Regulated Operations Accounting

Substantially all of Duke Energy’s regulated operations meet the criteria for application of regulated operations accounting treatment. As a result, Duke Energy is required to record assets and liabilities that would not be recorded for nonregulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities are recorded when it is probable that a regulator will require Duke Energy to make refunds to customers or reduce rates to customers for previous collections or deferred revenue for costs that have yet to be incurred.

Management continually assesses whether recorded regulatory assets are probable of future recovery by considering factors such as:

applicable regulatory environment changes;
historical regulatory treatment for similar costs in Duke Energy’s jurisdictions;
litigation of rate orders;
recent rate orders to other regulated entities;
levels of actual return on equity compared to approved rates of return on equity; and
the status of any pending or potential deregulation legislation.

If future recovery of costs ceases to be probable, asset write-offs would be recognized in operating income. Additionally, regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment, recognition of asset retirement costs and amortization of regulatory assets, or may disallow recovery of all or a portion of certain assets.

As required by regulated operations accounting rules, significant judgment can be required to determine if an otherwise recognizable incurred cost qualifies to be deferred for future recovery as a regulatory asset. Significant judgment can also be required to determine if revenues previously recognized are for entity specific costs that are no longer expected to be incurred or have not yet been incurred and are therefore a regulatory liability.

For further information, see Note 3 to the Consolidated Financial Statements, "Regulatory Matters."

Goodwill Impairment Assessments

Duke Energy performed its annual goodwill impairment tests for all reporting units as of August 31, 2021. Additionally, Duke Energy monitors all relevant events and circumstances during the year to determine if an interim impairment test is required. Such events and circumstances include an adverse regulatory outcome, declining financial performance and deterioration of industry or market conditions. As of August 31, 2021, all of the reporting units' estimated fair value of equity substantially exceeded the carrying value of equity. The fair values of the reporting units were calculated using a weighted combination of the income approach, which estimates fair value based on discounted cash flows, and the market approach, which estimates fair value based on market comparables within the utility and energy industries.

Estimated future cash flows under the income approach are based on Duke Energy’s internal business plan. Significant assumptions used are growth rates, future rates of return expected to result from ongoing rate regulation and discount rates. Management determines the appropriate discount rate for each of its reporting units based on the WACC for each individual reporting unit. The WACC takes into account both the after-tax cost of debt and cost of equity. A major component of the cost of equity is the current risk-free rate on 20-year U.S. Treasury bonds. In the 2021 impairment tests, Duke Energy considered implied WACCs for certain peer companies in determining the appropriate WACC rates to use in its analysis. As each reporting unit has a different risk profile based on the nature of its operations, including factors such as regulation, the WACC for each reporting unit may differ. Accordingly, the WACCs were adjusted, as appropriate, to account for company specific risk premiums. The discount rates used for calculating the fair values as of August 31, 2021, for each of Duke Energy’s reporting units ranged from 5.4% to 5.8%. The underlying assumptions and estimates are made as of a point in time. Subsequent changes, particularly changes in the discount rates, authorized regulated rates of return or growth rates inherent in management’s estimates of future cash flows, could result in future impairment charges.


MD&A			CRITICAL ACCOUNTING POLICIES AND ESTIMATES

One of the most significant assumptions utilized in determining the fair value of reporting units under the market approach is implied market multiples for certain peer companies. Management selects comparable peers based on each peer’s primary business mix, operations, and market capitalization compared to the applicable reporting unit and calculates implied market multiples based on available projected earnings guidance and peer company market values as of August 31. The implied market multiples used for calculating the fair values as of August 31, 2021, for each of Duke Energy's reporting units ranged from 9.7 to 12.7.

Duke Energy primarily operates in environments that are rate-regulated. In such environments, revenue requirements are adjusted periodically by regulators based on factors including levels of costs, sales volumes and costs of capital. Accordingly, Duke Energy’s regulated utilities operate to some degree with a buffer from the direct effects, positive or negative, of significant swings in market or economic conditions. However, significant changes in discount rates or implied market multiples over a prolonged period may have a material impact on the fair value of equity.

Duke Energy has approximately $19.3 billion in Goodwill at both December 31, 2021, and 2020. For further information, see Note 11 to the Consolidated Financial Statements, "Goodwill and Intangible Assets."

Asset Retirement Obligations

AROs are recognized for legal obligations associated with the retirement of property, plant and equipment at the present value of the projected liability in the period in which it is incurred, if a reasonable estimate of fair value can be made. Duke Energy has approximately $12.8 billion and $13 billion of AROs as of December 31, 2021, and 2020, respectively. See Note 9, "Asset Retirement Obligations," for further details including a rollforward of related liabilities.

The present value of the initial obligation and subsequent updates are based on discounted cash flows, which include estimates regarding the amount and timing of future cash flows, regulatory, legal, and legislative decisions, selection of discount rates and cost escalation rates, among other factors. These estimates are subject to change.

Obligations for nuclear decommissioning are based on site-specific cost studies. Duke Energy Carolinas and Duke Energy Progress assume prompt dismantlement of the nuclear facilities after operations are ceased. During 2020, Duke Energy Florida, closed an agreement for the accelerated decommissioning of the Crystal River Unit 3 nuclear power station after receiving approval from the NRC and FPSC. The retirement obligations for the decommissioning of Crystal River Unit 3 nuclear power station are measured based on accelerated decommissioning from 2020 continuing through 2027. Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida also assume that spent fuel will be stored on-site until such time that it can be transferred to a yet to be built DOE facility.

Obligations for closure of ash basins are based upon discounted cash flows of estimated costs for site-specific plans. Certain ash basins have had probability weightings applied to them based on different potential closure methods and the probabilities surrounding pending legal changes.

For further information, see Notes 3, 4 and 9 to the Consolidated Financial Statements, "Regulatory Matters," "Commitments and Contingencies" and "Asset Retirement Obligations."

Long-Lived Asset Impairment Assessments, Excluding Regulated Operations

Duke Energy evaluates property, plant and equipment for impairment when events or changes in circumstances (such as a significant change in cash flow projections or the determination that it is more likely than not that an asset or asset group will be sold) indicate the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with their carrying value.

Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the undiscounted future cash flows. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value and recording a loss if the carrying value is greater than the fair value. Additionally, determining fair value requires probability weighting future cash flows to reflect expectations about possible variations in their amounts or timing and the selection of an appropriate discount rate. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. When determining whether an asset or asset group has been impaired, management groups assets at the lowest level that has discrete cash flows.

During 2021, Duke Energy evaluated recoverability of certain renewable merchant plants due to changing market pricing and declining long-term forecasted energy prices, primarily driven by lower long-term forecasted natural gas prices, capital cost of new renewables and increased renewable penetration. It was determined the assets were all recoverable as the carrying value of the assets approximated or were less than the aggregate estimated future cash flows. Duke Energy has approximately $200 million and $210 million in Property, plant and equipment related to these assets as of December 31, 2021, and 2020, respectively.

Workplace and workforce realignment has been a focus for the company and costs have been incurred attributable to business transformation, including long-term real estate strategy changes and workforce realignment. For further information, see Notes 2 and 10 to the Consolidated Financial Statements, "Business Segments" and "Property, Plant and Equipment."

Pension and Other Post-Retirement Benefits

The calculation of pension expense, other post-retirement benefit expense and net pension and other post-retirement assets or liabilities require the use of assumptions and election of permissible accounting alternatives. Changes in assumptions can result in different expense and reported asset or liability amounts and future actual experience can differ from the assumptions. Duke Energy believes the most critical assumptions for pension and other post-retirement benefits are the expected long-term rate of return on plan assets and the assumed discount rate applied to future projected benefit payments.


MD&A			CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Duke Energy elects to amortize net actuarial gain or loss amounts that are in excess of 10% of the greater of the market-related value of plan assets or the plan's projected benefit obligation, into net pension or other post-retirement benefit expense over the average remaining service period of active participants expected to benefit under the plan. If all or almost all of a plan's participants are inactive, the average remaining life expectancy of the inactive participants is used instead of average remaining service period. Prior service cost or credit, which represents an increase or decrease in a plan's pension benefit obligation resulting from plan amendment, is amortized on a straight-line basis over the average expected remaining service period of active participants expected to benefit under the plan. If all or almost all of a plan's participants are inactive, the average remaining life expectancy of the inactive participants is used instead of average remaining service period.

As of December 31, 2021, Duke Energy assumes pension and other post-retirement plan assets will generate a long-term rate of return of 6.50%. The expected long-term rate of return was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers, where applicable. The asset allocation targets were set after considering the investment objective and the risk profile. Equity securities are held for their higher expected returns. Debt securities are primarily held to hedge the qualified pension liability. Real assets, return-seeking fixed income, hedge funds and other global securities are held for diversification. Investments within asset classes are diversified to achieve broad market participation and reduce the impact of individual managers on investments.

Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 2.90% as of December 31, 2021. Discount rates used to measure benefit plan obligations for financial reporting purposes reflect rates at which pension benefits could be effectively settled. As of December 31, 2021, Duke Energy determined its discount rate for U.S. pension and other post-retirement obligations using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high-quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected.

Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Duke Energy’s pension and post-retirement plans will impact future pension expense and liabilities. Duke Energy cannot predict with certainty what these factors will be in the future. The following table presents the approximate effect on Duke Energy’s 2022 pretax pension expense, pretax other post-retirement expense, pension obligation and other post-retirement benefit obligation if a 0.25% change in rates were to occur.


	Qualified and Non-						Other Post-Retirement
	Qualified Pension Plans						Plans
(in millions)	0.25		%	(0.25)		%	0.25		%	(0.25)		%
Effect on 2022 pretax pension and other post-retirement expense:
Expected long-term rate of return	$	(21)		$	21		$	—		$	—
Discount rate	(6)			6			1			(1)
Effect on pension and other post-retirement benefit obligation at December 31, 2022:
Discount rate	(189)			193			(11)			12

For further information, see Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans.”

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, Duke Energy does not expect to be a significant federal cash taxpayer until around 2030.


MD&A			LIQUIDITY AND CAPITAL RESOURCES

Capital Expenditures

Duke Energy continues to focus on reducing risk and positioning its business for future success and will invest principally in its strongest business sectors. Duke Energy’s projected capital and investment expenditures, including AFUDC debt and capitalized interest, for the next three fiscal years are included in the table below.


(in millions)	2022		2023		2024
New generation	$	14	$	156	$	445
Regulated renewables	742		1,194		1,346
Environmental	780		580		461
Nuclear fuel	453		366		385
Major nuclear	252		186		48
Customer additions	596		591		605
Grid modernization and other transmission and distribution projects	4,154		4,377		4,526
Maintenance and other	2,959		3,050		2,609
Total Electric Utilities and Infrastructure	9,950		10,500		10,425
Gas Utilities and Infrastructure	1,350		1,375		1,150
Commercial Renewables and Other	1,050		1,100		650


Total projected capital and investment expenditures	$	12,350	$	12,975	$	12,225

Debt

Long-term debt maturities and the interest payable on long-term debt each represent a significant cash requirement for the Duke Energy Registrants. See Note 6 to the Consolidated Financial Statements, “Debt and Credit Facilities,” for information regarding the Duke Energy Registrants' long-term debt at December 31, 2021, the weighted average interest rate applicable to each long-term debt category and a schedule of long-term debt maturities over the next five years.

Fuel and Purchased Power

Fuel and purchased power includes firm capacity payments that provide Duke Energy with uninterrupted firm access to electricity transmission capacity and natural gas transportation contracts, as well as undesignated contracts and contracts that qualify as NPNS. Duke Energy’s contractual cash obligations for fuel and purchased power as of December 31, 2021, are as follows:


	Payments Due by Period
(in millions)	Total		Less than 1 year (2022)		2-3 years (2023 & 2024)		4-5 years (2025 & 2026)		More than 5 years (2027 & beyond)
Fuel and purchased power	$	19,976	$	4,594	$	6,071	$	3,618	$	5,693

Other Purchase Obligations

Other purchase obligations includes contracts for software, telephone, data and consulting or advisory services, contractual obligations for EPC costs for new generation plants, wind and solar facilities, plant refurbishments, maintenance and day-to-day contract work and commitments to buy certain products. Amount excludes certain open purchase orders for services that are provided on demand for which the timing of the purchase cannot be determined. Total cash commitments for related other purchase obligation expenditures are $7,941 million, with $7,526 million expected to be paid in the next 12 months.

See Note 5 to the Consolidated Financial Statements, “Leases” for a schedule of both finance lease and operating lease payments over the next five years. See Note 9 to the Consolidated Financial Statements, “Asset Retirement Obligations” for information on nuclear decommissioning trust funding obligations and the closure of ash impoundments.

Duke Energy performs ongoing assessments of its respective guarantee obligations to determine whether any liabilities have been incurred as a result of potential increased nonperformance risk by third parties for which Duke Energy has issued guarantees. See Note 7 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements. Issuance of these guarantee arrangements is not required for the majority of Duke Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantees, there would not be a material impact to the consolidated results of operations, cash flows or financial position. Other than the guarantee arrangements discussed in Note 7 and off-balance sheet debt related to non-consolidated VIEs, Duke Energy does not have any material off-balance sheet financing entities or structures. For additional information, see Note 17 to the Consolidated Financial Statements, "Variable Interest Entities."

Cash and Liquidity

The Subsidiary Registrants generally maintain minimal cash balances and use short-term borrowings to meet their working capital needs and other cash requirements. The Subsidiary Registrants, excluding Progress Energy, support their short-term borrowing needs through participation with Duke Energy and certain of its other subsidiaries in a money pool arrangement. The companies with short-term funds may provide short-term loans to affiliates participating under this arrangement. See Note 6 to the Consolidated Financial Statements, “Debt and Credit Facilities,” for additional discussion of the money pool arrangement.


MD&A			LIQUIDITY AND CAPITAL RESOURCES

Duke Energy and the Subsidiary Registrants, excluding Progress Energy, may also use short-term debt, including commercial paper and the money pool, as a bridge to long-term debt financings. The levels of borrowing may vary significantly over the course of the year due to the timing of long-term debt financings and the impact of fluctuations in cash flows from operations. From time to time, Duke Energy’s current liabilities exceed current assets resulting from the use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate due to the seasonality of its businesses.

As of December 31, 2021, Duke Energy had approximately $343 million of cash on hand, $5.0 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. Additionally, by January 2023, Duke Energy is expecting another $1,025 million from GIC for the second closing of the investment in Duke Energy Indiana. Proceeds from the minority interest investment are expected to partially fund Duke Energy's $63 billion capital and investment expenditure plan. Refer to Notes 6 and 19 to the Consolidated Financial Statements, "Debt and Credit Facilities" and "Stockholders' Equity," respectively, for information regarding Duke Energy's debt and equity issuances, debt maturities and available credit facilities including the Master Credit Facility.

Credit Facilities and Registration Statements

See Note 6 to the Consolidated Financial Statements, "Debt and Credit Facilities," for further information regarding credit facilities and shelf registration statements available to Duke Energy and the Duke Energy Registrants.

Dividend Payments

In 2021, Duke Energy paid quarterly cash dividends for the 95th consecutive year and expects to continue its policy of paying regular cash dividends in the future. There is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, financial condition and are subject to the discretion of the Board of Directors.

Duke Energy targets a dividend payout ratio of between 65% and 75%, based upon adjusted EPS. Duke Energy increased the dividend by approximately 2% annually in both 2021 and 2020, and the company remains committed to continued growth of the dividend.

Dividend and Other Funding Restrictions of Duke Energy Subsidiaries

As discussed in Note 3 to the Consolidated Financial Statements, “Regulatory Matters,” Duke Energy’s wholly owned public utility operating companies have restrictions on the amount of funds that can be transferred to Duke Energy through dividends, advances or loans as a result of conditions imposed by various regulators in conjunction with merger transactions. Duke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures and Articles of Incorporation, which in certain circumstances, limit their ability to make cash dividends or distributions on common stock. Additionally, certain other Duke Energy subsidiaries have other restrictions, such as minimum working capital and tangible net worth requirements pursuant to debt and other agreements that limit the amount of funds that can be transferred to Duke Energy. At December 31, 2021, the amount of restricted net assets of wholly owned subsidiaries of Duke Energy that may not be distributed to Duke Energy in the form of a loan or dividend does not exceed a material amount of Duke Energy’s net assets. Duke Energy does not have any legal or other restrictions on paying common stock dividends to shareholders out of its consolidated equity accounts. Although these restrictions cap the amount of funding the various operating subsidiaries can provide to Duke Energy, management does not believe these restrictions will have a significant impact on Duke Energy’s ability to access cash to meet its payment of dividends on common stock and other future funding obligations.

Cash Flows From Operating Activities

Cash flows from operations of Electric Utilities and Infrastructure and Gas Utilities and Infrastructure are primarily driven by sales of electricity and natural gas, respectively, and costs of operations. These cash flows from operations are relatively stable and comprise a substantial portion of Duke Energy’s operating cash flows. Weather conditions, working capital and commodity price fluctuations and unanticipated expenses including unplanned plant outages, storms, legal costs and related settlements can affect the timing and level of cash flows from operations.

As part of Duke Energy’s continued effort to improve its cash flows from operations and liquidity, Duke Energy works with vendors to improve terms and conditions, including the extension of payment terms. To support this effort, Duke Energy established a supply chain finance program (the “program”) in 2020, under which suppliers, at their sole discretion, may sell their receivables from Duke Energy to the participating financial institution. The financial institution administers the program. Duke Energy does not issue any guarantees with respect to the program and does not participate in negotiations between suppliers and the financial institution. Duke Energy does not have an economic interest in the supplier’s decision to participate in the program and receives no interest, fees or other benefit from the financial institution based on supplier participation in the program. Suppliers’ decisions on which invoices are sold do not impact Duke Energy’s payment terms, which are based on commercial terms negotiated between Duke Energy and the supplier regardless of program participation. A significant deterioration in the credit quality of Duke Energy, economic downturn or changes in the financial markets could limit the financial institutions willingness to participate in the program. Duke Energy does not believe such risk would have a material impact on our cash flows from operations or liquidity, as substantially all our payments are made outside the program.

Duke Energy believes it has sufficient liquidity resources through the commercial paper markets, and ultimately, the Master Credit Facility, to support these operations. Cash flows from operations are subject to a number of other factors, including, but not limited to, regulatory constraints, economic trends and market volatility (see Item 1A, “Risk Factors,” for additional information).

Debt Issuances

Depending on availability based on the issuing entity, the credit rating of the issuing entity, and market conditions, the Subsidiary Registrants prefer to issue first mortgage bonds and secured debt, followed by unsecured debt. This preference is the result of generally higher credit ratings for first mortgage bonds and secured debt, which typically result in lower interest costs. Duke Energy Corporation primarily issues unsecured debt.


MD&A			LIQUIDITY AND CAPITAL RESOURCES

In 2022, Duke Energy anticipates issuing additional securities of $9.5 billion through debt capital markets. In certain instances Duke Energy may utilize instruments other than senior notes, including equity-content securities such as subordinated debt or preferred stock. Proceeds will primarily be for the purpose of funding capital expenditures and debt maturities. See to Note 6 to the Consolidated Financial Statements, "Debt and Credit Facilities," for further information regarding significant debt issuances in 2021.

Duke Energy’s capitalization is balanced between debt and equity as shown in the table below.


	Projected 2022		Actual 2021		Actual 2020
Equity	42	%	43	%	44	%
Debt	58	%	57	%	56	%

Restrictive Debt Covenants

Duke Energy’s debt and credit agreements contain various financial and other covenants. Duke Energy's Master Credit Facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower, excluding Piedmont, and 70% for Piedmont. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements or sublimits thereto. As of December 31, 2021, each of the Duke Energy Registrants was in compliance with all covenants related to their debt agreements. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Credit Ratings

Moody’s Investors Service, Inc. and S&P provide credit ratings for various Duke Energy Registrants. The following table includes Duke Energy and certain subsidiaries’ credit ratings and ratings outlook as of February 2022.


	Moody's	S&P
Duke Energy Corporation	Stable	Stable
Issuer Credit Rating	Baa2	BBB+
Senior Unsecured Debt	Baa2	BBB
Junior Subordinated Debt/Preferred Stock	Baa3/Ba1	BBB-
Commercial Paper	P-2	A-2
Duke Energy Carolinas	Stable	Stable
Senior Secured Debt	Aa3	A
Senior Unsecured Debt	A2	BBB+
Progress Energy	Stable	Stable
Senior Unsecured Debt	Baa1	BBB
Duke Energy Progress	Stable	Stable
Senior Secured Debt	Aa3	A

Duke Energy Florida	Stable	Stable
Senior Secured Debt	A1	A
Senior Unsecured Debt	A3	BBB+
Duke Energy Ohio	Stable	Stable
Senior Secured Debt	A2	A
Senior Unsecured Debt	Baa1	BBB+
Duke Energy Indiana	Stable	Stable
Senior Secured Debt	Aa3	A
Senior Unsecured Debt	A2	BBB+
Duke Energy Kentucky	Stable	Stable
Senior Unsecured Debt	Baa1	BBB+
Piedmont Natural Gas	Stable	Stable
Senior Unsecured	A3	BBB+

Credit ratings are intended to provide credit lenders a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold. The Duke Energy Registrants’ credit ratings are dependent on the rating agencies’ assessments of their ability to meet their debt principal and interest obligations when they come due. If, as a result of market conditions or other factors, the Duke Energy Registrants are unable to maintain current balance sheet strength, or if earnings and cash flow outlook materially deteriorates, credit ratings could be negatively impacted.


MD&A			LIQUIDITY AND CAPITAL RESOURCES

Cash Flow Information

The following table summarizes Duke Energy’s cash flows for the two most recently completed fiscal years.


	Years Ended December 31,


(in millions)	2021		2020
Cash flows provided by (used in):
Operating activities	$	8,290	$	8,856
Investing activities	(10,935)		(10,604)
Financing activities	2,609		1,731

Net decrease in cash, cash equivalents and restricted cash	(36)		(17)
Cash, cash equivalents and restricted cash at beginning of period	556		573
Cash, cash equivalents and restricted cash at end of period	$	520	$	556

OPERATING CASH FLOWS

The following table summarizes key components of Duke Energy’s operating cash flows for the two most recently completed fiscal years.


	Years Ended December 31,


(in millions)	2021		2020		Variance
Net income	$	3,579	$	1,082	$	2,497
Non-cash adjustments to net income	5,941		8,353		(2,412)
Payments for AROs	(540)		(610)		70

Refund of AMT credit carryforwards	—		572		(572)
Working capital	(690)		(541)		(149)
Net cash provided by operating activities	$	8,290	$	8,856	$	(566)

The variance was driven primarily by:

a $572 million refund of AMT credit carryforwards in the prior year; and
a $149 million increase in cash outflows from working capital primarily due to an increase in under collected fuel used in generation due to higher pricing, partially offset by coal ash insurance litigation proceeds, fluctuations in accounts payable levels and timing of property tax accruals and payments in the current year.

Partially offset by:

an $85 million increase in net income after adjustment for non-cash items primarily due to higher revenues from rate cases in various jurisdictions, higher retail sales volumes and the prior year coal ash settlement agreement filed with the NCUC, partially offset by an impairment charge related to the South Carolina Supreme Court Decision on coal ash, higher depreciation, amortization and accretion and interest expense; and
a $70 million decrease in payments for AROs.

INVESTING CASH FLOWS

The following table summarizes key components of Duke Energy’s investing cash flows for the two most recently completed fiscal years.


	Years Ended December 31,


(in millions)	2021		2020		Variance
Capital, investment and acquisition expenditures, net of return of investment capital	$	(9,752)	$	(10,144)	$	392
Debt and equity securities, net	5		(62)		67

Disbursements to canceled equity method investments	(855)		—		(855)
Other investing items	(333)		(398)		65
Net cash used in investing activities	$	(10,935)	$	(10,604)	$	(331)


MD&A			LIQUIDITY AND CAPITAL RESOURCES

The variance relates primarily to a payment made to fund ACP's outstanding debt, partially offset by a decrease in capital expenditures due to lower overall investments in the Commercial Renewables segment. The primary use of cash related to investing activities is typically capital, investment and acquisition expenditures, net of return of investment capital detailed by reportable business segment in the following table.


	Years Ended December 31,


(in millions)	2021		2020		Variance
Electric Utilities and Infrastructure	$	7,653	$	7,612	$	41
Gas Utilities and Infrastructure	1,271		1,303		(32)
Commercial Renewables	543		965		(422)
Other	285		264		21
Total capital, investment and acquisition expenditures, net of return of investment capital	$	9,752	$	10,144	$	(392)

FINANCING CASH FLOWS

The following table summarizes key components of Duke Energy’s financing cash flows for the two most recently completed fiscal years.


	Years Ended December 31,


(in millions)	2021		2020		Variance
Issuance of common stock	$	5	$	2,745	$	(2,740)

Issuances of long-term debt, net	3,758		1,824		1,934
Notes payable and commercial paper	479		(319)		798
Dividends paid	(3,114)		(2,812)		(302)

Contributions from noncontrolling interests	1,575		426		1,149
Other financing items	(94)		(133)		39
Net cash provided by financing activities	$	2,609	$	1,731	$	878

The variance was driven primarily by:

a $1,934 million net increase in proceeds from issuances of long-term debt, primarily due to timing of issuances and redemptions of long-term debt;
a $1,149 million increase in contributions from noncontrolling interests, primarily due to a $1,025 million receipt from GIC to make an indirect minority interest investment of 11.05% in Duke Energy Indiana; and
a $798 million increase in net borrowings from notes payable and commercial paper.

Partially offset by:

a $2,740 million decrease in proceeds from the issuance of common stock.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Management Policies

The Enterprise Risk Management policy framework at Duke Energy includes strategy, operational, project execution and financial or transaction related risks. Enterprise Risk Management includes market risk as part of the financial and transaction related risks in its framework.

Duke Energy is exposed to market risks associated with commodity prices, interest rates and equity prices. Duke Energy has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy’s Chief Executive Officer and Chief Financial Officer are responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Finance and Risk Management Committee of the Board of Directors receives periodic updates from the Chief Risk Officer and other members of management on market risk positions, corporate exposures and overall risk management activities. The Chief Risk Officer is responsible for the overall governance of managing commodity price risk, including monitoring exposure limits.

The following disclosures about market risk contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. See Item 1A, “Risk Factors,” and “Cautionary Statement Regarding Forward-Looking Information” for a discussion of the factors that may impact any such forward-looking statements made herein.

Commodity Price Risk

Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including the effects of regulation, commodity contract size and length, market liquidity, market conditions, location and unique or specific contract terms. Duke Energy is exposed to the impact of market fluctuations in the prices of electricity, coal, natural gas and other energy-related products marketed and purchased as a result of its ownership of energy-related assets.


MD&A			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Duke Energy’s exposure to these fluctuations through its regulated utility operations is limited since these operations are subject to cost-based regulation and are typically allowed to recover substantially all of these costs through various cost recovery clauses, including fuel clauses, formula-based contracts, or other cost-sharing mechanisms. While there may be a delay in timing between when these costs are incurred and when they are recovered through rates, changes from year to year generally do not have a material impact on operating results of these regulated operations.

Within Duke Energy’s Commercial Renewables segment, the company has exposure to market price fluctuations in prices of electricity or other energy-related products as a result of its ownership of renewable assets, although its exposure to the market price of power is generally limited by entering into contracts with third parties to sell the production of these assets, usually for a term of 10 to 15 years from commercial operation.

Duke Energy employs established policies and procedures to manage risks associated with these market fluctuations, which may include using various commodity derivatives, such as swaps, futures, forwards and options. For additional information, see Note 14 to the Consolidated Financial Statements, “Derivatives and Hedging.”

Generation Portfolio Risks

For the Electric Utilities and Infrastructure segment, the generation portfolio not utilized to serve retail operations or committed load is subject to commodity price fluctuations. However, the impact on the Consolidated Statements of Operations is limited due to mechanisms in these regulated jurisdictions that result in the sharing of most of the net profits from these activities with retail customers.

The majority of the energy assets in Duke Energy’s Commercial Renewables segment operate in regions managed by RTOs and are therefore governed and dispatched under the rules of the applicable RTO. Depending on the structure of power sale agreements with third parties, these assets may be exposed to basis risk associated with different locational marginal prices based on the specific delivery locations and requirements specified in the agreements. Additionally, these assets may be subject to operational constraints under the RTO rules and may be exposed to market price risk.

Hedging Strategies

Duke Energy monitors risks associated with commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, coal and natural gas hedging contracts and options to mitigate the effect of such fluctuations on operations. Duke Energy’s primary use of energy commodity derivatives is to hedge against exposure to the prices of power, fuel for generation and natural gas for customers. Additionally, Duke Energy’s Commercial Renewables business may enter into short-term or long-term hedge agreements to manage price risk associated with project output to the extent such output is not under contract to third parties.

Duke Energy also manages its exposure to basis risk through the use of congestion hedge products in RTOs such as financial transmission rights (PJM) and congestion revenue rights (ERCOT), which result in payments based on differentials in locational marginal prices. The majority of instruments used to manage Duke Energy’s commodity price exposure are either not designated as hedges or do not qualify for hedge accounting. These instruments are referred to as undesignated contracts. Mark-to-market changes for undesignated contracts entered into by regulated businesses are reflected as regulatory assets or liabilities on the Consolidated Balance Sheets. Undesignated contracts entered into by nonregulated businesses are marked-to-market each period, with changes in the fair value of the derivative instruments reflected in earnings.

Duke Energy may also enter into other contracts that qualify for the NPNS exception. When a contract meets the criteria to qualify as NPNS, Duke Energy applies such exception. Income recognition and realization related to NPNS contracts generally coincide with the physical delivery of the commodity. For contracts qualifying for the NPNS exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract as long as the transaction remains probable of occurring.

Interest Rate Risk

Duke Energy is exposed to risk resulting from changes in interest rates as a result of its issuance or anticipated issuance of variable and fixed-rate debt and commercial paper. Duke Energy manages interest rate exposure by limiting variable-rate exposures to a percentage of total debt and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, which may include instruments such as, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. See Notes 1, 6, 14 and 16 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Debt and Credit Facilities,” “Derivatives and Hedging,” and “Fair Value Measurements.”

Duke Energy had $7.5 billion of unhedged long- and short-term floating interest rate exposure at December 31, 2021. The impact of a 100-basis point change in interest rates on pretax income is approximately $75 million at December 31, 2021. This amount was estimated by considering the impact of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges as of December 31, 2021.

Certain Duke Energy Registrants have variable-rate debt and manage interest rate risk by entering into financial contracts including interest rate swaps. See Notes 6 and 14 to the Consolidated Financial Statements, "Debt and Credit Facilities" and "Derivatives and Hedging." Such financial arrangements generally are indexed based upon LIBOR, which is expected to be fully phased out in 2023. The Secured Overnight Financing Rate (SOFR) has been identified by regulators and industry participants as the preferred successor rate for U.S. dollar-based LIBOR. Impacted financial arrangements extending beyond the phaseout of LIBOR may require contractual amendment or termination and renegotiation to fully adapt to a post-LIBOR environment, and there may be uncertainty regarding the effectiveness of any such alternative index methodologies. Alternative index provisions are being assessed and incorporated into new financial arrangements that extend beyond the phaseout of LIBOR. Additionally, the progress of the phaseout is being monitored, including proposed transition relief from the FASB.

Credit Risk

Credit risk represents the loss that the Duke Energy Registrants would incur if a counterparty fails to perform under its contractual obligations. Where exposed to credit risk, the Duke Energy Registrants analyze the counterparty's financial condition prior to entering into an agreement and monitor exposure on an ongoing basis. The Duke Energy Registrants establish credit limits where appropriate in the context of contractual arrangements and monitor such limits.


MD&A			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

To reduce credit exposure, the Duke Energy Registrants seek to include netting provisions with counterparties, which permit the offset of receivables and payables with such counterparties. The Duke Energy Registrants also frequently use master agreements with credit support annexes to further mitigate certain credit exposures. The master agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents a negotiated unsecured credit limit for each party to the agreement, determined in accordance with the Duke Energy Registrants’ internal corporate credit practices and standards. Collateral agreements generally also provide that the failure to post collateral when required is sufficient cause to terminate transactions and liquidate all positions.

The Duke Energy Registrants also obtain cash, letters of credit, or surety bonds from certain counterparties to provide credit support outside of collateral agreements, where appropriate, based on a financial analysis of the counterparty and the regulatory or contractual terms and conditions applicable to each transaction. See Note 14 to the Consolidated Financial Statements, “Derivatives and Hedging,” for additional information regarding credit risk related to derivative instruments.

The Duke Energy Registrants’ principal counterparties for its electric and natural gas businesses are RTOs, distribution companies, municipalities, electric cooperatives and utilities located throughout the U.S. Exposure to these entities consists primarily of amounts due to Duke Energy Registrants for delivered electricity. Additionally, there may be potential risks associated with remarketing of energy and capacity in the event of default by wholesale power customers. The Duke Energy Registrants have concentrations of receivables from certain of such entities that may affect the Duke Energy Registrants’ credit risk.

The Duke Energy Registrants are also subject to credit risk from transactions with their suppliers that involve prepayments or milestone payments in conjunction with outsourcing arrangements, major construction projects and certain commodity purchases. The Duke Energy Registrants’ credit exposure to such suppliers may take the form of increased costs or project delays in the event of nonperformance. The Duke Energy Registrants' frequently require guarantees or letters of credit from suppliers to mitigate this credit risk.

Credit risk associated with the Duke Energy Registrants’ service to residential, commercial and industrial customers is generally limited to outstanding accounts receivable. The Duke Energy Registrants mitigate this credit risk by requiring tariff customers to provide a cash deposit, letter of credit or surety bond until a satisfactory payment history is established, subject to the rules and regulations in effect in each retail jurisdiction at which time the deposit is typically refunded. Charge-offs for retail customers have historically been insignificant to the operations of the Duke Energy Registrants and are typically recovered through retail rates. Management continually monitors customer charge-offs, payment patterns and the impact of current economic conditions on customers' ability to pay their outstanding balance to ensure the adequacy of bad debt reserves.

In response to the COVID-19 pandemic, in March 2020, the Duke Energy Registrants announced a suspension of disconnections for nonpayment as a result of the national emergency. While disconnections have resumed, the company continued to offer flexible options to customers struggling with the pandemic and the economic fallout, including extended payment arrangements to satisfy delinquent balances through June 2021. Since then, the company has resumed standard payment arrangement options . The Duke Energy Registrants are still monitoring the effects of the resultant economic slowdown on counterparties’ abilities to perform under their contractual obligations. The Duke Energy Registrants have observed a significant increase in utility account arrears as of December 31, 2021. There is an expectation of an increase in charge-offs in the future and the Duke Energy Registrants have reserved for these losses in the allowance for doubtful account balance. See Notes 3 and 18 to the Consolidated Financial Statements, "Regulatory Matters" and "Revenue," respectively, for more information. Duke Energy Ohio and Duke Energy Indiana sell certain of their accounts receivable and related collections through CRC, a Duke Energy consolidated VIE. Losses on collection are first absorbed by the equity of CRC and next by the subordinated retained interests held by Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana. See Note 17 to the Consolidated Financial Statements, “Variable Interest Entities.”

The Duke Energy Registrants provide certain non-tariff services, primarily to large commercial and industrial customers in which incurred costs, including invested capital, are intended to be recovered from the individual customer and therefore are not subject to rate recovery in the event of customer default. Customer creditworthiness is assessed prior to entering into these transactions. Credit concentration related to these transactions exists for certain of these customers.

Duke Energy’s Commercial Renewables segment enters into long-term agreements with certain creditworthy buyers that may not include the right to call for collateral in the event of a credit rating downgrade. Credit concentration exists to certain counterparties on these agreements, including entities that could be subject to wildfire liability. Additionally, Commercial Renewables may invest in projects for which buyers are below investment grade, although such buyers are required to post negotiated amounts of credit support. Also, power sales agreements and/or hedges of project output are generally for an initial term that does not cover the entire life of the asset. As a result, Commercial Renewables is exposed to market price risk and credit risk related to these agreements.

Duke Energy Carolinas has third-party insurance to cover certain losses related to asbestos-related injuries and damages above an aggregate self-insured retention. See Note 4 to the Consolidated Financial Statements, "Commitments and Contingencies" for information on asbestos-related injuries and damages claims.

The Duke Energy Registrants also have credit risk exposure through issuance of performance and financial guarantees, letters of credit and surety bonds on behalf of less than wholly owned entities and third parties. Where the Duke Energy Registrants have issued these guarantees, it is possible that they could be required to perform under these guarantee obligations in the event the obligor under the guarantee fails to perform. Where the Duke Energy Registrants have issued guarantees related to assets or operations that have been disposed of via sale, they attempt to secure indemnification from the buyer against all future performance obligations under the guarantees. See Note 7 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further information on guarantees issued by the Duke Energy Registrants.

Based on the Duke Energy Registrants’ policies for managing credit risk, their exposures and their credit and other reserves, the Duke Energy Registrants do not currently anticipate a materially adverse effect on their consolidated financial position or results of operations as a result of nonperformance by any counterparty.


MD&A			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketable Securities Price Risk

As described further in Note 15 to the Consolidated Financial Statements, “Investments in Debt and Equity Securities,” Duke Energy invests in debt and equity securities as part of various investment portfolios to fund certain obligations. The vast majority of investments in equity securities are within the NDTF and assets of the various pension and other post-retirement benefit plans.

Pension Plan Assets

Duke Energy maintains investments to facilitate funding the costs of providing non-contributory defined benefit retirement and other post-retirement benefit plans. These investments are exposed to price fluctuations in equity markets and changes in interest rates. The equity securities held in these pension plans are diversified to achieve broad market participation and reduce the impact of any single investment, sector or geographic region. Duke Energy has established asset allocation targets for its pension plan holdings, which take into consideration the investment objectives and the risk profile with respect to the trust in which the assets are held. See Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans,” for additional information regarding investment strategy of pension plan assets.

A significant decline in the value of plan asset holdings could require Duke Energy to increase funding of its pension plans in future periods, which could adversely affect cash flows in those periods. Additionally, a decline in the fair value of plan assets, absent additional cash contributions to the plan, could increase the amount of pension cost required to be recorded in future periods, which could adversely affect Duke Energy’s results of operations in those periods.

Nuclear Decommissioning Trust Funds

As required by the NRC, NCUC, PSCSC and FPSC, subsidiaries of Duke Energy maintain trust funds to fund the costs of nuclear decommissioning. As of December 31, 2021, these funds were invested primarily in domestic and international equity securities, debt securities, cash and cash equivalents and short-term investments. Per the NRC, Internal Revenue Code, NCUC, PSCSC and FPSC requirements, these funds may be used only for activities related to nuclear decommissioning. These investments are exposed to price fluctuations in equity markets and changes in interest rates. Duke Energy actively monitors its portfolios by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes.

Accounting for nuclear decommissioning recognizes that costs are recovered through retail and wholesale rates; therefore, fluctuations in investment prices do not materially affect the Consolidated Statements of Operations, as changes in the fair value of these investments are primarily deferred as regulatory assets or regulatory liabilities pursuant to Orders by the NCUC, PSCSC, FPSC and FERC. Earnings or losses of the funds will ultimately impact the amount of costs recovered through retail and wholesale rates. See Note 9 to the Consolidated Financial Statements, “Asset Retirement Obligations,” for additional information regarding nuclear decommissioning costs. See Note 15 to the Consolidated Financial Statements, “Investments in Debt and Equity Securities,” for additional information regarding NDTF assets.

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.

The following sections outline various proposed and recently enacted legislation and regulations that may impact the Duke Energy Registrants. Refer to Note 3 to the Consolidated Financial Statements, "Regulatory Matters," for further information regarding potential plant retirements and regulatory filings related to the Duke Energy Registrants.

Coal Combustion Residuals

In April 2015, EPA published a rule to regulate the disposal of CCR from electric utilities as solid waste. The federal regulation classifies CCR as nonhazardous waste and allows for beneficial use of CCR with some restrictions. The regulation applies to all new and existing landfills, new and existing surface impoundments receiving CCR and existing surface impoundments located at stations generating electricity (regardless of fuel source), which were no longer receiving CCR but contained liquids as of the effective date of the rule. The rule establishes requirements regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring, protection and remedial procedures and other operational and reporting procedures to ensure the safe disposal and management of CCR.

On July 17, 2018, EPA issued a final rule (Phase 1, Part 1) revising certain closure deadlines and groundwater protection standards in the CCR rule. The rule does not change the primary requirements for groundwater monitoring, corrective action, inspections and maintenance, and closure, and thus does not materially affect Duke Energy’s coal ash basin closure plans or compliance obligations under the CCR rule. On October 22, 2018, a coalition of environmental groups filed a petition for review in the U.S. Court of Appeals for the District of Columbia (D.C. Circuit Court) challenging EPA's final Phase 1, Part 1 revisions to the CCR rule. On March 13, 2019, the D.C. Circuit Court issued an order in the Phase 1, Part 1 litigation granting EPA’s motion to remand the rule without vacatur. To date, EPA has finalized two notice-and-comment rulemakings to implement the court’s decision on remand. The “Part A” rule, which was promulgated on August 28, 2020, establishes an April 11, 2021 deadline to cease placement of CCR and non-CCR waste streams into unlined ash basins and initiate closure, and the “Part B” rule, which was promulgated on November 12, 2020, establishes procedures to allow facilities to request approval to operate an existing CCR surface impoundment with an alternate liner.

In addition to the requirements of the federal CCR rule, CCR landfills and surface impoundments will continue to be regulated by the states. Cost recovery for future expenditures will be pursued through the normal ratemaking process with federal and state utility commissions and via wholesale contracts, which permit recovery of necessary and prudently incurred costs associated with Duke Energy’s regulated operations. For more information, see Notes 3 and 9 to the Consolidated Financial Statements, "Regulatory Matters" and "Asset Retirement Obligations," respectively.


MD&A			OTHER MATTERS

Coal Ash Act

AROs recorded on the Duke Energy Carolinas and Duke Energy Progress Consolidated Balance Sheets at December 31, 2021, and December 31, 2020, include the legal obligation for closure of coal ash basins and the disposal of related ash as a result of the Coal Ash Act, the EPA CCR rule and other agreements. The Coal Ash Act includes a variance procedure for compliance deadlines and other issues surrounding the management of CCR and CCR surface impoundments and prohibits cost recovery in customer rates for unlawful discharge of ash impoundment waters occurring after January 1, 2014. The Coal Ash Act leaves the decision on cost recovery determinations related to closure of ash impoundments to the normal ratemaking processes before utility regulatory commissions.

Consistent with the requirements of the Coal Ash Act, Duke Energy previously submitted comprehensive site assessments and groundwater corrective action plans to NCDEQ. In addition, on December 31, 2019, Duke Energy submitted updated groundwater corrective action plans and site-specific coal ash impoundment closure plans to NCDEQ.

On April 1, 2019, NCDEQ issued a closure determination requiring Duke Energy Carolinas and Duke Energy Progress to excavate all remaining coal ash impoundments at the Allen, Belews Creek, Rogers, Marshall, Mayo and Roxboro facilities in North Carolina. On April 26, 2019, Duke Energy Carolinas and Duke Energy Progress filed Petitions for Contested Case Hearings in the Office of Administrative Hearings to challenge NCDEQ's April 1 Order. On December 31, 2019, Duke Energy Carolinas and Duke Energy Progress entered into a settlement agreement with NCDEQ and certain community groups under which Duke Energy Carolinas and Duke Energy Progress agreed to excavate seven of the nine remaining coal ash basins at these sites with ash moved to on-site lined landfills, including two at Allen, one at Belews Creek, one at Mayo, one at Roxboro, and two at Rogers. At the two remaining basins at Marshall and Roxboro, uncapped basin ash will be excavated and moved to lined landfills. Those portions of the basins at Marshall and Roxboro, which were previously filled with ash and on which permitted facilities were constructed, will not be disturbed and will be closed pursuant to other state regulations.

Following NCDEQ's April 1 Order, Duke Energy estimated the incremental undiscounted cost to close the nine remaining impoundments by excavation would be approximately $4 billion to $5 billion, potentially increasing the total estimated costs to permanently close all ash basins in North Carolina and South Carolina to $9.5 billion to $10.5 billion. The settlement lowers the estimated total undiscounted cost to close the nine remaining basins by excavation by approximately $1.5 billion as compared to Duke Energy’s original estimate that followed the order. As a result, the estimated total cost to permanently close all ash basins in North Carolina and South Carolina is approximately $8 billion to $9 billion of which approximately $3.1 billion has been spent through 2021. The majority of the remaining spend is expected to occur over the next 15 to 20 years.

Duke Energy has completed excavation of all coal ash at the Riverbend, Dan River and Sutton plants.

For further information on ash basins and recovery, see Notes 3 and 9 to the Consolidated Financial Statements, "Regulatory Matters" and “Asset Retirement Obligations,” respectively.

North Carolina House Bill 951

On October 13, 2021, North Carolina Governor Roy Cooper signed into law legislation passed by the North Carolina House of Representatives and Senate (the “Legislation”). This Legislation establishes a framework overseen by the NCUC to advance state CO2 emissions reductions through the use of least cost planning while providing for continued reliability and affordable rates for customers served by such generation. It also authorizes the use of performance-based regulation in North Carolina. Among other things, the Legislation requires the NCUC to:

develop an initial carbon plan that would target a 70% reduction in CO2 emissions from public utilities' electric generation in the state by 2030 and carbon neutrality by 2050, considering all resource options and the latest technology;
adopt rules to implement the requirements of the Legislation authorizing performance-based regulation that includes multiyear rate plans with a maximum three-year term, performance incentive mechanisms to track utility performance, and revenue decoupling for the residential customer class;
establish rules to securitize costs associated with the early retirement of subcritical coal-fired electric generating facilities necessary to achieve the authorized carbon reduction goals at 50% of remaining net book value, with the remaining net book value recovered through normal cost of service basis; and
initiate a process for updating rates and terms of certain existing solar power purchase agreements executed under PURPA.

Other Environmental Regulations

The Duke Energy Registrants are also subject to various federal, state and local laws regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Duke Energy continues to comply with enacted environmental statutes and regulations even as certain of these regulations are in various stages of clarification, revision or legal challenge. The Duke Energy Registrants cannot predict the outcome of these matters.

Global Climate Change and Regulation of GHG Emissions

In 2021, President Biden recommitted the United States to the Paris Agreement and announced a new target for the United States of 50% - 52% reduction in economywide net GHG emissions from 2005 levels by 2030. The U.S. submittal to support this Paris target includes a goal for 100% carbon-free electricity by 2035. These actions have been supplemented by a number of executive orders by President Biden and an indication by a number of regulatory agencies, including the EPA, that they would impose additional regulations on CO2 and methane emissions to which Duke Energy will be subject. The Duke Energy Registrants are monitoring these matters and cannot predict the outcome, however, there could be a material impact on our climate strategy.


MD&A			OTHER MATTERS

CO****2 Emissions Reductions

The Duke Energy Registrants’ direct GHG emissions consist primarily of CO2 that results primarily from operating a fleet of coal-fired and natural gas-fired power plants to serve its customers reliably and affordably. On September 17, 2019, Duke Energy announced an updated climate strategy with new goals of at least 50% reduction in carbon emissions from electric generation by 2030 and net-zero carbon emissions from electric generation by 2050. The Duke Energy Registrants have taken actions that have resulted in a reduction of CO2 emissions over time. Between 2005 and 2021, the Duke Energy Registrants have collectively lowered the CO2 emissions from their electricity generation by 44%. Timelines and initiatives, as well as implementation of new technologies, for future reductions of GHG emissions will vary in each state in which the company operates and will involve collaboration with regulators, customers and other stakeholders. The goals announced in 2019, as well as the actions taken to reduce CO2 emissions, potentially lower the exposure to any future mandatory CO2 emission reduction requirements, whether as a result of federal legislation, EPA regulation, state regulation or other as yet unknown emission reduction requirement.

Actions to reduce CO2 emissions have included the retirement of 56 coal-fired electric generating units with a combined generating capacity of 7,500 MW, while investing in renewables and state-of-the-art highly efficient natural gas-fired generation that produces far fewer CO2 emissions per unit of electricity generated than coal. Duke Energy also has made investments to increase EE offerings and ensure continued operations of its zero-CO2 emissions hydropower and nuclear plants. These efforts have diversified its system and significantly reduced CO2 emissions.

Duke Energy will continue to explore the use of currently available and commercially demonstrated technology to reduce CO2 emissions, including EE, wind, solar and storage, as well as evolving technologies like carbon capture, utilization and storage, the use of hydrogen and other low-carbon fuels, long-duration storage and advanced nuclear, in its efforts to achieve its net-zero goal as well as to comply with any future regulations. Duke Energy plans to adjust to and incorporate evolving and innovative technologies in a way that balances the reliability and affordability while meeting regulatory requirements and customer demands. Under any future scenario involving mandatory CO2 limitations, the Duke Energy Registrants would plan to seek recovery of their compliance costs through appropriate regulatory mechanisms. Future levels of GHG emissions by the Duke Energy Registrants will be influenced by variables that include capacity needs in the jurisdictions in which they operate, public policy, tax incentives, economic conditions that affect electricity demand, fuel prices, market prices, availability of resources and labor, compliance with new or existing regulations, the ability to make enhancements to transmission and distribution systems to support increased renewables, and the existence of new technologies that can be deployed to generate the electricity necessary to meet customer demand.

Currently, the Duke Energy Registrants do not purchase carbon credits or offsets for use in connection with the company's net-zero emissions goals. Though they may purchase carbon credits or offsets for such uses in the future , the amount or cost of which is not expected to be material at this time.

Generation Mix Planning Process

The Duke Energy Registrants annually, biennially or triennially prepare lengthy, forward-looking IRPs. These detailed, highly technical plans are based on the company’s thorough analysis of numerous factors that can impact the cost of producing and delivering electricity that influence long-term generation resource planning decisions. The IRP process helps to evaluate a range of options, taking into account stakeholder input as well as forecasts of future electricity demand, fuel prices, transmission improvements, new generating capacity, integration of renewables, energy storage, EE and demand response initiatives. The IRP process also helps evaluate potential environmental and regulatory scenarios to better mitigate policy and economic risks. The IRPs we file with regulators look out 10 to 20 years depending on the jurisdiction.

For a number of years, the Duke Energy Registrants have included a price on CO2 emissions in their IRP planning process to account for the potential regulation of CO2 emissions. Incorporating a price on CO2 emissions in the IRPs allows for the evaluation of existing and future resource needs against potential climate change policy risk in the absence of policy certainty. One of the challenges with using a CO2 price, especially in the absence of a clear and certain policy, is determining the appropriate price to use. To address this uncertainty and ensure the company remains agile, the Duke Energy Registrants typically use a range of potential CO2 prices to reflect a range of potential policy outcomes.

In September 2020, Duke Energy Carolinas and Duke Energy Progress filed their IRPs in North Carolina and South Carolina, and, in December 2021, Duke Energy Indiana filed its IRP, outlining an accelerated energy transition which aligns with the company's 2030 CO2 emissions goal. In December 2021 the PSCSC rejected Duke Energy Carolinas and Duke Energy Progress’ preferred accelerated coal retirements IRP scenario and instead found that the base case without a price on CO2 emissions was the most reasonable IRP scenario.

In 2021, the State of North Carolina passed HB 951, which among other things, directs the NCUC to develop and approve a carbon reduction plan by the end of 2022 that would target a 70% reduction in CO2 emissions from Duke Energy Progress' and Duke Energy Carolinas' electric generation in the state by 2030 and carbon neutrality by 2050, considering all resource options and the latest technology. In light of this legislation, in November 2021, the NCUC declined to make a determination on the portfolios presented in the 2020 IRP noting that the legislation may impact the schedule for coal plant retirements and new resources and limited its order to short term actions for use on an interim basis pending preparation of the carbon plan. The NCUC's carbon reduction plan will be informed by Duke Energy's initial carbon plan, which will be filed with the NCUC by May 16, 2022, building on the IRPs that were filed in 2020 by Duke Energy Carolinas and Duke Energy Progress and incorporating feedback from extensive stakeholder engagement.

CO****2 and Methane Emissions Reductions from the Natural Gas Distribution Business

In addition to CO2 emissions resulting primarily from our operations of coal-fired and natural gas-fired power plants, the Duke Energy Registrants are also responsible for certain methane emissions from the distribution of natural gas to customers. On October 9, 2020, Duke Energy announced a new goal to achieve net-zero methane emissions from its natural gas distribution business by 2030. The Duke Energy Registrants have taken actions that have resulted in methane emission reductions, including the replacement of cast iron and bare steel pipelines and associated services with plastic or coated steel, advanced methane leak detection efforts, reducing time to repair nonhazardous leaks and operational releases of methane, and investment in renewable natural gas.

Timelines and initiatives, as well as implementation of new technologies, for future reductions of upstream methane emissions will vary in each state in which the company’s natural gas distribution business operates and will involve collaboration with regulators, customers and other stakeholders. EPA has also proposed regulations that would require reduction of methane emissions upstream of the Duke Energy Registrants' natural gas distribution business. The impact of these regulations on natural gas fuel prices is not currently quantifiable.


MD&A			OTHER MATTERS

In addition to possible EPA regulation of methane emissions, certain local governments, none within the jurisdictions in which the Duke Energy Registrants operate, have enacted or are considering initiatives to eliminate natural gas use in new buildings and focus on electrification. Enactment of similar regulations in the areas in which the Duke Energy Registrants' natural gas distribution operates could have a significant impact on the natural gas distribution business and its operations. At this time, such impacts are not able to be quantified; however, the net-zero methane goals announced in 2020 for the natural gas distribution business, as well as the actions taken to reduce these GHG emissions, potentially lowers the exposure to any future mandatory GHG emission reduction requirements. The Duke Energy Registrants would plan to seek recovery of their compliance costs with any new regulations through the regulatory process.

Physical Impacts of Climate Change

The Duke Energy Registrants recognize that scientists associate severe weather events with increasing levels of GHGs in the atmosphere. It is possible that these weather events could have a material impact on future results of operations should they occur more frequently and with greater severity. However, the uncertain nature of potential changes in extreme weather events (such as increased frequency, duration and severity), the long period of time over which any potential changes might take place and the inability to predict potential changes with any degree of accuracy, make estimating with any certainty any potential future financial risk to the Duke Energy Registrants’ operations difficult. Additionally, the Duke Energy Registrants would plan to continue to seek recovery of storm costs through the appropriate regulatory mechanisms. For more information on storm securitization in North Carolina and storm cost recovery in Florida, see Note 3 to the Consolidated Financial Statements, "Regulatory Matters."

The Duke Energy Registrants routinely take steps to reduce the potential impact of severe weather events on their electric transmission and distribution systems and natural gas facilities. The steps include modernizing the electric grid through smart meters, storm hardening, self-healing systems and targeted undergrounding and applying lessons learned from previous storms to restoration efforts. The Duke Energy Registrants’ electric generating facilities and natural gas facilities are designed to withstand extreme weather events without significant damage. The Duke Energy Registrants maintain inventories of coal, oil and liquified natural gas to mitigate the effects of any potential short-term disruption in fuel supply so they can continue to provide customers with an uninterrupted supply of electricity and/or natural gas.

New Accounting Standards

See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for a discussion of the impact of new accounting standards.

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